An Assessment of Oil Shale Technologies

June 1980

NTIS order #PB80-210115 Library of Congress Catalog Card Number 80-600101

For sale by the Superintendent of Documents, U.S. Government Printing Office Washington, D.C. 20402 Stock No. 052-003 -00759-2 Foreword

For many decades, the oil shale resources of the Western United States have been considered possible contributors to the Nation’s liquid fuel supply. This volume reviews several paths to development of these resources and the likely consequences of following these paths. A chapter providing background information about the nature of oil shale is followed by an evaluation of technologies for recovery of shale oil. The economics and finances of establishing an industry of various sizes are analyzed. The fact that much of the best shale is located on Federal land is examined in light of the desire to increase use of the resources. The consequences of shale development in terms of impact on the physical and social environments, and a discussion of the availability of water complete the report. Policy options addressing barriers that could hinder the establishment of the industry are presented. These options, designed primarily for Congressional consideration, are limited to the obstacles OTA identified as currently existing. Other issues, of equal importance for the protection of the environment and the communities, but not constraints to development, are discussed in the body of the report. The assessment deals only with oil shale; no systematic attempt was made in this study to compare this energy source with liquid fuel sources other than conventional petroleum or with alternative energy strategies. Other OTA assessments are addressing many of these topics. Volume II evaluates the Federal Prototype Oil Shale Leasing Program. Both volumes were prepared in response to requests from the Senate Committee on En- ergy and Natural Resources. We hope they will be of value to the entire Congress when considering domestic energy policies.

JOHN H, GIBBONS Director

/// Oil Shale Advisory Committee

James H. Gary, Chairman Colorado School of Mines

James Boyd Charles H. Prien** Private Consultant Denver Research Institute William Brennan Rancher John F. Redmond Rio Blanco County, Colo. Retired, Shell Oil Co.

Robert L. Coble* Richard D. Ridley Massachusetts Institute of Technology Occidental Oil Shale, Inc. Roland C. Fischer Colorado River Water Conservation Raymond L. Smith District Michigan Technological University John D. Haun Colorado School of Mines Thomas W. Ten Eyck Rio Manco Oil Shale Co. Carolyn A. Johnson Public Lands Institute Wallace Tyner Sidney Katell Purdue University West Virginia University Estella B. Leopold Glen D. Weaver University of Washington Colorado State University

*Resigned March 1979. * *Died April 1979.

NOTE: The Advisory Committee provided advice and comment throughout the assessment, but does not necessarily approve, disapprove, or endorse the report, for which OTA assumes full responsibility. Oil Shale Technology Project Staff

Lionel S. Johns, Assistant Director, OTA Energy, Materials, and International Security Division

Audrey Buyrn, Materials Program Manager Thomas A. Sladek, Principal Investigator William E. Davis, Social and Economic Impacts Patricia L. Poulton, Environmental and Water Availability Phillip L. Robinson, Economic and Financial

Administrative Staff

Patricia A. Canavan Margaret M. Connors Carol A. Drohan Jackie S. Robinson Contributors Bob Fensterheim, Health Program Donald G. Kesterke, U.S. Bureau of Mines* Mike Gough, Health Program Albert E. Paladino, National Bureau of Standards** Steven Plotkin, Energy Program

Publishing Staff

John C. Holmes, Publishing Officer Kathie S. Boss Debra M. Datcher Joanne Heming

*Oil Shale Project Director through January 1979, on detail to OTA from the U.S. Bureau of Mines. **Materials Program Manager through December 1978. Acknowledgments

This report was prepared by the Office of Technology Assessment Materials Program staff. The staff wishes to acknowledge the assistance and cooperation of the following contractors and consultants in the collection and analysis of data. Steven C. Ballard, University of Oklahoma Colorado School of Mines Research Institute Denver Research Institute Energy and Environmental Analysis, Inc. Renee Ford, editor The John Muir Institute for Environmental Studies, Inc. Colin J. High, Dartmouth College Christopher T. Hill, Center for Policy Alternatives, Massachusetts Institute of Technology Robert Kalter Associates Kevin Markey, Friends of the Earth The Pace Company Consultants and Engineers, Inc. Plant Resources Institute Quality Development Associates, Inc. Resource Planning Associates, Inc. The Rocky Mountain Center for Occupational and Environmental Health Bernel Stone, Georgia Institute of Technology George W. Tauxe, University of Oklahoma Water Purification Associates Richard W. Wright, Cardozo Law School, Yeshiva University Wyoming Research Corp. The Materials Program staff also wishes to acknowledge the assistance of the large number of Federal, State, and local government groups and private- sector parties who provided advice and guidance throughout the assessment. Contents

Chapter Page 1. Summary ...... o...... o.. o.. .o ...... O.. 3 2. Introduction, ...... 51 3. Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints...... 55 4. Background. .., ...... 85 5. Technology .,...... 119 6. Economic and Financial Considerations ...... , ., 179 7. Resource Acquisition ...... 235 8. Environmental Considerations. ., ...... 255 9. Water Availability ...... 359 10. Socioeconomic Aspects ...... 419

Appendixes A. Description and Evaluation of the Simulation Model ...... 477 B. Assumptions and Data for Computer Analyses...... 480 C, Oil Shale Water Pollutants ...... 481 D. Technologies for Managing Point Sources of Wastewater...... 488 E. Acronyms, Abbreviations, and Glossary...... 513

Vfl CHAPTER 1 Summary Contents

Table No. Page 4. Bvaluation of Potential Financial Incentives for Oil ,Shale Dtvelopment . ..• 21 5. Estimated Shale Oil Production by 1990 in

Resource Acquisition .•...... •...... 0 0 • Response to Various Federal Actiolls . . . . 26 Environment ...... •...... 6. Actual and Projected Population and Water Availability ....•...... Estimated Capacity of Oil Shale

Socioeconomics ... 0 ••••••••••••••• ' •••••• Communities in Colorado ...... ~ . . 42 Ba.ckp-oaad •••••••••••••••••••••••••••• Ittahll.lllni an on shal. w.trr: List of Rgura. P.~dvesaDdTradeoff•...... 8 Figure No. Page The Objectives for Development ...... 8 1. The Western Oil Shale Region...... • . . . 6 Attainment of the Objectives ...... 10 2. Oil Shale Deposits of the Green River Constraints...... 11 Formation...... 7 ...... and PoBcy OptleDS. • • • • • • • • • • • • • • •• 12 3. The Relative Degree to Which the Technology ...... 12 Production Targets Would Attain the Economics and Finances ....•...... 15 Objectives for Development...... 10 Resource Acquisition ...... 0. • • • • • • • • • •• 22 4. The Components of an Underground

Environment ... 0 • • • • • • • • • • • • • • • • • • • • • •• 30 Mining and Aboveground Retortin--8 Oil Water Availability...... 37 Shale Complex ...... 14 Socioeconomics...... 41 5. Ownership of the Oil Shale Lands of the Green River Formation ...... 24 Ust of Tables 6. Privately Owned Tracts in the Piceance Basin...... 25 Table No. Poge 7. The Upper and Lower Colorado River 1. Constraints to Implementing Pour Basins...... 38 Production Targets 0 • '0 ••••••• ' •••• 0 • • 12 8. The Communities in the Colorado Oil 2. Requirements for the Production Targets. 17 Shale Region...... 44 3. Subsidy Effect and Net Cost to the 9. Projected Growth of Counties in Government of Possible Oil Shale Northwestern Colorado From Oil Shale

Incentives •...... •...... 0 • • • • • • • • 18 Development, 1980-2000 ...... 45 CHAPTER 1 Summary

Summary of Findings Technology and expand regional employment, but would lead to increases in local inflation for certain Two basic retorting technologies are being goods, services, and property. The establish- developed: modified in situ (MIS) for under- ment of a l-rnillion-bbl/d industry by 1990 ground retorting, and aboveground retorting could save more than $10 billion per year in (AGR) for processing mined shale. These charges for imported oil and would substan- technologies are not presently ready for tially increase local employment; however, large-scale commercialization, but a sound the risks associated with overextended de- R&D base exists, and they could be made sign and construction capacity, insufficient ready either by modular demonstration proj- equipment manufacturing capability, and ects or construction of pioneer plants. The possible inefficiency from tight construction MIS process is being developed on two sites schedules could cause damaging cost over- and one commercial facility is planned. runs. Severe regional inflation could be ex- Aboveground retorts have been tested at up pected for land and housing as well as for to one-tenth of full size and at least one other goods and services. commercial-scale retort is planned in con- Shale oil may be price competitive with for- junction with an MIS demonstration. There eign crude, but when expected real rates of are no firm plans for testing other above- return on investment are 12 percent or less, -ground retorts, although several companies the commercialization of the industry could have shown interest. One process would be still be impeded by uncertainties and risks. tested if a lease were provided for the De- Among these are cost estimates for construct- partment of Energy (DOE) facility at Anvil ing the facilities, the future price of oil, reg- Points, Colo. With financial incentives, two ulations, and competition with lower cost in- others could be tested on private lands. A vestments of similar risk in conventional oil or multimineral aboveground process awaits the other alternatives. To establish a 200,000- availability of Federal land, either through bbl/d (or larger) industry within 10 years land exchange or limited leasing. Two true in would require financial incentives. The most situ (TIS) processes are being developed with effective would be production tax credits, DOE cost sharing, but are only at preliminary purchase agreements, and price supports. stages. Underground mining would also bene- The smaller firms may need loan guarantees. fit from additional research, development, The net cost of an effectively designed and and demonstration. No major technical prob- administered incentives program could range lems are anticipated either for open pit min- from $0.60 to $1.40/bbl* of shale oil syn- ing or for the conventional room-and-pillar crude** produced. Financial incentives alone method of underground mining. Minor uncer- may not spur development because alterna- tainties remain in the upgrading and refining tive investments with a greater return for an area. equivalent level of risk could compete for the Economics available capital. An oil shale industry could benefit the Na- The Government also could build its own tion’s economy and security, but would also commercial-scale or modular plants, but at entail several economic risks. For example, a *Present barrel equivalent over 20 years at lo-percent dis- 400,000-barrel-per-day (bbl/d) industry es- count rate. **A synthetic crude oil produced by adding hydrogen to tablished by 1990 would reduce expendi- crude shale oil. Shale oil syncrude is a high-quality material, tures for imported oil by $4.2 billion per year comparable with the best grades of conventional crude.

3 4 . An Assessment of 0il Shale Technologies much higher cost. A Government effort to dustries. While there is reason to believe that construct and supervise demonstration mod- the methods can be made to work, they have ules (9,000 to 12,000 bbl/d each) would pro- not been tested in commercial-scale oil shale vide technological information that could re- plants because none exist. solve some hitherto unanswered questions about the implications of oil shale develop- The potential leaching of waste disposal ment. It might also reduce the initial costs of areas and in situ retorts after the plants are industry development. However, the Govern- abandoned is a major concern. If it occurs, ment’s experience in designing, financing, the leachates could degrade the water quality and operating facilities could be sufficiently in the Colorado River system, a vital water dissimilar to that of possible private oper- resource in the Southwest. Such “nonpoint” ators to make the information inapplicable. wastewater discharges are neither well un- Government efforts also probably would less- derstood nor well regulated, although the en the commercial and R&D interest of the Clean Water Act provides a regulatory business community. framework. Techniques for preventing leaching need to be demonstrated on a commercial scale. It will be necessary to test a variety of Resource Acquisition* development technologies to assure adequate control of a large industry. A 400,000-bbl/d production of shale oil could be achieved by 1990 without extensive The Clean Air Act is the only existing envi- leasing of additional Federal land if subsi- ronmental law that could prevent the crea- dies are provided so that two presently active tion of a large industry. It could limit produc- projects are completed, three suspended proj- tion in Colorado to 400,000 bbl/d, although ects are resumed, and a new project on pri- additional capacity could be installed in vate land is initiated. If these financial incen- Utah. The procedures for obtaining environ- tives are not provided, then additional Feder- mental permits can take several years. Al- al leasing will probably be necessary if it is though unexpected regulatory delays should desired to achieve this level of production. To not preclude the establishment of an individ- produce 1 million bbl/d by IWO would require ual project, they could lead to cost overruns leasing, land exchanges, and substantially and might prevent the deployment of a large greater subsidies. industry.

Environment Water Availability Air and water quality, topography, wild- A 500,000-bbl/d” industry would increase life, and the health and safety of the workers by about 1.5 percent the water demands pro- will be affected by the development of an oil jected for the Upper Colorado River Basin in shale industry. Many effects will be similar the year 2000. Surplus surface water could to those caused by any type of mineral devel- be available to support this industry until at opment, but the scale of operations, their least 2025, after which water scarcities may concentration in a relatively small geo- limit all regional growth. Severe shortages graphic area, and the nature of the wastes could be experienced as much as 20 years will present some unique challenges. Many sooner if the region develops more rapidly of the impacts will be regulated by State and than expected. Surface water scarcity may Federal laws. The developers plan to comply lead to intensified ground water develop- by using control technologies from other in- ment, to a shift in the economic base, or to importation of water from other areas. Any *On May 27, 1980, the Department of the Interior (DOI) an- large oil shale industry will need new reser- nounced it will lease up to four new tracts under the Prototype Program and will begin preparations for a new permanent voirs and diversion projects. Their environ- leasing program. mental effects, though small overall, will be Ch 1–Summary ● 5 substantial in the areas where they are built. alone. There is a potential for adverse ef- The use of water for a 2-million-bbl/d oil shale fects, whose severity will depend on where, industry, while increasing regional income by when, and how rapidly the plants are built, several billion dollars per year, would cause and on how well the communities are pre- losses of about $25 million per year to farm- pared to cope with the growth. The communi- ing and hydroelectric power generation. ties could accommodate the growth accompa- States that will not directly share in the in- nying an industry of up to 200,000 bbl/d by creased regional income will experience 1990 if presently planned improvements and some of these losses. expansions are completed. Social and personal distress will occur unless active meas- Socioeconomic ures are taken for their prevention. A l-mil- Oil shale development will change the lion-bbl/d industry could not be accommo- communities in the sparsely populated oil dated without major Government involvement shale region both socially and economically. and massive mitigation programs. The partic- Growth problems arising from the simultane- ipation of Federal, State, and local agencies, ous development of oil shale and other ener- the public, and the developers would be es- gy resources are likely to be more difficult to sential to minimize the adverse living condi- solve than those from shale development tions that would inevitably arise.

Background

Oil shale deposits are found on all inhab- The formation has been divided into sever- ited continents. Those in Colorado, Utah, and al distinct geological basins. (See figure 2.) Wyoming contain both a solid hydrocarbon The richest and most thoroughly explored de- (kerogen) that can be converted to crude posits occur in Colorado’s Piceance basin. shale oil by heating, and sodium minerals that The resources of Utah’s Uinta basin are, in can be used in air pollution control, in glass- general, of somewhat poorer quality. The making, and to produce aluminum. Deposits Wyoming deposits are relatively inferior and of somewhat different chemical composition often intermingled with rock that contains no and geology are found elsewhere. Those in organic matter. Overall, the deposits contain some foreign countries (Scotland, Spain, Aus- the equivalent of over 8 trillion bbl of crude tralia) have been the sites of very small-scale shale oil. However, only a few hundred billion industries in the past. Other countries (Brazil, barrels could be recovered economically with the U. S. S. R., the People’s Republic of China) existing technology. either have such industries or are building them. In general, the oil shale region is rugged country, with elevations ranging from 4,300 The deposits of the Green River formation to 9,000 ft above sea level. The climate is dry, are found in northwestern Colorado, south- and the weather is strongly influenced by the western Wyoming, and northeastern Utah. topography. Although the soils are generally (See figure 1.) The Federal Government owns thin and dry, they support diverse plant com- about 70 percent of the land, which contains munities and over 300 species of animals, in- close to 80 percent of the oil shale and nearly cluding the largest migratory deer herd in all of the associated sodium minerals. Private North America and several threatened or en- parties, Indian tribes, and the three States dangered species. share the rest. Large deposits are also found Air quality is generally excellent, but high throughout the Midwestern and Eastern concentrations of hydrocarbons* (possibly States. Because of their richness and accessi- from vegetation) and windblown dust are oc- bility, however, the Green River shales are the ones most likely to be developed on a large casionally encountered, and thermal inver- scale in the near future. “Organic chemicals that contain only hydrogen and carbon. 6 ● An Assessment of 0il Shale Technologies

Figure 1 .—The Western Oil Shale Region

“1

)URCE The National Atlas, Department of the Interior sions are frequent. Water quality in the although it does not, in general, satisfy drink- surface stream-s is good to excellent in the ing water standards. upper reaches but much poorer downstream The population is approximately 120,000— because of the discharges from naturally about 3 persons per square mile. Only four saline streams, irrigated fields, and towns towns in the shale region have populations and mineral development sites. The quality of over 5,000: Grand Junction and Craig in Colo- the water in the extensive ground water aqui- rado, Vernal in Utah, and Rock Springs in fers* also varies widely. Some contain only Wyoming. The economy is based on agricul- saline brines; others contain potable water, ture, minerals, tourism, and recreation. Coal, oil, and gas development is increasing rapidly. The oil shale resources are also receiving *An aquifer is an undergrounfl formation containing water, considerable attention. Ch. 1–Summary ● 7

Figure 2.—Oil Shale Deposits of the Green River Formation

IDAHO GREAT DIVIDE BASIN —.- --i I RIVER . . % WYOMING I

BASIN I WASHAKIE BASIN

SAND WASH ● Salt Lake City UTAH BASIN

Vernal ~+~ ~ ● @ ,, COLORADO /“Y’ i UINTA /a

Rifle

/’”

1 11 EXPLANATION

Area underlain by the Green Fhver FormatIon Area underlain by 011 shale more than In which the 011 shale IS unappralsed or 10 feet thick, whtch ytelds 25 gallons low grade or more 011 per ton of shale

SOURCE D C Duncan and V E Swanson, Orgarr/c.R/ch Sha/es of the United States and Wodd Land Areas, U S Geological Survey Circular 523, 1965 8 An Assessment of Oil Shale Technologies

Phofo credit George Wa//erste/n Central Piceance basin, Colo.

Establishing an Oil Shale Industry: Perspectives and Tradeoffs The Objectives for Development be designed to maximize information generation. The ultimate decision as to whether, how, and to what extent to develop oil shale will be To maximize energy supplies.—This objec- political. Diverse groups with disparate pref- tive has both economic and national security erences for particular types and rates of de- implications. Its pursuit would lead to the velopment will influence the decision. Some rapid development of a large industry. The of the objectives of the different groups are benefits that might accrue include reduced discussed below. import reliance, improved balance of payments, stimulation of private investment, in- To position the industry for rapid deploy- creased employment, and lower energy costs ment.—The advocates of this objective be- over the long term. Policy responses favored lieve the industry should be ready to expand by supporters of this objective emphasize rapidly. They acknowledge that more infor- encouragement of the industry and removal mation and experience are needed if produc- of the restraints on its establishment. In- tion is to be expanded in times of national cluded might be leasing programs, substan- need. Many techniques and sites would have tial incentives, direct Government involve- to be evaluated in order to answer the re- ment in production, and the waiving of envi- maining questions. Supporters favor policies ronmental laws. expanding technical, economic, and environmental R&D, which should include demon- To minimize Federal promotion.—This ob- stration plants to evaluate a full spectrum of jective is supported by those who oppose gov- technologies. Incentives and additional Fed- ernmental interference with private enter- eral land might be employed to encourage pri- prise, and by those who stress that oil shale vate sector experiments. All programs would should not be promoted at the expense of Ch 1–Summary ● 9 other energy resources. They believe the in- stress the need for positioning the industry dustry should develop in response to market and its technologies for long-term profitable pressures and opportunities without active operations so that any future expansions Government support or participation. Policies could be financed with internally generated furthering this objective emphasize technical resources. The related objectives of efficient and environmental R&D and testing to pro- development of the resource and balanced vide a basis for developing regulations and environmental and social protection are also for comparing oil shale with other energy al- emphasized. The pace of development would ternatives. Planning for future mobilization allow thorough evaluation of the technologies programs would be carried out; leasing, land so that the elements of production (including exchanges, and incentives programs would land, labor, capital, water, and energy) could not. be used most efficiently if a large-scale indus- To maximize ultimate environmental infor- try were created. Policies would focus on in- mation and protection.—Advocates of this centives that leave intact some degree of objective emphasize the desirability of main- managerial risk, on thorough testing of di- taining an ecological balance. They also be- verse technologies and sites, and on ad- lieve that oil shale should not be promoted vanced R&D and demonstration to provide a more than other energy sources that could be basis for comparing oil shale with its alterna- less harmful to the environment. They would tives. The policies would not require a com- phase development to evaluate its potential mitment of funds and resources to the exclu- impacts and to design and test controls, Infor- sion of other potential energy sources. mation on environmental effects and control strategies would be acquired for all technol- *** ogies that might be used in a commercial in- The Government, in preparing its oil shale dustry. Policies would emphasize enforce- policies, must consider all of these, as well as ment of existing regulations, siting of plants well as other objectives. For example, the to minimize potential impacts, monitoring and Government owns rich oil shale deposits and R&D to provide guidance for new regulations, is responsible for protecting the Nation from and public education and participation. interruptions in energy supplies; this would To maximize the integrity of the social en- encourage the rapid development of public vironment .—Supporters of this objective em- lands. On the other hand, the public trust phasize personal and community needs. They requires that these lands be developed effi- believe it essential that growth management ciently, with equitable returns for the use of be well planned and coordinated, and that de- the public’s resources, and with fair treat- velopment proceed at a gradual pace. Policies ment of the affected groups and regions. This stress involving the region’s residents in man- mandate would lead to a moderate pace of de- aging growth, structuring incentive and leas- velopment. Finally, the Government is re- ing programs to avoid excessive growth rates quired by law to protect the environment and in the communities, funding community im- to consider the socioeconomic consequences provements and planning efforts, and allocat- of its major actions. These mandates require ing responsibilities for impact mitigation carefully managed development. among the developers and the Federal, State, Depending on which objectives are empha- and local governments. sized, a number of future industries can be To achieve an efficient and cost-effective postulated. The following section evaluates energy supply system.—Supporters of this the relative degree to which each of four pro- objective emphasize the importance of production targets could be expected to attain viding a mix of energy alternatives with the the objectives for development, given a con- best overall ratio of costs to benefits. They struction deadline of 1990. IO . An Assessment of 011 Shale Technologies

Attainment of the Objectives bbl/d goal is rated next since production at this level would constitute a major industry; OTA analyzed four production targets for further rapid deployment could then follow. It 1990: 100,000 bbl/d, 200,000 bbl/d, 400,000 is rated lower than the 400,000-bbl/d industry bbl/d, and 1 million bbl/d. Strategies to reach because its accelerated construction sched- the targets would entail substantially differ- ule would preclude precommercial experi- ent requirements, consequences, and policy ments and would probably result in less tech- responses. Regardless of the strategy, trade- nically efficient plants. The other goals are offs among objectives are inevitable. This is rated lower because fewer processes could indicated in figure 3, where the production be evaluated. goals are rated according to the relative degree to which they are expected to attain the To maximize energy supplies.—The bene- objectives for development. The following il- fits, and thus the ratings, are proportional to lustrates how attainment varies with the size the production rate. of the industry. To minimize Federal promotion.—The To position the industry for rapid deploy- 100,000-bbl/d target is rated highest because ment.—The 400,000-bbl/d industry is given it could be achieved by completing the pres- the highest rating because a wide variety of ently active projects. The 200,000-bbl/d goal technologies and sites would be evaluated probably would require some incentives, and and substantial technical, environmental, the 400,000-bbl/d goal would require incen- and economic information would be obtained; tives, a small land exchange, and the short- all of which would place the industry in a term leasing of a Federal R&D facility in Colo- good position for rapid scaleup. The l-million- rado for a demonstration project. The l-mil-

Figure 3.—The Relative Degree to Which the Production Targets Would Attain the Objectives for Development

1990 production target, bbl/d I 100.000 200.000 400.000 1 million To position the industry for rapid deployment I iI I I To maximize energy supplies

To minimize federal promotion , To maximize environmental information and protection ‘1 To maximize the integrity of the social environment To achieve an efficient and cost-effective energy supply system

Lowest degree of attainment I I - Highest degree of attainment

SOURCE Off Ice of Technology Assessment Ch l–Summary ● 11 lion-bbl/d goal would require much stronger strategies and extensive financial outlays. subsidies, additional long-term leasing of pub- Severe social disruption could ensue. lic land, permitting modifications, variances, and extensive Federal involvement in growth To achieve an efficient and cost-effective management. energy supply system.—The 400,000-bbl/d target has the highest rating because it would To maximize ultimate environmental infor- provide a balance of information generation mation and protection.—The quantity of pol- and of process development and demonstra- lutants and wastes generated will increase as tion. The 100,000- and 200,000-bbl/d targets the rate of production increases. Establishing are rated lower because only a few technol- a l-million-bbl/d industry in 10 years would ogies and sites would be tested. The l-million- cause the most disturbance per unit of pro- bbl/d industry is also rated low because its duction because there would not be enough deployment strategy would use many of the time to improve the control technologies, The elements of production poorly. Furthermore, 100,000 -bbl/d goal is also given a low rating the plants might not generate sufficient profit because the limited number of technologies capital for subsequent expansion. tested would provide neither extensive infor- An illustration of the need for tradeoffs mation on impacts nor guidance for the improvement of controls and regulations. The among objectives can be seen at the l-million- 400,000-bbl/d target would meet the needs bbl/d level. This choice has high attainment of for information and testing of control technol- the positioning and energy production objec- ogies but would incur a greater environment- tives (e.g., it would displace about 16 percent al risk per unit of production than 200,000 of the imported oil and reduce the balance of bbl/d. The latter would maximize the attain- payments significantly); however, reaching ment of this objective. the target requires tradeoffs in all the other areas (for example, it would violate the Clean To maximize the integrity of the social Air Act). environment. —The 100,000-bbl/d target is rated high because it should be within the Constraints physical capacities of the communities. A 200,000-bbl/d industry would strain the abil- OTA analyzed the requirements for achiev- ity of the towns to absorb the number of ex- ing each of the production goals by 1990, pected new residents; the amount of stress given the present state of knowledge and the would depend on the location of the develop- current regulatory structure. The factors ment. Adjusting to the growth associated with identified as hindering or even preventing a 400,000-bbl/d industry would be possible if reaching the goals are shown in table 1. The the plantsites were dispersed in Utah and constraints judged to be “moderate” will Colorado, if plant construction were phased, hamper but not necessarily preclude develop- and if preparations for the construction of ment; those judged to be “critical” could be- new towns were started at once; but boom- come severe barriers. When it was inconclu- town effects would most probably accompany sive whether or to what extent certain fac- the growth. A l-million-bbl/d industry would tors would impede development, they were require coordinated growth management called “possible” constraints. 12 ● An Assessment of Oil Shale Technologies

Table 1.–Constraints to lmplementing Four Production Targets

1990 production target, bbl/d 100,000 200,000 400,000 1 million Possible deterring factors Severity of impediment Technological Technological readiness ... ., ... . None None None Critical Economic and financial Availability of private capital ... None None None Moderate Marketability of the shale 011 . . . Possible Possible Possible Possible Investor participation. . None Possible Possible Possible Institutional Availability of land...... None None Possible Critical Permitting procedures None None Possible Critical Major-pipeline capacity . None None None Critical Design and construction services . ... None None Moderate Critical Equipment availability None None Moderate Critical Environmental Compliance with environmental regulations. . None None Possible Critical Water availability Availability of surplus surface water. . None None None Possible Adequacy of existing supply systems None None Critical Critical Socioeconomic Adequacy of community facilities and services . None Moderate Moderate Critical

SOURCE Otflce of Technology Assessment

Issues and Policy Options Technology converted to petrochemicals or refined like most conventional crudes. It is better as a Oil shale contains a solid hydrocarbon source of jet fuel, diesel fuel, and the other called kerogen that when heated (retorted) heavier distillates than of gasoline. (The proc- yields combustible gases, shale oil, and a sol- essing steps for an AGR system are shown in id residue called spent, retorted, or proc- figure 4.) essed shale. Crude shale oil can be obtained by either aboveground or in situ (in place) Issues processing. In aboveground processing, the shale is mined and then heated in retorting vessels. In a TIS* process, a deposit is first What are the advantages and disad- fractured by explosives and then retorted un- 1 vantages of different mining and processing methods? derground. TIS is at present a primitive technology, although R&D and field tests are Open pit mining allows large-scale, eco- being conducted. MIS* is a more advanced in nomical development and maximizes the re- situ method in which a portion of the deposit covery of the resource. Its application, how- is mined and the rest is shattered (rubbled) by ever, is limited to a few areas in the Piceance explosives and retorted underground. The basin and to several in the Uinta basin. Alter- mined portion can either be retorted on the ations to the surface of the land are substan- surface or discarded as waste. The crude tial, and the stripped overburden must be dis- shale oil can be burned as a boiler fuel, or it posed of along with the processing wastes. can be converted into a synthetic crude oil Open pit mining of oil shale has never been (syncrude) by adding hydrogen. The syncrude tested. The technique is highly developed can also be burned as boiler fuel, or it can be with other minerals, however, and few tech- *TIS = true in situ; MIS = modified in situ. nical problems are anticipated. Ch I–Summary ● 13

that the retorted shale is left underground where it may be leached by ground water, The MIS process requires mining 20 to 40 percent of the deposit to be retorted, and involves more facilities and waste disposal on the surface. More oil is recovered per ton of rock processed than with TIS, but less than with aboveground processing. Oil recovery per acre is probably higher with MIS than with a combination of underground mining and aboveground processing, but lower than with surface mining and aboveground processing. The principal advantage of above- -ground processing is its high oil recovery. Its principal disadvantage is that it requires large mining and waste disposal operations and substantial surface facilities.

Are the technologies ready for large- 2 scale applications? The commercial-scale deployment of the critical retorting processes, at their present developmental stage, would entail appreciable risks of both technological and economic failure. All the components of an oil shale Photo credit Departmenf of Energy project must function together, which means Department of Energy’s batch retort that building a large-scale project is risky. pilot test plant, Laramie, Wyo. Even though some of the other components, like the upgrading and refining processes, are Underground mining, which has been highly advanced, the oil shale processes are tested in four mines in the Piceance basin, is not. more generally applicable. The Piceance More than 30 years of R&D by governmen- mines, however, were relatively small and tal and private organizations has provided a were located on the southern fringe. Mining basis for commercialization tests. Two above- conditions in other areas are considerably -ground retorts have been tested for several different. Underground mining is especially months at production rates approaching affected by the physical properties of the ore 1,000 bbl/d, about one-tenth of the size of and by the presence of ground water. In gen- commercial modules. Others, like the Paraho eral, it is more costly than open pit mining, retort, have been tested at rates of a few hun- and resource recovery is lower. dred barrels per day. These experiments The advantages of TIS processing are that have produced a total of about 500,000 bbl of mining is not required, spent shale is not pro- shale oil—the equivalent of 10 days’ produc- duced on the surface, and the surface facil- tion from a 50,000bbl/d commercial plant. ities needed are minimal. Its principal disad- Additional testing, especially of the TIS proc- vantages are that the technology is not well ess, is needed before a major industry can be advanced, that it is applicable only to depos- established with a reasonable level of confi- its that are not deeply buried, that oil recov- dence. The MIS process is being developed on eries are lower than by other methods, and three sites in the Piceance basin, and the re- 14 . An Assessment of Oil Shale Technologies

Figure 4.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTS FROM UPGRADING UNITS

● Low Sulfur Fuel 011 ● Ammonia ● Liquefied Petroleum Gas ● sulfur ● Coke

PROCESSED SHALE REVEGETATION IN SHALLOW CANYON OR VALLEY --~ .- -. \. --- . \ Compacted --- - ..,, ,.m .-r. - . .’-- D.....-... -A c -. f 1 L-, Covered Processe . -. -. Shale Conveyors

Yno. ,..

Y L Catchment Dam HEADFRAME DISCHARGE ; Surface Runoff STATION Water reused

Roof Upper Bench Loading Dnlhng - Bolting Scaling — . . . .-.. ___

1 . . ROOM AND PILLAR MINING (Several Hundred Feet or more w Underground) SKIP LOADING STATION

SOURCE: C-b Shale Oil Project, Deta//ed Development Plan and Related Materlak, Ashland 011, Inc., and Shell Oil Co., February 1976, p. 1.24 suits of this work should assist in determining produced, and the somewhat lower oil recov- its applicability to other areas. ery efficiencies. With AGR, the effects of scaleup on the performance and reliability of the retorts themselves and on their associ- What are the major areas of uncer- ated equipment (pollution controls, product 3 tainty? recovery devices, and materials-handling equipment) are unknown. The effects of shale stability and strength on mine design, on safety, and on resource recovery from underground mines are present- What can be done to reduce the uncer- ly unclear. The effects that large inflows of tainties? ground water would have on efficiency are 4 also not determined. Many uncertainties ex- TIS will require extensive evaluation, in- ist with respect to the feasibility and envi- cluding theoretical, laboratory, and field ronmental impacts of TIS processing. The ma- studies, before its commercial potential can jor questions about MIS concern its applica- be determined. Some of the uncertain aspects bility to very rich or deeply buried shales, use of MIS and AGR processing could also be re- of the large quantities of retort gas that are solved with small-scale R&D programs. How- Ch. l–Summary . 15

ever, demonstration projects will be needed public and intermediate levels of informa- to accurately determine the performance, re- tion. Modular demonstration projects liability, and costs of the various development would require a smaller total capital in- systems under commercial operating condi- vestment than a commercial plant, but they tions. At a minimum, the retorting systems would cost much more per barrel of oil pro- could be demonstrated by the construction duced. The projects could be structured in and operation of modular retorts—the small- several ways. est production units that would be used in a —A single module on a single site would commercial operation. The module for an have the lowest total cost but the highest MIS process might be a single retort with a per barrel cost. The information would capacity of several hundred barrels a day, or be useful only to the process and the site a cluster of retorts producing several evaluated. thousand. An AGR processing module might —Several modules on a single site would produce 10,000 bbl/d. (A commercial plant have higher total costs but the costs per might contain five or six of these modules. ) module and per barrel would be lower. Other technologies, such as open pit mining, A full-scale commercial plant, incorpo- may necessitate a substantially larger degree of scaleup, perhaps to a full-scale commercial rating several technologies, could be plant. The retorting technologies could also simulated. be demonstrated in full-scale “pioneer” —Single modules on several sites would plants, as proposed by Colony Development. have even higher costs. Unit costs would be similar to those for the single mod- Policy Options ule/single site option. Several sites and processes could be evaluated. ● R&D funding.—R&D programs could be —Several modules on several sites, the conducted by Government agencies or by equivalent of a pioneer commercial in- the private sector, with or without Federal dustry, would be the most costly but participation. Federal programs could be would generate the maximum amount of implemented through the congressional information and experience. budgetary process by adjusting the appropriations for DOE and other executive branch agencies, by providing additional Economics and Finances appropriations earmarked for oil shale An oil shale plant will be very costly and R&D, or by passing legislation specifically the oil will be expensive. Trends in world oil for R&D for oil shale technologies. prices suggest that shale oil may be competi- ● Demonstration programs.—Government tive, both now and in the foreseeable future. ownership of demonstration plants would On the other hand, the long-term profitability maximize its intervention and expense, but of the industry could be impeded by future would also provide it with the largest pricing strategies for competing fuels, by in- amount of information, This would, how- accuracies in the current cost estimates for ever, discourage independent industry pro- constructing facilities, and by risks that reg- grams. Funding by the private sector alone ulatory problems or litigation could delay or would minimize Government involvement bar a project’s completion. The following dis- and expense, but the developers might not cussion deals with oil shale’s economic as- be willing to invest in a timely manner and pects and with some possible economic pol- share information. Cost sharing of the proj- icies. All costs and prices are expressed in ects would entail intermediate costs to the third-quarter 1979 dollars. 16 . An Assessment of 0il Shale Technologies

Issues 3 How much will oil shale facilities cost? According to the current cost estimates, to What are the economic and energy- complete a 50, 000-bbl/d” syncrude project by 1 supply benefits of oil shale develop- 1990 would require a capital investment of ment? about $1.7 billion. The economic and finan- The output from a 400,000-bbl/d industry cial requirements of the four production tar- would approximate the petroleum require- gets are indicated in table 2, together with ments of the Department of Defense or would their requirements for water and labor. A 1- satisfy about 70 percent of the demand for million-bbl/d industry (approximately 20 proj- liquid fuels in the Rocky Mountain States. A ects) would cost about $35 billion, unless cost l-million-bbl/d industry could provide about overruns resulted from regulatory delays, ac- 20 percent of the liquid fuels currently con- celerated construction schedules, or attempts sumed in the entire Midwest, including 60 to build many of the projects simultaneously, percent of the jet fuel, diesel fuel, and dis- Establishing this industry by 1990 could cost tillate heating oil. The amount of output as much as $45 billion. would replace about 16 percent of the cur- About 70 percent of the capital investment rent imported oil requirement. At $32/bbl, would probably come from corporate equity; this would reduce expenditures for imported the rest would be borrowed. The annual debt oil by about $10 billion per year (about 56 requirement for a l-million-bbl/d industry percent of the balance-of-payments deficit in would constitute no more than 4 percent of 1979). * The effects of this industry on world annual business investment, and should not oil prices cannot be accurately predicted. For significantly strain U.S. private sector lend- illustration, if prices were depressed by 1 ing capabilities. percent, then expenditures for foreign oil would be reduced by an additional $900 million per year. Employment in the oil shale region would increase dramatically if an indus- 4 Is oil shale competitive? try of any appreciable size were established. Estimates of a breakeven price for shale oil are highly dependent on assumptions, including the real rate of return required on invest- What are the negative economic ef- ment, capital costs, operating costs, annual 2 fects of establishing the industry? real escalations of operating costs, produc- During its construction by 1990, a l-mil- tive life of the resource base, and the effec- lion-bbl/d industry would cause a very small, tive tax rate for developers. OTA’s computer but perceptible, increase in the national rate simulations indicate that prices of $48 and of inflation. In the longer term, this impact $62/bbl (in 1979 dollars) of shale oil syncrude would be offset by improvements in the bal- would be required to achieve real, aftertax ance of payments. If the industry were em- rates of return of 12 and 15 percent, respec- phasized at the expense of less costly alter- tively. (See table 3.) natives, the long-term inflationary effects, OTA’s assumptions are more conservative through increased energy costs, might be (less optimistic) than those of many devel- greater. Inflationary impacts on the oil shale opers who believe that syncrude breakeven region would be significant for a 200,000- price estimates are $6 to $9/bbl below those bbl/d industry, substantial for 400,000 bbl/d, used by OTA. OTA based its analysis, how- and severe for 1 million bbl/d, Costs of labor ever, on the most recent cost estimates for and housing would be most affected. those technologies having advanced engineer- *Posted prices of some foreign crudes currently exceed ing designs, and the results are believed to $32/bbl. represent accurately the present economic Ch. l–Summary 17

Table 2.–Requirements for the Production Targets

1990 production target, bbl/d 100,000 200,000 400,000 1 million Resource Requirements Institutional Design and construction services, % of 1978 U.S. capacity needed each year Minimal Minimal 12 35 Plant equipment, % of 1978 U.S capacity needed each year Mlnlmal Minimal 6-12 15-30 Economic and financiala Loans. $ billion ., $0.9-1.35 $1,8-26 $3.6-42 $90-135 Equity, $ billion 2,1-3,15 4,2-59 8.4-98 21.0 -31,5 Total, $ billion 3.0-4.5 6.0-85 12,0-140 30,0 -45.0 Annual, $ billlonb : : 06-0.9 1.2-1,7 2.4-2,8 6.0-9.0 Water avai/abi/ity Water, acre-ft/yrc 9,800-24,600 19,600-49,200 39,200-98,400 100,000-250,000 Socioeconomic Workers ., ., 5,600 8,800-11,200 17,600-22,400 44,000-56,000 New residents requlrlng housing and community services ., ., 23,000 41,200-47,200 82,000-95,000 118,000-236,000 alhlrd quarter 1979 dollars bMaxlmum annual requlcements for a 5 year construchon period cAssumes 4 9001012 300 acre It /yr for producf(on of 50 000 bbl/d of shale 011 syncrude dA55umes 1 200 Construction ~o~kers and 1 600 operators per 50 oo&bbl/d plant Multlp[lers used for total Increase = ‘2 5 x (Corlsfructlofl workers) + 55 x (Opt3rdOrS) Ranges reflect adjustments In construction work forces assuming phasing of plant construction SOURCE Ofhce of Technology Assessment

$ \

/’

Photo cred~t OTA staff

Oil shale retort plant at Anvil Points, Colo. 18 ● An Assessment of Oil Shale Technologies

Table 3.–Subsidy Effect and Not Cost to the Government of Possible Oil Shale Incentivesa (12-percent rate of return on invested capital)

(15-percent rate of return on invested capital)

aThe Ca[culatlofls assume a $sslbbl price for conventional premmrm crude that escalates at a real rate of 3 percent per year Thus, the predtcled $48/bbl breakeven price fOr the f 2-PerCent dlscounf rate WIII be reached In t 1 years, or In the fifth year of production Therefore, m narrow economic terms, 011 shale plants starfmg constructwn now which assume a 12-percent dlscounl rate WIII be profitable over the life of the project wtfhout subsidy (See dscusslon especially ch 6, for caveats concerning this Conclusion ) The calculations are for a 50 000-bbl/d plant coshng $1 7 bdhon All monetary values are m 1979 dollars SOURCE Resource Planrung Associates Inc Washington D C position of shale oil. If OTA’s cost estimates ● Unreliable cost estimates.—There are proved correct and a 12-percent rate of re- no cost data for commercial-size plants turn were sufficient to attract industry in- because none have been built. Cost esti- vestment, Government incentives might not mates for projects have traditionally be required to foster shale oil development. been unstable, rising by more than 400 Similarly, if OTA has overestimated the costs percent between 1973 and 1978. The and required rate of return, this conclusion current range of estimates, based on would still hold. On the other hand, if the un- preliminary engineering designs and ex- certainties discussed below should come to perience with other industries, is be- pass and/or a rate of return higher than 12 lieved to be more accurate, although the percent is required to attract capital, subsi- possibility of significant errors remains, dies or other public policy actions would be ● Regulatory disincentives.— Projects required to encourage development. may be delayed or precluded by procedures for obtaining permits, by siting or Several uncertainties bear on forecasts of process changes necessitated by regula- competitiveness. Although OTA’s analysis at- tions or litigation, or by future regula- tempted to capture them, the following ones tions that cannot be met economically. cannot be completely incorporated in a quan- Unexpected delays would contribute to titative analysis: cost overruns. Ch. 1–Summary . 19

● Uncertain future world oil prices.— have contributed significantly to the rising Present prices are high, and rising. estimates of the cost for a barrel of shale oil. There is a possibility, however, that fu- Alternative investment possibilities also ture price changes may be less signifi- critically affect shale oil’s competitiveness. cant than commonly forecast, or that Shale oil is tied to conventional oil in two they could be sufficiently unstable to ways. First, it is a substitute in the market- add appreciably to the risks of oil shale place, and therefore must be price competi- development. tive. Second, the companies that are potential ● Cost overruns because of competition oil shale developers are the same ones that with other projects.—Individual proj- produce or refine petroleum, or are potential ects could be completed in 5 to 7 years developers of other synthetic fuels. The prof- (10 years if preliminary demonstration itability of shale oil must be “competitive” in tests were conducted for the technol- the sense of selling at a price that competes ogies). A 400,000-bbl/d industry could with conventional oil while permitting a rea- probably be put in place by 1990 without sonable rate of return. A company with a fi- severe cost overruns if the various nite amount of capital is most likely to invest plants’ construction were coordinated in those projects that offer the highest rate of and phased. However, the 20 or so proj- return at a given level of risk. ects needed for 1 million bbl/d by 1990 Price increases over the past 7 years have would face delays and cost overruns be- dramatically increased the profitability of cause of the large demands for equip- both domestic and foreign petroleum development, labor, and construction services. ment. As a consequence, companies may choose to invest in petroleum so long as it has These uncertainties make any forecast of a similar rate of return and does not entail breakeven prices unreliable. At the same the extensive uncertainties of oil shale. It time, they may induce developers to seek follows that public policies to encourage oil higher rates of return for their shale invest- shale development must address making its ments. For example, a 15-percent real rate of risks and rates of return comparable to those return, which would be substantially greater of petroleum. than that required for more conventional investments, would increase the price of shale Oil shale investments at 12- or 15-percent oil syncrude by $14/bbl (to about $62/bbl) and rates of return are not likely to displace in- thus would make it noncompetitive, without vestments that have lower costs, lower risks, subsidy, with the forecast prices of foreign and higher rates of return, even if shale oil oil. has a competitive price. The incentives summarized in this chapter and discussed in de- The rate of return issue.—In addition to tail in chapter 6 primarily address making the interactions between the uncertainties shale oil price competitive. They will not nec- and required rate of return, there is another essarily assure that it will compete success- important interrelationship. It pertains to the fully with alternative investments. Fewer op- flow of private capital given the rates of portunities in the future for investment in return for potential alternative investments. conventional petroleum projects will tend to There has been much confusion over why the increase interest in oil shale investments. estimated costs of shale oil always have been These considerations of price, cost, and rate higher than the actual costs of conventional of return also apply to other synthetic and al- oil, even after the sustained high price rises ternate energy industries. To the extent that of the 1970’s. As discussed above (and in ch. subsidies or other policy actions encourage 6), the effects of both increasingly detailed shale development alone, these other energy engineering cost estimates and of inflation on investment alternatives are put at at relative construction and capital equipment costs disadvantage. 20 ● An Assessment of Oil Shale Technologies

Which incentives would be most effec- existing major pipeline systems leading to 5 tive? Midwest markets and by shortages in design OTA analyzed 10 possible incentives on the and construction services and plant equip- basis of 6 economic and financial criteria. ment. These factors should not be major prob- (See table 4.) Price supports, purchase agree- lems for industries of up to 400,000 bbl/d. ments, and production tax credits appear to have the most overall economic merit. Debt Policy Options for Financial Support guarantees or low-interest loans, however, Financial support could be provided either will probably be necessary to encourage the by incentives to private industry or by direct participation of smaller firms. All incentives Government ownership or participation. programs would have to be properly administered to be effective, and should be removed Incentives to private industry .—Incentive when no longer needed. programs could be structured for a high level of risk reduction with relatively small net costs and administrative burdens. The proper incentives would share the risks associated 6 What would incentives programs cost? with creating the projects, but would leave some of the managerial risks intact. This The total net cost of subsidizing a 50,000- would help establish the industry but would bbl/d plant with one of the more effective sub- allow market risks and opportunities to gov- sidies could range from $200 million to $400 ern its development. million. (See table 3.) This cost would be spread over about 22 years, and would range A possible disadvantage of incentives from $0.60 to $1.40/bbl of oil produced. It is would be that the Government could not di- determined by: rectly control the pace of the industry’s growth unless extensive encouragement were ● the size and timing of the outflows from provided. On the other hand, direct Govern- the Treasury, ment control is likely to discourage participa- ● the size and timing of the increased tion by private firms and could incur the risk taxes paid by the developers, and of managerial inefficiency. Also, with reli- ● the discount rate assumed for Govern- ance on incentives, the Government would not ment expenditures. * have direct access to the types of technical It is not necessarily true that the least costly and economic information that might be incentive would be the best choice. Firms needed to structure future oil shale policies. * with different corporate circumstances will Incentives legislation could include require- prefer different incentives because they must ments for disclosure of proprietary informa- avert different risks. It would be cost effec- tion and for specific test programs, but such tive to offer a choice of incentives (e.g., grants requirements would discourage industrial and low-interest loans to smaller firms, tax participation. Information could also be ob- credits to larger firms with bigger tax liabili- tained through licensing arrangements with ties) to encourage participation by a variety the owners of the technologies. of firms. Direct Government participation or ownership. —A Government-owned industry might be desirable in a crisis situation. OTA What other economic factors could af- did not analyze this option in detail because 7 fect the establishment of an industry? of its extremely high cost to the public. The Attempts to establish a large industry quickly could be impeded by the capacity of *In its May 27, 1980, oil shale policy announcement, DOI indicated it would seek Memoranda of Understanding and other *The Office of Management and Budget uses a discount rate formal documents to expand its ability to obtain performance of 10 percent per year to compare the cost effectiveness of Gov- information. ernment programs. Table 4.–Evaluation of Potential Financial Incentives for Oil Shale Development

Effect of Incentwe on program ob]ectwes Extent to which Incentive meets pohcy guldehnes . . IJromotlon 01 Mlnlmlzatlon ot Promohon of comDetltlon Risk-sharing effect Flnanclng effect Incentive Subsidy effect economic efficiency —admlnlstratwe -. burden Effect on firms Firm preferences — 1. Prod uctIon tax Strong, subsidizes Moderate, shares risk Slight, Improves - Sllght adverse effect, Mlnlmal admlnlstratwe Benefits firms with Supported by relatwely credit ($3/bbl) product price associated with price uncer- project economics distorts product price burden large tax Ilablllty and large firms, talnty (If tax credit varies with strong flnanclal product price) capability 2. Investment tax Strong, subsidizes Moderate; shares msk SIlght, Improves Moderate adverse effect; Minimal admmlstratwe Benefits firms with Supported very strong- credit (additional Investment cost associated with Investment project economics dcstorts Input costs, burden large tax Ilabdlty and ly by most firms; 10YO) cost uncertainty favors capital-lntenswe strong flnanclal however, firms that technologies capability would not be able to use the investment tax credit do not favor Its enactment 3. Price supper Strong; subsidizes Moderate: shares nsk Moderate; improves Sllght adverse effect, Moderate Benefits all ftrms Moderately supported product price (If con- associated with price borrowing capability distorts product price admlnlstratwe burden except those with by a wide range tract price IS higher uncertainty very weak flnanclal of firms than market price) capability 4. Loan guarantee Slight; subsidizes Moderate; shares nsk of Strong: improves Slight adverse effect; Moderate Benefits firms with Supported by firms Investment cost project failure borrowing capability distorts Input costs: administrative burden weak financial with Ilmited debt favors capital-lntenswe capability capacity technologies 5. Subsidized interest Shght; subsidizes Moderate; shares risk of Strong; Government Shght adverse effect; Moderate Benefits firms with Supported by firms loan (70% debt at investment cost project failure provides capital distorts Input costs; adminlstratwe burden weak flnanclal with Ilmited debt 3Y0 below market favors capital-lntenswe capability capacity rate) technologies 6. Purchase Strong; but less than Strong; shares risk of price Moderate; improves Sllght adverse effect; Moderate (normally Benefits all firms but Moderate, but less agreements price supports uncertainty borrowing capability distorts product price more than price sup- those with very weak than for price ports) financial capabdlty supports 7 Block grant (33 & Strong; neutral None Strong; Government No adverse effect Moderate BenefNs all firms Supported by firms In 50% of plant cost) subsidy prowdes capital administrative burden widely varying flnanclal circumstances 8 Government Slight Strong, shares all project Moderate; reduces No adverse effect on firm Major admlnstrative Benefits firms that are Little support parflcipation risks firm’s capital require- decisions; however, ac- burden very averse to risk ment tive Government involve- (e. g., smaller, less ment may lead to ineffi- well-financed firms) ciency 9 Accelerated de- Moderate: subsidizes Moderate; shares risk SIlght; Improves Moderate adverse effect, Minimal admlnlstratwe Benefits firms with Supported by large, predation (5 years) investment cost; max- associated with Investment project economics distorts Input costs, burden large tax Ilabdltles Integrated 011 imum subsidy effect cost uncertainty favors capital-intensive and strong flnanclal companies is limited by Federal technologies capabdlty corporate income tax rate and interaction with the depletlon allowance 10. Percentage deple- Moderate: subsidizes None; Increases nsk Shght; improves Moderate adverse effect, Mlnlmal admlnistrahve Benefits firms with Not supported tion allowance product price; value associated with price project economics distorts product price In a burden large tax Ilabdltles (27Yo) of subsidy increases uncerfalnty variable and undesirable and strong flnanclal as the need for the manner capability subsidv decreases SOURCE Resource Planning Assoclales Inc 22 . An Assessment of O// Shale Technologies remaining option is Federal participation in ered in this way would not entail such prob- demonstration programs for the purpose of lems. Furthermore, most of the information obtaining and disseminating information. secured through Government ownership This could provide a better assessment of the could be made available as a condition of public’s oil shale resources, allow for the par- granting private financial incentives. ticipation of firms lacking oil shale land or Government intervention is likely to dis- proprietary technologies, permit the thorough courage private developers from undertaking testing of environmental controls, and facili- their own modular development and R&D ini- tate regulation of the industry. * tiatives, because programs of this kind tend The Government could become a part to reduce the benefits that a particular firm owner of the project by sharing the capital could obtain from its own R&D or modular and operating costs with industry. The conse- testing. Finally, the patenting and licensing of quences would be similar to those resulting technologies make definite provision for dis- from the construction grant option, except semination of technical information on both that the Government would share all of the gratis and fee terms to possible users of the risks and benefits. Almost without exception, processes. potential developers believe that active Gov- ernment participation would increase mana- Policy Options for Services, Equipment, gerial complexity and inefficiency. Adminis- and Pipelines trative burdens would be high. The Government could also contract for the Training programs could alleviate the shortage of design and construction person- construction of several modular plants it nel, whose skills could be used later in the would then operate, either alone or through operating facility. Developers normally try to contracts. It would then be in a position to obtain information on technical feasibility, proj- avoid equipment shortages by identifying ect economics, and the relative merits of dif- items with long delivery times and ordering ferent processes. This might be of assistance them early. Developers who coordinated ef- in evaluating future policies towards oil shale forts to standardize equipment could reduce their problems with specially fabricated development, in disseminating technical in- items. However, such coordination could be formation, and in improving understanding of impeded by developers’ unwillingness to the value of publicly owned oil shale re- share their process information and by anti- sources. The facility could later be scrapped or sold to a private operator. This option trust laws. The Government could reduce or would provide the Government with informa- eliminate tariffs and quotas on imported tion and experience. The cost, however, equipment. Domestic suppliers would resist would be much higher than that of incentives this action. Shortages in pipeline capacity to private developers. could be reduced only by building more pipelines. The Government could provide aid by Considering that the technologies to be expediting the review and approval of the nu- tested are proprietary, it is by no means clear merous permit applications that would be re- that the Government would have the legal quired. right to publish all this information. In addition, its experience in designing, financing, Resource Acquisition managing, and obtaining permits for an oil shale plant may not resemble that of private The oil shale resources are owned by the industry. Thus, the information acquired Federal and State governments, by Indian might be of little use to subsequent private de- tribes, and by private firms. (See figure 5.) velopers. Environmental information gath- Overall, the Government owns about 70 per- *Various types of demonstration programs are discussed in cent of the land surface, which overlies about the section on technological policies. 80 percent of the resources. About 20,000 Ch 1–Summary 23

acres (less than 1 percent) of the Federal land What production is expected from the has been leased to private firms. It may be 2 Federal lease tracts? necessary to involve more Federal land in Production from the two Federal Prototype order to test certain technologies, or to estab- Program lease tracts that are presently ac- lish a large industry rapidly. tive could reach 133,000 bbl/d by 1987. How- ever, only the lessees of Colorado tract C-b Issues are committed to commercial-scale production (57,000 bbl/d). Four other leases were offered in 1973, but those in Wyoming were not Could the private land support 1arge- sold and those in Utah are suspended until 1 scale development? the Supreme Court decides who owns the The private lands are extensive, but it is land. * The potential production from the unlikely that a large industry will be sited on Utah tracts (100,000 bbl/d) is not assured. them until the processing technologies have been proven to be economic. As shown in figure 6, the private lands in the Piceance basin What other projects have been pro- generally lie along the southern fringe where 3 posed or are presently active? the deposits are comparatively thin and lean, Tosco is proceeding at a slow pace in re- and are sometimes mixed with layers of bar- sponse to the diligence requirements of a ren rock. Development would be more costly State lease in Utah. Geokinetics, Inc., and than on the Federal land to the north, where Equity Oil are conducting small-scale R&D the deposits are more than 1,000 ft thick and projects under cost-sharing arrangements yield more oil per ton. In addition, the private- with DOE. Occidental Oil Shale is conducting ly owned resources contain no large deposits large-scale tests of its MIS process under a of sodium minerals and they are, in general, similar arrangement. Paraho Development is too deeply buried for economical open pit attempting to extend its lease for DOE’s re- mining. The large sodium mineral deposits search facility at Anvil Points, Colo., and to and the shallow oil shale beds are on Federal obtain funding for a modular demonstration land. program. Superior Oil Co. has proposed a There are some tracts, Colony and Union, land exchange to develop a multimineral for example, that contain commercially at- process in Colorado, and EXXON Corp. has tractive rich deposits. These firms have been proposed to exchange its scattered holdings developing retorting technologies for about for a single tract of Federal land in the Pi- 20 years, and projects with a total capacity of ceance basin.** DOE and the Department of about 150,000 bbl/d have been proposed for Defense are preparing a plan to develop Na- their tracts. These projects have been sus- val Oil Shale Reserve (NOSR) 1, near the An- pended, however, pending a more favorable vil Points site. If the current R&D is success- economic and regulatory climate. The tracts ful, if the land exchanges are consummated, owned by Getty, Standard Oil of California, and if favorable economic conditions exist, and others contain resources of comparable the total production from these projects could quality, but no projects have been announced exceed 250,000 bbl/d. for any of these private lands. In part, this reflects the technological positions of the land- *On May 19, 1980, the U.S. Supreme Court reversed the owners who do not own advanced retorting lower court decisions and held that the Secretary of the In- technologies. They may plan to license the terior could reject Utah’s applications for oil shale lands (An- drus v, Utah, No, 78-1522). processes of the other companies, once these **The Bureau of Land Management recently denied Superi- have been demonstrated. or’s initial proposal. Negotiations are continuing. .

24 . An Assessment of Oil Shale Technologies

Figure 5.—Ownership of the Oil Shale Lands of the Green River Formation

SOURCE Map of the Ma/or 0// Shale Ho/dregs—Colorado, Wyorrrmg, Utah, Denver, Colo Cameron Engineers, Inc , January 1978

Will more Federal land be needed to shale oil that might result from various Gov- 4 initiate an oil shale industry? ernment actions are indicated in table 5. An industry producing at least 60,000 bbl/d could The need for more land will depend on emerge without additional Federal actions. A whether a large industry is to be created rap- 360,000-bbl/d industry might result if incen- idly, on the prevailing prices for imported oil, tives were provided to encourage Colony and on whether financial incentives are provided, Union to resume their projects. * An industry *The incentives would have to be carefully structured to and on whether specific processing technol- achieve this result. See the section on economic and financial ogies are to be tested. Different amounts of policies for a discussion of incentives programs. Ch 1–Summary ● 25

Figure 6.— Privately Owned Tracts in the Piceance basin

EXXON RANGELY INTERNATIONAL NUCLEAR MEEKER

PICEA NC

FEDERAL BASIN JTRACT C.a GULF STD OF L INDIANA

MOBIL kEQUITY MOBIL ARCO EQUITY STANDARD OF . Lb’w CALIFORNIA UNION COLONY \/

SERVICE v- OCCIDENTAL ~Qo o+ N ~ov

Outhne of the Green Rwer a forrnatjon A Proposed odshale prolect (

SOURCE Map of the Ma/or 0// Shale Ho/d/rigs-Colorado, Wyofn/ng, Utah. Denver, COIO Cameron Engineers, Inc , January 1978

t ~- , i“ , < — , 26 ● An Assessment of 0il Shale Technologies

Case Federal action 1 2 3 4 5 6 7 8-— None x Incentives for first-generation developersa x x x x x Testsites for modular retortsb x x x x x x Resolution of ownership issues on Utah tractsc x x x x x Offtract land used x x x x Proposed land exchanges x x x Incentives for second-generation developers (or Improved economics) x x Naval 011 Shale Reserves or expanded Prototype Program or permanent Ieasing x Production, bbl/d 60,000-f 360,000 390,000 490,000 560,000 620,000 850,000 1,000,000 185,000 aA~~ume~ the entry of one as yet unannounced develoPer blncludes the proposed Superior 0,[ land ex~hange and a lea~lng of AnvI[ polnl~ by paraho Oevelopmen[ A 31J 000.b~{/ci production Increment Irom Government-sponsored modular lest retorls could occur at any po[nf w the hrst 400000 bbl/d of production cResumptlon of the Iracl U-a/ J.b prolect may also depend on the avallablllfy of lncentwes and on other Improvements in project economics dFor ~as[e O’lsposa( fronl [he open pIt rrurre fhal was Orlglnally proPosed for tract C a elncludes the proposed Superior 011 and EXXON land exchanges fonly 57000 bbltd IS fwmly committed SOURCE Offtce of Technology Assessment Ch 1–Summary . 27

approaching 400,000 bbl/d could be realized 200,000 bbl/d for at least 20 years. One if incentives were provided and small tracts drawback is that this reserve is located near of Federal land were available for retort test the private lands that may be developed, and programs. A multimineral lease or land ex- environmental and socioeconomic effects change (such as proposed by Superior) and would be concentrated if it were developed continuation of the Paraho lease at Anvil concurrently. Any program for developing Points are alternatives. If the Utah lease the reserves (whether by a Government- tracts resume development, a production of owned corporation, leasing, or cooperative 500,000 bbl/d might be possible. If the tract agreement with industry) could be structured C-a lessees returned to the original open pit to yield valuable information, but would also mining concept, production could reach add a level of administrative overhead, 560,000 bbl/d. (This would require permission to site processing facilities and to dispose of the solid wastes outside of the tract Leasing has several advantages. Informa- boundaries. ) Adding the EXXON land ex- tional requirements and environmental stipu- change might increase production to 620,000 lations can be included in the lease provi- bbl/d. Unless economic conditions became sions, and the pace of development can be very favorable, a much stronger set of incen- controlled (e.g., specifying preconstruction tives would be needed to spur development of monitoring periods, providing favorable roy- the “second generation” tracts—those near alty arrangements, and including diligence the fringe of the Piceance basin. All of these requirements). Under the Mineral Leasing conditions, plus additional leasing or develop- Act, as amended, a portion of the leasing pro- ment of the NOSR in Colorado, would be re- ceeds would be returned to the affected State quired to reach 1 million bbl/d by 1990. and could be used to mitigate the socioeconomic impacts accompanying development. A major long-term advantage would be that the What are the options for making Fed- Government would continue to own the land. 5 eral land available?* The major options are governmental devel- Additional leasing at this time also has opment of the NOSRs, leasing, and land ex- disadvantages. It could increase environmen- change, Leasing is allowed under the Mineral tal and socioeconomic impacts by encourag- Leasing Act of 1920, as amended. The Proto- ing development before these impacts are ful- type Program was structured under this Act. ly understood and strategies for their mitiga- Land exchanges such as those proposed by tion in place. Delaying leasing, however, Superior and EXXON are authorized by the while information is collected could lead to Federal Land Policy and Management Act of better design of a future leasing program. 1976 (FLPMA). Furthermore, it can be argued that new leasing is unwarranted now since existing projects theoretically could yield about 400,000 What are their advantages and disad- bbl/d, which is sufficient to test a variety of 6 vantages? technologies at commercial scale. The NOSRs contain poorer quality oil shale than the Federal holdings in the central Pice- ance basin. NOSR 1 in Colorado, however, is Land exchanges could improve resource large enough to support production of management by allowing consolidation of tracts that are presently too small, or too un- *On May 27, 1980, DOI announced it will lease up to four favorably situated, for economical develop- new tracts under the Prototype Program and will begin prepa- ment. Under FLPMA, however, environmen- rations for a new perm~nent leasing effort. Also announced was the decision not to give special emphasis to the execution tal stipulations, informational requirements, of exchanges. and developer participation in socioeconomic 28 ● An Assessment of 01/ Shale Technologies

impact mitigation programs could not be Policy Options made conditions of any exchange. ● Amend the Mineral Leasing Act of 1920. Either lease tracts or land exchange par- —The Act could be amended to increase cels could be selected to avoid ecologically the acreage limitations, or to set the size of sensitive areas and to disperse socioeconomic the tract according to the recoverable effects. resources it contained. This might allow more economies of scale, thereby improv- What are the difficulties with leasing ing economic feasibility. It might also allow and land exchange? the inclusion of a suitable waste disposal 7 site within a tract’s boundaries, thus avoid- All actions involving Federal land in the oil ing the need for separate offtract disposal shale region may be affected by the unpat- while still providing adequate shale re- ented mining claims that overlie most of the sources for sustained, large-scale oper- Federal holdings. * The claims have been a ations. The number of leases per person or source of legal controversy since the 1920’s. firm could also be increased. This might en- If they are validated by the courts, the Gov- courage firms that do not own oil shale ernment could lose control of much of the oil lands because it would allow them to apply shale land, including tracts potentially avail- experience obtained on one lease tract to able for leasing or land exchange. another while the first was still operating. Some provisions of the Mineral Leasing Act However, the number participating in the also may inhibit industry’s response to lease leasing program could be reduced if a few offerings. These provisions limit the number firms acquired all of the leases. One possi- of leases to one per person or firm and re- bility would be to increase the number but strict the size of a lease tract to a maximum limit it to one lease per State. This might of 5,120 acres.** encourage a firm to develop a process in the richer deposits in Colorado and then If a firm wishes to exchange its holdings apply it to the poorer quality resources in for a Federal tract, the values of the lands Utah or Wyoming.

must be within 25 percent of one another. ● Given the lower quality of the private oil Amend FLPMA. —FLPMA could be shale lands, such equivalent values may be amended to allow the inclusion of condi- difficult to achieve. In addition, the evaluations (such as environmental stipulations tion and review procedures for exchanges so and diligence requirements) in oil shale far have been time consuming. (The Superior land exchange agreements. This would im- proposal has been in the review stage since prove the Government’s control over the 1973. ) The experiences of Superior and Col- exchanged parcel, but could discourage ony were the first attempts to use, for oil private participation. shale lands, the exchange authority under ● Allow offsite land use for lease tracts. FLPMA. Colony did not immediately request —Legislation could be passed to allow a expedited treatment. Inadequate information lessee to use land outside of the boundaries in Superior’s initial request may have been of a lease tract for facility siting and waste partly responsible for the delay in evaluating disposal. * This might permit larger, more its request. economical operations (including perhaps *On June 2, 1980, the U.S. Supreme Court ruled in favor of an open pit mine) and would maximize re- two groups of unpatented claimholders in Colorado. It is too source recovery on the tract, but could in- early to determine the effects of this action on other unpatented claims. Andrus v. Shell OiJ Co. (No. 78-1815, June 2, hibit subsequent development of the off- 1980). tract areas. * *]n its May 27, 1980, decision paper, DOI stated that ‘t would seek legislation to remove the statutory acreage limitations on lease size, and to permit holding a maximum of four *DOI indicated in its May 1980 announcement that it would leases nationwide and two per State. propose such a legislative change. Ch 1–Summary ● 29

● Lease additional tracts under the Proto- duction could probably not begin until after type Program.—There is no statutory lim- 1990. Abandonment of the Prototype Pro- itation on the number of tracts that could gram would be implied, which might engen- be leased under the Prototype Program. der opposition. However, DOI originally committed to leasing no more than six. Because two of the Expedite land exchanges.—No regulations original tracts were not leased, offering governing land exchanges have been pro- two new ones might be justified, provided mulgated under FLPMA. Standardized and that the technologies to be tested were dif- objective procedures could significantly ferent from the processes being developed expedite the process. The review and ap- on the existing tracts. (One of the primary proval procedures could also be improved goals of the Prototype Program is to obtain by, for example, setting up a task force information about a variety of technol- within DOI specifically for oil shale pro- ogies. ) Leasing more than two more tracts, posals, or leasing for the purpose of expanding Government development.—The Govern- near-term shale oil production, would be ment could develop the NOSRs. Unless this opposed by critics of rapid oil shale devel- were done by leasing to private developers, opment. Leasing could begin sooner than it would involve competition with private under a new leasing program, if some of industry, and would encounter political op- the potential lease tracts previously nomi- position. It would also be costly; the public nated were offered. A supplemental envi- would have to pay the full cost of the facili- ronmental impact statement (EIS) would be ties, and that might discourage independ- required. Construction on the tracts could ent experiments by private firms. The op- probably not begin until 1985 and production would be helpful in obtaining information no sooner than 1990. tion for developing policies and regulations ● Lease only for testing of multimineral for the industry, but the information might extraction. * —Multimineral extraction, not be useful to private developers when wherein shale oil is obtained along with evaluating their investment alternatives. other commercially valuable minerals such This is because of the discrepancy between as nahcolite and dawsonite, has been re- Government and private developers’ ex- ceiving increased attention. Potential de- perience in financing and operating facil- velopers argue that obtaining the associ- ities. Some of the information is being ac- ated minerals would substantially increase quired in the present Prototype Program. It the profitability of the venture, The only could also be obtained in additional leasing suitable land for multimineral experimen- programs or through licensing arrange- tation is federally owned. ments with the owners of the technologies. ● Initiate a new, permanent leasing pro- Continuation of present policies.—Contin- gram.—An advantage would be that more uation of present policies concerning off- production than is possible under the pres- site disposal, lease limitations, and land ex- ent Prototype Program could be achieved. change procedures (without additional A full EIS and a new set of leasing regula- leasing) would help protect the social and tions would be needed. Without the in- physical environments. It would preclude formation to be acquired by completing the commercial development beyond that pres- present Prototype Program projects, it ently envisioned on the four lease tracts might be difficult to prepare an accurate and the three to five private holdings that environmental assessment and to structure could support commercial operations. By comprehensive leasing regulations. Pro- limiting future leasing and land exchanges, shale oil production could not exceed *DOI will offer at least one multimineral tract in its renewed 300,000 to 400,000 bbl/d and the adverse Prototype Program. impacts of a larger industry would be 30 ● An Assessment of Oil Shale Technologies

avoided. The gathering and evaluation of water by accidental leaks and spills, by point- information would enhance understanding source wastewater discharges, and by non- of the environmental consequences of de- point discharges, such as runoff and leaching velopment prior to further commercializa- of waste disposal areas and ground water tion, and the pace would provide leadtime leaching of in situ retorts. Unless the pollution for the communities to prepare for growth. is properly controlled, aquatic biota and Given the long period needed to construct water for irrigation, recreation, and drinking facilities, however, this option would re- could be adversely affected. Point-source dis- strict the contribution shale oil could make charges are well regulated under the Clean in the near term to the Nation’s liquid fuel Water Act; developers plan to discharge no supply. The option also would tend to dis- processing wastewater to surface streams, courage further corporate interest and although they may discharge ground water could delay the testing of a variety of tech- during the early stages of development. nologies, Standards for injecting wastewaters into ground water aquifers are being promulgated under the Safe Drinking Water Act; develop- Environment ers do not plan to inject any wastewaters, but Oil shale facilities, like other mineral may reinject the ground water extracted dur- operations, will emit pollutants and produce ing mining. Most of the wastewaters will be large amounts of solid wastes. The severity of treated for reuse within the facility. Untreat- the environmental impacts will depend on the able wastes will be sent to solid-waste dispos- scale and duration of the operations, on the al areas. As mentioned, these areas have the kinds of development technologies used, and potential for nonpoint discharges that are on the efficiency of the control strategies. The neither well understood nor well regulated at plants must be designed and operated in com- present, although a framework for their regu- pliance with environmental laws. The devel- lation has been established under the Clean opers plan to achieve compliance largely Water Act and the Resource Conservation through use of control technologies applied and Recovery Act. successfully in other industries. There ap- The extent to which development will af- pears to be little reason to believe that the fect the land will be determined by the loca- proposed controls cannot be made to work, tion of the tract; the scale, type, and combina- but they have not yet been tested for ex- tion of processing technologies used; and the tended ‘periods with the wastes produced duration of the operations. Land conditions during oil shale processing (largely topographic changes from mining and waste disposal) and wildlife will be af- Issues fected. The facilities must comply with the State laws that govern land reclamation and waste disposal, which in some ways are less How will oil shale development affect stringent than the Federal laws governing 1 the environment? reclamation of land disturbed by coal mining. The air in the oil shale region is relatively Appropriate methods must be used to prevent unpolluted and, even if the best available con- the large quantities of solid wastes from pol- trol technologies are used, a large industry luting the air with fugitive dust and the water will affect visibility and air quality not only with runoff and leachates. near the facilities but also in nearby parks Many of the occupational safety and health and wilderness areas. These impacts will be hazards will be similar to those of hard-rock regulated under the Clean Air Act. mining, mineral processing, and the refining Water quality is a major concern in the re- of conventional petroleum. Workers might, gion. Oil shale operations could pollute the however, be exposed to unique hazards be- Ch 1–Summary ● 31

Phofo credit OTA staff Colorado River flowing along Interstate 70 cause of the physical and chemical charac- known whether conventional methods could teristics of the shale and its derivatives, the treat all of the process wastewaters to dis- types of development technologies employed, charge standards, should this become neces- and the scale of the operations. To protect sary or desirable in the water-short region. workers from these hazards, the developers Nor is it known whether the proposed recla- will have to comply with the Occupational mation techniques will adequately protect the Safety and Health Act and the Mine Safety waste disposal areas from leaching. Were and Health Act. Specific practices will have significant leaching to occur, it could have to be developed as the industry grows. This severe effects on the region’s water quality. may be difficult if the growth is too rapid. The stability of revegetated spent shale piles will remain uncertain for many years, and the effectiveness of strategies proposed for What are the major uncertainties with controlling the leaching of in situ retorts is 2 respect to the impacts of the industry? unknown. Although extensive work has been under- Worker fatalities and injuries have been taken on pollution control technologies and rare in the industry to date, but oil shale has mitigating strategies and on procedures to been mined and processed only for experi- protect the safety and health of the workers, mental purposes, and at rates that are insig- uncertainties remain. For example, it is not nificant compared with commercial-scale op- 32 . An Assessment of 01/ Shale Technologies erations. Predictions of a safe working envi- those under the Prototype Leasing Program. ronment have yet to be verified under condi- Environmental groups believe that the same tions of sustained large-scale production. conditions should apply to both private lands The rates and characteristics of atmos- and Federal lease tracts. This, they believe, pheric emissions have not been firmly de- would provide better information about the fined, and their dispersion patterns cannot be environmental impacts from the technologies accurately predicted because modeling meth- operating on private holdings, and would ods are not yet adequate for the irregular ter- allow comparison with the effects from the rain and complex meteorology of the oil shale Federal lands. Furthermore, since one purpose of the Prototype Program is to obtain in- region. formation about a variety of technologies, ad- Laboratory studies, computer simulations, ditional monitoring of the private lands might and pilot-scale test programs could clear up provide these data. As a result, the need for some of these uncertainties (such as disper- additional Federal leasing might be reduced. sion behavior and wastewater treatment). Others (such as the efficacies of waste dis- Developers using private lands oppose this posal practices) may need extensive test pro- action and claim that existing requirements grams involving commercial-scale modules or are more than sufficient to monitor the ef- plants. fects of their projects. They also point out that additional monitoring is done voluntarily, and assert that some of the tests required on What potential impacts are not pres- the lease tracts are of limited or dubious 3 ently well regulated? value. New Source Performance Standards for air and water pollution control have not yet been developed, although the regulatory 4 How much will pollution control cost? framework exists and they will be forthcom- Air pollution control is estimated to cost ing as experience is gained with the oper- approximately $0.90 to $1.15/bbl of syncrude ations. Standards for hazardous air pollut- produced. Water pollution control is esti- ants and visibility will be promulgated by the mated to cost about $0.25 to $1.25/bbl of syn- end of 1981. It does not appear, however, that crude, assuming the water is treated for re- the hazardous substances to be covered by use within the facilities. Land reclamation these regulations will be generated in signifi- will cost about $4,000 to $l0,000/acre dis- cant quantities by oil shale operations. Non- turbed, or about $0.01 to $0.04/bbl of syn- point sources of water pollution are not crude. The total cost, which may vary signifi- presently well regulated. Performance stand- cantly with the location of a project, with the ards for land reclamation that are specific to nature of the operation, and with other fac- oil shale have not yet been developed. Stand- tors, might be about $1.00 to $2.50/bbl (1.6 to ards developed for coal under the Surface 2.4 cents/gal) of oil produced. Although sub- Mining and Reclamation Act are not entirely stantial, the cost should not preclude the es- suitable for oil shale because of the signifi- tablishment of an industry since it would cant differences that exist in geology, topog- have only a small effect on the product price. raphy, waste characteristics, and other factors. A regulatory framework similar to that in the Act could be used for developing oil Will the size of the industry be limited shale standards. 5 by existing environmental regulations? Environmental monitoring is presently re- Existing regulations for water quality, land quired on private lands to assure compliance use, and worker health and safety do not ap- with State and Federal regulations. The re- pear to be obstacles. However, the industry’s quirements, however, are not so strict as capacity will probably be limited by air quali- Ch. 1–Summary ● 33 ty standards governing the prevention of sig- need additional technical information, or if nificant deterioration (PSD). These specify agency personnel are overloaded with work, the maximum increase in the concentrations the process may even take longer. Although of sulfur dioxide and particulate that can oc- the permitting process is lengthy, it should cur in any area, Under the Clean Air Act, the not preclude the establishment of an individ- oil shale region has been designated a Class II ual project. Particularly if many projects be- area, where some additional pollution and in- gin simultaneously, agency overloads could dustrial growth are allowed. Class I areas, delay them all, thus causing cost overruns. where the air quality is more strictly regu- This should not limit the size of the industry, lated, however, are nearby. One of these, the but it might prevent a large industry from Flat Tops Wilderness, is less than 40 miles being established rapidly. from the edge of the Piceance basin, where most of the near-term development is likely to take place. A preliminary dispersion model- Policy Options for Air Quality Management ing study by the Environmental Protection Agency (EPA) has indicated that an industry Increase information.—More R&D could of up to 400,000 bbl/d in the Piceance basin be conducted on air pollutants, their ef- could probably comply with the PSD stand- fects, and their controls. Studies of the ards for Flat Tops, if the plants were dis- dispersion behavior of oil shale emissions, persed. Additional capacity could be infor example, would lead to a better under- stalled in the Uinta basin, which is at least 95 standing of the long-range consequences of miles from Flat Tops. A l-million-bbl/d in- these emissions on ambient air quality. dustry could probably not be accommodated, This, in turn, would provide guidance for because at least half of its capacity would plant siting to reduce air quality deteriora- have to be located in the Piceance basin. tion. Options include the evolution of existing R&D programs in EPA and DOE, their The lack of commercially available plant expansion by redistributing or increasing species that are adaptable to the oil shale appropriations, and the passage of legisla- region also could impose a temporary restriction specifically for air quality studies. tion on the industry’s land reclamation ef- R&D should be coordinated with any dem- forts. If commercial growers were to expand onstration projects that are conducted. their production to keep ahead of the needs, Data from these projects could help in set- this problem could be solved. ting performance standards for pollution control.

Will the industry be limited by the pro- Change the standards.—The emissions 6 cedures for obtaining environmental standards for oil shale facilities have not permits? yet been set because of a lack of informa- Of the more than 100 permits required for tion about the nature of the operations, The construction and operation of an oil shale fa- estimated limit of 400,000 bbl/d in the Pi- cility, about 10—the major environmental ceance basin is based on estimates of the permits—require substantial commitments of emissions that would occur if the best cur- time and resources. It may take as long as 2 rently available control technologies were years after the start of baseline monitoring applied. EPA could set stricter emissions programs to obtain these permits, with an ad- standards that would reduce air pollution ditional minimum of 9 to 24 months required and, if the standards could be met, would if an EIS needed. * If the regulatory agencies also allow more production. If the plant *A statement may take much longer. The programmatic EIS emissions were cut in half, for example, up for the Prototype Leasing Program required 4 years. Preparing to 800,000 bbl/d could be installed in the the draft EIS for the proposed Superior land exchange required 2 Vears. The EIS for extending Paraho’s Anvil Points lease is in Piceance basin, and more in Utah. This op- its fifth revision, after more than 2 years. tion would entail much higher control 34 ● An Assessment of Oil Shale Technologies

costs, and it might not be technologically Finally, the Act could be amended to ex- achievable. empt the developers from air quality regu- Another option would be to redesignate lations in both the oil shale area and the the oil shale region from Class II to Class nearby Class I areas. This would allow III. This would allow greater degradation high levels of production, again at the cost of air quality (the extent of which cannot of increased pollution over a large area. be accurately predicted in the absence of This action would encounter significant po- reliable regional modeling studies) while litical and legal resistance. allowing more production. However, it would not remove the limits imposed by Policy Options for Water Quality Management nearby Class I areas, which at present appear to be controlling. Increase information.—More R&D could

● be conducted to develop and demonstrate Amend the Clean Air Act.—There are methods for treating the process waste- three options for amending the Act. Each waters to meet discharge standards. Al- deals with the restriction posed by the PSD though not a part of current developer standards. plans, such treatment could provide addi- At present, EPA distributes PSD permits tional water resources for the water-short to developers on a first-come, first-served region. Additional attention could also be basis. The Act could be changed to require given to preventing leaching of waste dis- a coordinated strategy for facility siting posal areas and in situ retorts. Policy ac- that would maximize production while tions would be similar to those for air maintaining air quality at regulated levels. quality R&D. Alternatively, requirements EPA could allocate portions of the PSD infor developing strategies for dealing with crements based on its own analysis of the long-term effects on water quality needs and impacts, or it could consult with could be added to leases for Federal land. all of the potential developers in an attempt (The lessees in the current Prototype Leas- to evolve an optimum distribution. (An ing Program are required to develop and amendment would be required to avoid im- demonstrate both reclamation methods pediments to such cooperation under the and procedures that will prevent the leach- antitrust laws. ) Distributing the PSD incre- ing of in situ retorts. ) ment among the maximum number of facilities would amount to an implicit tightening Develop regulatory procedures and stand- of the emissions restrictions, which would ards.—Promulgating standards in the add to the costs of air pollution control. areas that are not presently well regulated The Act could be amended to exempt the would reduce the uncertainty that future developers from maintaining the air quali- regulations could preclude profitable oper- ty of the nearby Class I areas, while adher- ations. Under the present approach, regu- ing to Class II standards in the oil shale lations evolve as the industry and its con- region. The maximum size of the industry trol technologies develop. This introduces would be limited, because the developers uncertainty, but allows the standards to be would still have to comply with the region’s set with a knowledge of the technical and standards. Alternatively, if this action economic limitations. As an alternative, were coupled with a redesignation of the standards could be set that would not oil shale region to Class III, there could be, change for a period of say, 10 years, after at the cost of increased pollution in all which they could be adjusted to reflect the areas, at least twice as much production as experience of the industry. This would re- is presently possible. (The Class III stand- move the uncertainty, but the standards ards allow twice as much pollution as would have to be carefully established to Class II.) assure that they were both adequate to Ch. 1–Summary ● 35

protect the environment and attainable at Policy Options for Land Reclamation reasonable cost. ● Increase information.—R&D and field test- ● Ensure the long-term management of ing could be conducted on reclamation waste disposal sites and in situ retorts.— methods and the selection of plant species These locations may require monitoring for revegetation. This work would help set and maintenance for many years after the reclamation performance standards for projects are completed. Long-term manage- the oil shale industry. Policy actions would ment could be regulated, for example, un- be similar to those for air quality R&D. Ad- der the Resource Conservation and Recov- ditionally, the developers could continue to ery Act, which allows EPA to set standards be required in future leasing programs to for the management of hazardous materi- develop viable reclamation methods (cur- als, including mining and processing rently required of participants in the Proto- wastes. (Spent oil shale has not been classi- type Leasing Program). fied as a hazardous waste, but EPA has ● suggested that it may be given a special Establish Federal reclamation stand- classification because of the large volumes ards.—Legislation could be introduced to that will be produced.) Alternatively, the provide standards that are appropriate to developers could be required to guarantee the conditions in the oil shale region and to such management by incorporating appro- the types of disturbance that will occur priate provisions in leasing regulations. with development. The standards should be ecologically sound, economically achievable, and consistent with the public’s goals Policy Options for Occupational Health and Safety for postmining land use. Consideration ● Increase information.—R&D could be con- should be given to the relative merits of ducted on the cancer risks associated with alternative control strategies and environ- processing oil shale and shale oil. This mental performance standards necessary work should take advantage of the exten- to reduce erosion and leaching and to allow sive, but often conflicting, prior work and more efficient use of the land for wildlife, should be coordinated with ongoing stud- grazing, or other purposes. ies. Policy actions would be similar to those ● Expand the production of seeds and plant for air quality R&D. materials.—This might avoid a possible de- ● Undertake health surveillance,-A central lay in reclamation programs. It could be registry of health records would facilitate done by providing appropriations to the the identification of hazards and the devel- Federal plant materials centers and by ex- opment of protective methods. It could be panding the cooperative programs be- located in a regional medical center, with tween these centers and commercial sup- or without the active participation of Fed- pliers. eral agencies. Funds could be provided by ● Protect the wildlife and their habitats. the Government, by the States, by labor or- —Lease tracts and land exchange parcels ganizations, or by the developers. could be chosen to minimize disruption of ● Develop exposure standards.—As infor- ecologically fragile areas. This would re- mation about potential chemical health quire extensive, site-specific character- hazards is analyzed, the National Institute ization studies in advance of leasing or ex- of Occupational Safety and Health, the Oc- change. These studies would be expensive cupational Safety and Health Administra- and time consuming, but they could ulti- tion, and the Mine Safety and Health Ad- mately expedite subsequent actions by re- ministration could address the necessity ducing the duration of the baseline moni- for exposure standards. toring period that might be required of de- . .

36 ● An Assessment of Oil Shale Technologies

velopers. (Provisions for wildlife mainte- the coordination of public participation in nance were included in the leases for the agency decisionmaking processes. This Prototype Program.) might help reduce confrontations, although it could lead to an expanded perception of Policy Options for Monitoring and for risks and thus to stronger opposition. Permitting Procedures ● Clarify the regulations and the permitting Increase information.—Additional envi- process.— Simplifying the procedures ronmental monitoring of developments on would have the advantage of retaining the private lands could be required. This laws and their protection while making it would entail changing existing laws and easier to comply with them. Problems could regulations. Its advantages include gather- arise if procedures were changed while ap- ing comparable information for both pri- plications were in process. Another ap- vate holdings and Federal lease tracts. The proach would be to establish detailed, new information might reduce the need for standardized specifications for permit ap- leasing more Federal tracts to test technol- plications. (EPA is doing this for the PSD ogies not being used by the Prototype Pro- process.) This would reduce, but not elim- gram lessees. Its disadvantages include the inate, delays. Fully standardized forms are possibility of litigation. It would also in- probably not practical. crease expenses for developers using pri- ● Expedite the permitting procedure.—An vate holdings, authority (such as the Energy Mobilization Further study of the permitting proce- Board) could be established with power to dures could help to design more efficient ones while maintaining a high level of envi- make regulatory decisions if the agencies ronmental protection. The studies could be do not do so within a set period. This would conducted by the regulatory agencies or by provide a single point of contact between the General Accounting Office. the developer and the regulatory system, but it would add to the bureaucracy and in- ● Increase agency resources.—Increasing crease controversy. Another possibility personnel and financial resources would would be to limit the period of litigation for allow the agencies to improve their re- permitting actions, as was done in the case sponse capabilities and increase their as- of the Trans-Alaska oil pipeline. sistance to State and local regulators. Co- ordination of the expanded resources ● “Grandfather” oil shale projects.—Plants would also be needed. under construction, or already operating, could be exempted from future regulations. ● Improve coordination among the agencies (This concept is embodied in the Energy and between the agencies and the pub- Mobilization Board legislation.) This would lic.-Coordinated reviews could be con- remove many regulatory uncertainties, but ducted to reduce jurisdictional overlaps, would reduce environmental protection. paperwork, and workloads. It might be Some environmental laws already contain necessary to mandate coordination to as- “grandfather” clauses. sure its effectiveness. Another approach would be to establish a regionwide envi- ● Waive existing environmental laws.—This ronmental monitoring system to determine would remove virtually all of the problems baseline conditions for all areas to be af- and delays associated with permitting. fected by oil shale projects. This might re- However, it would have serious political, duce the duration and the cost of the moni- environmental, and social ramifications. toring programs now required of permit The allocations of the waivers would be applicants. Site-specific studies and mon- highly controversial. The extent to which itoring would still be needed for certain such action would speed the deployment of data. Another option would be to improve an oil shale industry is unclear. Ch 1–Summary . 37

Water Availability Is there enough surface water avail- 2 able to support a large industry with- Oil shale development will affect the hy- out curtailing other uses? drologic basins of the Green River, the White Surplus surface water will be available to River, and the Colorado River mainstem in supply an industry of at least 500,000 bbl/d Colorado. These basins are located within the through the year 2000 if: semiarid Upper Colorado River Basin, which includes the Colorado River and its tribu- additional reservoirs and pipelines are taries north of Lee Ferry, Ariz. (See figure 7.) built; The river system is one of the most important and in the Southwest, It serves approximately 15 demand for other uses increases no fast- million people, and its waters are critical re- er than the States” high growth rate pro- sources for towns, farming, industry and min- jections; ing, energy development, recreation, and the and environment. In the past, natural flows along average virgin flows of the Colorado with water storage and diversion projects River do not decrease below the 1930-74 have generally been adequate. However, be- average (13.8 million acre-ft/yr). cause the region is developing, water supplies Otherwise, surface water supplies would not are beginning to be strained, and at some be adequate for this level of production un- point in the future a scarcity of water may less other uses were curtailed, interstate and limit further growth. international delivery obligations as presently interpreted by the Government were not Issues met, or other sources of water were developed. If the reservoirs and pipelines are built, flows do not decrease, and the region devel- What are the water needs of an oil ops at a medium rate (which the States re- 1 shale industry? gard as more likely), there should be suffi- Depending on the technologies used, pro- cient surplus water to support an industry of ducing 50,000 bbl/d of shale oil syncrude over 2 million bbl/d through 2000. would consume 4,800 to 12,300 acre-ft/yr of In the longer term, surface water may not water for mining, processing, waste disposal, be adequate to sustain growth. Surplus water land reclamation, municipal growth, and availability is much less assured after 2000. power generation. This is the equivalent of If the rivers’ flows do not decrease, and if a from 2. I to 5.2 bbl of water consumed per low growth rate prevails, demand will exceed barrel of oil produced. A l-million-bbl/d in- supply by 2027 even without an oil shale industry using a mix of technologies might re- dustry. With a medium growth rate, the sur- quire 170,000 acre-ft/yr. This is slightly more plus will disappear by 2013. A high growth than 1 percent of the virgin flow* of the Colo- rate will consume the surplus by 2007, again rado River at Lee Ferry, or 5 percent of the without any oil shale development. This is a water consumed in the Upper Basin at pres- potentially serious problem for the region, ent. * * and its implications for oil shale development are controversial. On the one side, it is argued that there is no surplus surface water ‘Virgin flow is the flow that would occur in the absence of human-related activities. and this should preclude the establishment of **For comparison, irrigated agriculture along the White an industry. On the other side, it is main- River and the Colorado River consumes about 549.000 acre- tained that the facilities in a major industry ft/yr to produce 3 percent of Colorado”s crop production. This is equivalent to the water needs of a 3.2-m illion-bbl/d oil shale in- could function for much of their economic dustry. lifetimes without significantly interfering 38 ● An Assessment of Oil Shale Technologies

Figure 7.—The Upper and Lower Colorado River Basins

● BOISE IDAHO J’ k-w A

I Great Salt CHEYENNE Lake lb ● .

( MEXICO

1 t 100 MILES

SOURCE’ C. W Stockton and G. C Jacoby, “Long-Term Surface-Water SUPPIY and Streamfiow Trends In the UPper Colorado Rwer Basin Based on Tree-Ring Analyses,” Lake Powell Research Project Bulletin No. 18, March 1976, p. 2. Ch. 1–Summary . 39 with other users, and in any case would use the cost of treating the water to industrial relatively little water. (A l-million-bbl/d in- standards. Development of high-quality dustry would accelerate the point of critical ground water would be least expensive, but water shortage by about 3 years if only sur- would be limited to specific areas. face water were used.) In any event, the analysis of future water availability is clouded by the uncertain de- Will the use of water for oil shale demand schedules of other users and by a long- 4 velopment affect irrigated agricul- standing legal conflict between the Upper ture? and Lower Basin States. It is not clear how The effects on farming should be relatively much water is legally available to the Upper small, especially when compared with those Basin and therefore to the oil shale region, caused by competition for labor and by the For example, the calculations presented purchase of farmlands for municipal growth. above assume that 750,000 acre-ft/yr is sent Farm production in the Colorado portion of from the Upper Basin to Mexico to satisfy a the Upper Basin would be reduced if rights to national delivery obligation incurred under irrigation water were sold to oil shale devel- the Mexican Water Treaty of 1944-45. The opers, but the present developers do not plan Upper Basin States maintain that they are not to purchase irrigation water in significant responsible for this obligation and that the quantities. In the longer term, if water short- water should be freed for their use. (The ages occur, the industry may have to pur- quantity of water in question is equivalent to chase water, thus displacing farm produc- the water needs of a 4.4-million-bbl/d oil shale tion. The water laws of all three States allow industry. ) The region’s water problems can- the transfer of rights between willing sellers not be solved, however, simply by reallocat- and purchasers. ing surface water supplies from the Lower Basin States, where water is an equally critical resource. Rather, if growth is to be sus- Will developing water resources for oil tained in both basins, it may be necessary to 5 shale have severe environmental im- increase net supplies by more efficient mu- pacts? nicipal, industrial, and agricultural use; or to increase gross supplies by importing water The environmental impacts will include re- from other hydrologic basins or possibly by duced stream flows, increased salinity in the weather modification. All of these options river system, and land alterations as a conse- would be expensive, will involve environmen- quence of constructing reservoirs and diver- tal impacts, and could encounter legal, politi- sion facilities. These should be small on the cal, and institutional opposition. Upper Basin as a whole, but could be large in some areas, especially where reservoirs will be built. Fish habitats and recreational activ- Will the costs of obtaining water limit ities along the White River are expected to be 3 the size of the oil shale industry? the most severely affected. Environmental impacts on the Lower Basin States should not be Although water is expensive in the West, substantial. the costs of water development will be a small fraction of the costs of producing shale oil and therefore should not limit development. What will be the economic effects of The costs of the most expensive water supply 6 developing water resources for oil option, importation from other hydrologic ba- shale? sins, could exceed $1/bbl of shale oil produced. Other supplies would cost less than The economic losses from decreased flows $0.50/bbl. This includes the amortized costs and increased salinity could reach $25 mil- of reservoir and pipeline construction plus lion per year for a 2-million-bbl/d industry. 40 . An Assessment OfOil Shale Technologies

These would include the effects of increases ment alternatives, however, has compared in salinity on farming and of reductions in water supply options with respect to their river flows on farming and hydroelectric water and energy efficiency, their costs power production. (It is assumed that the de- and benefits, and their environmental and velopers do not purchase irrigation water. ) social effects. Such an assessment, involv- The positive effects of the same industry ing Federal, State, and local governments; would include a gain of several billion dollars regional energy developers; other users; per year in regional income. A simple com- and the general public, may be an appro- parison of the relative gains and losses priate prelude to actions to construct new should be made with caution, however, be- water storage and diversion projects. It cause some of the adverse effects would oc- could be especially useful in evaluating cur in areas that will not enjoy the benefits. and coordinating such controversial op- For example, some of the impacts on farming tions as importation of water. Funding will be experienced in the Lower Basin. could be provided by DOI, DOE, or other agencies. USBR or the Colorado River Com- Policy Options pact Commission could manage the study.

● ● Development of a water management sys- Financing and building new reservoirs.— tem.—The U.S. Bureau of Reclamation New reservoirs will be needed if a large in- (USBR)* and individual developers and dustry is to be established. These could be other users have conducted preliminary provided through two mechanisms, First, water management studies. No systematic Congress could appropriate funds for those basinwide evaluation of water manage- water projects that have already been authorized under the Colorado River Storage *NOW the Water Power Resources Service, Project Act. (At least one of these, the West Ch 1–Summary ● 41

Divide project, may be suitable for supply- tial source appears to be the NOSRs in Col- ing water to oil shale facilities in Colorado. ) orado and Utah. The States might resist al- Second, legislation could be passed speci- locating this water to an oil shale industry. fying both the construction and funding of For example, the use of water from NOSR 1 water projects not now authorized for the is in the early stages of litigation in Col- region, Alternatively, a State organization orado. or the oil shale developers themselves could finance and build the water storage. Supply water through interbasin diver- A commitment to the facilities would sim- sions.—Water shortages in the Upper plify planning for the oil shale industry and Basin could be reduced by importing water for other regional growth as well. The fa- from other hydrologic basins. Options in- cilities would be expensive, and their con- clude transporting water directly to the oil struction might be resisted especially if shale region; or to satisfy all or part of the general tax revenues were used for this delivery obligation to Mexico; or to supply purpose. water to the cities in Colorado’s Front Range Urban Corridor (to replace the wa- ● Minimizing reservoir and diversion siting ter that is presently obtained from the oil problems.—The siting, construction, and shale region). All of these options could re- operation of reservoirs and diversion proj- lease sufficient water to support a large in- ects could be affected by the Endangered dustry as well as allowing other types of re- Species Act, the National Wild and Scenic gional growth. However, they all would be Rivers Act, and the Wilderness Act. Prob- expensive. Furthermore, the study of diver- lems could be avoided if Congress directed sions into the Colorado River Basin is that the Federal agencies complete a sur- banned by Federal statute until 1988, This vey of endangered species in the area (in- ban would have to be lifted before the op- cluding the designation of critical habitats, tion of supplying water directly to the oil if any are found), identify the stream shale region could proceed. The other al- reaches that will be included in the Wild ternatives might not be impeded. and Scenic Rivers System, and designate the areas to be included in the National Encourage more efficient use of water.— Wilderness Preservation System. The stor- Financial and technical assistance could age and diversion facilities could then be be provided to encourage municipal, agri- sited to minimize interference with these cultural, and industrial water conservation areas. The environmental surveys in par- practices. Likely targets would be agricul- ticular could be time-consuming and ex- ture, powerplants, the oil shale facilities in pensive, and expediting the selection proc- the development region itself, and the cities esses might involve departing from the pur- on the eastern slope of the Rocky Moun- poses of the respective Acts. tains that import water from the region, Large quantities of water could be saved, ● Make water available for oil shale.— Congress could take steps to assure that although at substantial cost. The imple- water was supplied to oil shale facilities mentation of these policies could encounter from Federal reservoirs, both the existing resistance. Augmentation methods such as ones and any new ones that might be built, weather modification could be tried but This policy would have to be carefully im- would entail environmental, legal, and in- plemented to avoid interfering with other stitutional problems. users and with the water management policies of the affected States, The Government could also provide wa- Socioeconomics ter from Federal reserved rights. Because of legal restrictions on the use of water The oil shale region in which near-term de- from Federal reservations, the only poten- velopment is likely to occur is a 3,200 mi2 —

42 . An Assessment of Oil Shale Technologies

rural area, sparsely populated and with lim- Issues ited transportation. (See figure 8.) In northwestern Colorado, about a dozen towns in three counties are likely to be substantially How many people can the region ab- affected. * The population of one of these sorb? counties could increase by as much as seven- 1 fold if a 500,000-bbl/d industry were estab- Between 1985 and 1990, the physical facil- lished and other energy industries expanded. ities of the small communities in Garfield and (See figure 9.) The benefits of this growth Rio Blanco Counties that will be most affected could include increased employment, higher by oil shale development should be able to ac- wages, a broader tax base, community im- commodate up to 35,000 people. This as- provements, and stimulation of other busi- sumes presently planned improvements and nesses. Among the negative consequences expansions (including the construction of Bat- could be a severe housing shortage, strain on tlement Mesa, a new town) can be completed. public services and facilities, symptoms of (See table 6.) This capacity, which is an in- social stress such as increased crime, and crease of 250 percent over the present popu- private-sector dislocations such as small- lation, is compatible with the growth that will business failures. Even if the growth is rea- accompany completion of the two presently sonably well controlled, some residents may active oil shale projects (they could produce perceive a deterioration in their quality of 133,000 bbl/d). The growth accompanying an life. The term “modern boomtown” has been industry of up to 200,000 bbl/d could be ac- used to describe communities that have expe- commodated if the construction were phased rienced these kinds of growth-related nega- and if some of the new people lived in adja- tive impacts. cent Mesa County. If additional projects were sited in Utah, the industry could reach The region is presently growing and has ex- 300,000 bbl/d. Major efforts would be neces- perienced some adverse effects, although local officials are confident that their commu- Table 6.–Actual and Projected Population and Estimated nities can deal with additional development. Capacity of Oil Shale Communities in Colorado The oil shale developers have been respon- sive to the social effects of the industry’s ex- Population 1977 1980 1985-90 pansion. A sense of increased community Location a censusb projected c capacity d identity and pride is already evident, and is Garfield County considered by some as a positive conse- Rifle ., 2,244 4,362 10,000 quence of oil shale development. Whether the Silt ...... 859 1,211 2,800 New Castle. ., 543 831 1,000 communities will continue to deal successful- Grand Valley. 377 589 3,000 ly with their growth, or be overwhelmed by it, Battlement Mesae – 198 2,500 will depend on a number of factors. Among Other . . . . . – — 1,700 these are: Subtotal f . 4,023 7,191 21,000 Rio Blanco County ● the absolute numbers and abruptness of Meeker ,. 1,848 2,779 6,000 the population influx; Rangely . . . : : : : : : : ., 1,871 2,223 6,000 1,381 1.542 ● the attitudes of both long-term residents Other. . . . 2,000 and newcomers; Subtotal . . ., ... 5,100 6,544 14,000 ● past experiences with boom and bust Total ...... , 9,123 13,735 35,000 cycles; a~es not Include Mesa or Moffat Counties both of which are more dlslant from the area Of devel- ● opment the ability of local political structures to bAcluals from a special U S census prepare for population growth; and cEnd.of.lhe.year projections by the Colorado West Area COUflCIl of Governments dEstlmated by OTA from various plarlrllrlg and needs assessments documents, assumes COM@ ● the availability of assistance—financial hon of currently planned protects (e g housing, waler and sewer system expanwons street and road Improvements, elc ) and other—for mitigation of impacts. eA new [own, cons[ruc(lon anhclpaied 10 begin In the early 1980 s *This summary refers primarily to Colorado. Utah and Wyo- flncludes only [he Immediate 011 shale Wlnlty ming are discussed in ch. 10. SOURCE Off Ice of Technology Assessment Ch. 1–Summary 43

pacts, and has invested in housing and in the land for Battlement Mesa. The communities have been developing municipal facilities and services. New housing is being built, businesses expanded, and health care extended. The State has appropriated more than $40 million for over 75 projects, and the Federal Government has contributed technical assistance. These efforts have prepared the towns for a reasonable number of new residents.

Will oil shale development cause com- 2 munity disruption? Not enough is known about the causes of boomtowns to be able to predict the exact threshold beyond which oil shale development would lead to serious impacts. How- Photo crecfff OTA stalt ever, establishing a l-million-bbl/d industry Marker indicating original site of the by 1990 would exceed the capacity of all of Northern Ute Indian Reservation near Meeker, Colo. the communities, and stressful living conditions would be inevitable. It is known that the sary to assist the small communities in Utah if possibility of disruption will be influenced by sudden, rapid growth accompanied industry the location of the growth, by the total num- expansion. * In Colorado, additional growth ber of newcomers, by the rapidity with which could be accommodated if some of the pres- they arrive, and by the ability of the com- ently planned facilities for workers and their munities to prepare for the influx. Some families were constructed quickly. For exam- towns in Wyoming have successfully accom- ple, according to current schedules, Battle- modated expanded coal development, while ment Mesa will house 1,500 residents in its others that have experienced the same kinds first phase of development (ultimate plans of growth, and have had access to the same call for a maximum of 7,000 units for 21,000 preventive programs, have suffered for long people). If construction were accelerated, periods. The social and economic problems more could be housed in a shorter period of accompanying oil shale growth could be ag- time. gravated if development is concurrent with The Colorado communities expect to be expansions in other industries. The region is able to assimilate more residents because already experiencing some rapid growth, they have been preparing for an oil shale in- particularly from coal mining. dustry for nearly 10 years. Local interests have participated in broadly structured task forces that assist in planning and managing What role can industry play in dealing growth. The industry has supported these 3 with the socioeconomic consequences groups. It also has aided local governments, of oil shale development? has adopted programs to reduce negative im- Industry has contributed financial and technical assistance to the growth manage- *Plaming for oil shale impacts in Utah has not been as ex- ment effort. The Mineral Leasing Act of 1920 tensive as in Colorado for a number of reasons. Most important allows the affected States to share in the pro is that mitigation funds from a major source (the State’s share ceeds from leasing programs; Colorado re- of bonus and lease payments under the Mineral Leasing Act) have been held in escrow pending settlement of the ownership ceived nearly $74 million as its share of the questions. bonus payments for Federal tracts C-a and 44 ● An Assessment of Oil Shale Technologies

I I L— — — 1 I I L .— I I I I Y I I I I I I I I I I I \\ I I

I \ I I I

I I Ch 1–Summary ● 45

Figure 9.— Projected Growth of Counties in Northwestern Colorado From Oil Shale Development, 1980-2000

190,000 *

180,000

170,000

160,000 MESA COUNTY /

150,000

140,000

130,000

120,000

110,OOO

100,OOO

.5 90,000 ~ # 80,000 e GARFfELD COUNTY

70,000

60,000

50,000 / RIO BLANCO COUNTY 40,000

30,000

20,000

10,000 o

1 m n 1 1 9 1977 1980 1985 1990 1995

1977-actual t30mdation from special U.S. census 1980-ZOOO+ojections assun& oil shale development with a production I@/el of 500,000 BPD by 1990 and 750,000 BPD by 1995 combined with other energy industry (e.g., coal, electric generation, oil & gas) expansion.

SOURCE: Colorado West Area Council of Governments. 46 . An Assessment of Oil Shale Technologies

C-b. From this fund has come the $40 million attempted before 1990. In this case, a coordi- for community improvements in Colorado’s oil nated growth management strategy would be shale area. The lessees and other developers required to ensure that financing was avail- have contributed additional money and sup- able for building houses, that public facilities port for planning efforts and other improve- and services could be provided, that basic ments. If more projects are initiated by leas- needs could be met, and that a reasonably ing, more funds will become available. If, on stable work force could be maintained for the the other hand, the new projects are on pri- industry. Many Federal, State, local, and private land or on land-exchange parcels, devel- vate organizations, operating in many areas oper participation will be voluntary. and at all levels, would have to be involved to cope with sustained, rapid growth. It is in the developers’ best interest to participate. The benefits of such involvement are illustrated by the experience of the Missouri Policy Options Basin Power Cooperative in installing a pow- The courts have affirmed that, under the erplant on the Laramie River in Wyoming. National Environmental Policy Act of 1969, The developer invested $21 million in mitiga- the Federal Government must examine the so- tion efforts through grants and revenue guar- cial impacts of its major actions. The prob- antees to towns, counties, and public agen- lems accompanying recent expansion of ener- cies; by inkind services; with bond guaran- gy industries have led to a call for more Fed- tees; and with other types of assistance. The eral involvement. The extent and nature of company believes that it saved about $50 mil- this involvement, however, are controversial. lion in project costs by reducing employee On the one side it is argued that socioeco- turnover and avoiding construction delays. nomic changes are the inevitable results of in- Furthermore, all but about $3 million of the dustrial development and are, at most, State initial outlay will be recovered. Ultimately, and local problems. On the other side the the amount spent for mitigation may be less position is taken that national energy re- than 1 percent of the total cost of the plant. quirements are the root causes of negative impacts and, for reasons of equity, active Federal participation in their amelioration is What role can the Federal Government appropriate. Some examples of Federal as- 4 play? sistance programs arising from the latter The region should be able to accommodate position are the Coastal Zone Management growth from the presently active projects, Act Amendments of 1976, which are directed and no new Federal initiatives appear to be at communities experiencing impacts from oil needed unless an industry larger than and gas development on the Outer Continen- 200,000 bbl/d is desired before 1990. Al- tal Shelf, and the Powerplant and Industrial though some towns and counties have experi- Fuel Use Act of 1978, which established the enced problems in obtaining funds for specif- Impacted Area Development Assistance Pro- ic improvements, the existing growth man- gram (the sec. 601 program) to aid areas af- agement mechanisms have been successful to fected by coal and uranium development. date. They involve a cooperative effort among With respect to the socioeconomic prob- local citizens; municipal and county govern- lems of oil shale development, there are three ments; regional, State, and Federal agencies; policy options available. These options could the oil shale developers; and other energy in- be considered in bills that deal with the ef- dustries. These efforts must not be inter- fects of all types of energy development; or rupted if the communities are to continue to they could be considered along with the im- be able to deal with their growth problems. pacts of similar energy forms (e.g., synthetic Increased Federal involvement will be re- fuels); or they could be treated solely as the quired if production of over 200,000 bbl/d is consequences of oil shale development. Ch 1–Summary . 47

● Continuation of present policies.—Federal could include amending existing laws, assistance could continue to emphasize passing new legislation, or exercising over- technical and financial aid. Revenues sight powers. channeled through established programs Extension of impact mitigation programs. would be the major mechanism, but other —Existing programs could be expanded or programs not now designed to deal specifi- new ones adopted. Amendments to extend cally with impact mitigation could be redirected to assist the communities. Con- the assistance provided by the Powerplant gressional action would primarily involve and Industrial Fuel Use Act of 1978 are continuing or increasing appropriations. currently under consideration by Con- gress. * Among their features are the au- ● Increased growth management involve- thorization of grants, loans, loan guaran- ment. —New emphasis could be given to in- tees, and payment of interest on loans. An creased regulation. For example, social expediting process for providing assist- and economic effects could be made cri- ance through current Federal programs is teria for selecting Federal tracts to be of- proposed, as is an interagency council to fered in leasing programs, Alternatively, coordinate Federal efforts. This assistance mandatory participation of the lessees in is directed to the effects of major energy mitigation efforts could be included in the developments, which could include oil lease terms. Greater Federal involvement shale. in monitoring and in technical assistance is another possibility. Congressional action *S. 1699. CHAPTER 2 ——

CHAPTER 2 Introduction

At the request of the Senate Energy and tified, and some possible Government Natural Resources Committee, OTA has policies are discussed. studied the history and status of efforts to develop the oil shale resources in Colorado, ● Chapter 6— “Economic and Financial Utah, and Wyoming. The Committee’s request Considerations”- deals with the costs of called for a complete assessment of shale oil recovering shale oil and with the risks recovery technology in general and of the cur- that inhibit oil shale projects. These rent Federal Prototype Oil Shale Leasing Pro- risks include the absence of certainty gram in particular. about the capital cost estimates for commercial plants, the future of conven- The remaining chapters of this volume deal tional oil prices and their impact on with the general context of oil shale develop- shale oil prospects, and the adequacy of ment, The following subjects are discussed, U.S. equipment manufacturing and construction and design capacity for rapid ● Chapter 3— “Constraints to Oil Shale Commercialization: Policy Options to Ad- deployment of a large industry. The need dress These Constraints’ ’—describes for Government subsidies is evaluated. some alternative objectives that might A number of financial incentives are ex- be pursued to control the growth of the amined for their influence on the break- industry. Four development scenarios even price for syncrude from shale oil, are used as a framework for identifying the probability of project financial loss, the obstacles that might inhibit or pre- and the net cost to the Government. No clude the establishment of industries of explicit attempt has been made to com- various sizes before 1990, (This analysis pare the economics of shale oil with that is based largely on information con- of other synthetic fuels nor with possibil- tained in the subsequent chapters.) The ities such as conservation or solar en- congressional policies that might be di- ergy. Such a comparison is outside the rected to these obstacles are then dis- scope and mandate of the present study. cussed. Given these obstacles and poli- The chapter assumes that the commer- cies, the relative degree to which each cial prospects of shale oil will continue scenario would attain each objective for to be determined until the end of this development is then described. century by its cost and price relationship with conventional oil. ● Chapter 4—’’Background"-describe the oil shale region, discusses the re- ● Chapter 7—’’Resource Acquisition”’— sources, outlines the processes for ex- discusses the characteristics of the oil tracting shale oil and other materials, shale lands that are owned by the Feder- and summarizes the history and status al Government and by private parties. of development efforts in the United The possible need for involving addition- States and abroad. al Federal land is related to the level of shale oil production that is desired, and Chapter 5—” Technologies ’’—describes to the provision of other types of encour- the mining and processing methods that agement, such as subsidies, The princi- could be employed to recover shale oil pal mechanisms for providing such land and to refine it to finished fuels. The ad- —leasing and land exchange—are de- vantages and disadvantages of the vari- scribed and evaluated. ous processes are presented and their status summarized. Research, develop- ● Chapter 8—’’Environmental Considera- ment, and demonstration needs are iden- tions”—discusses the implications of de-

51 52 ● An Assessment of 0il Shale Technologies

velopment for the environment and for on the small, rural communities that the workers. Separate discussions are characterize the oil shale region. The provided for the potential effects on air population increases that might accom- quality, water quality, land characteris- pany development are estimated, and tics, and the health and safety of the the abilities of the communities to ac- workers. In each case the legal frame- commodate this growth are evaluated, work governing the effects is described, The nature of the potential impacts is the potential impacts of development are discussed and possible policy responses discussed, the proposed control technol- are presented. ogies are evaluated, and the areas of uncertainty are identified. A discussion is Volume II presents a history of the current also included of the procedures that con- Federal Prototype Oil Shale Leasing Program, trol the issuance of environmental per- together with an analysis of a prior leasing mits for oil shale projects. Possible gov- attempt which, although unsuccessful, af- ernmental policy responses are dis- fected the character and conduct of the Pro- cussed for each area of concern. totype Program. The problems encountered in ● Chapter 9—”Water Availability”- the Program since its inception are discussed, deals with the implications of oil shale and the status of development on the lease development for the region’s scarce tracts is described, The ability of the Pro- water supply. The water resources gram to achieve its original objectives is eval- themselves are described, and the insti- uated. tutional framework that governs their allocation is discussed. Water require- Each aspect of this assessment is based on ments of conventional users are pro- recent publications, on contractor reports jected to the year 2000 and compared prepared for OTA, and on the independent in- with the physical resources to determine vestigations of the project staff. The results if surplus water might be available to are current as of February 1980. It is impor- support an oil shale industry. Mecha- tant to note that the oil shale situation is in a nisms and policies for making additional state of flux and that new developments may water available are discussed. significantly alter the status and outlook of ● Chapter 10—” Socioeconomic Aspects” the industry and affect the accuracy of any —deals with the effects of development conclusions presented herein. CHAPTER 3 Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints Contents

Page Table No. Page Introduction ...... 55 8. Some Potential Oil Shale Development Approaches to Development ...... 55 Sites in Colorado and Utah ...... , . . 60 Possible Objectives...... 55 9. Some Production Alternatives for the Possible Futures ...... 57 Scenarios ...... 61 10, Constraints to Implementing Four Requirements for Development...... 57 Production Targets ...... ~ ...... ,. 61 11. Actual and Projected Population and Constraints to Development...... 60 Estimated Capacity of Oil Shale Technological ...... 62 Communities in Colorado...... 65 Economic and Financial ...... 62 12. Subsidy Effect and Net Cost to the Institutional ...... 63 Government of Possible Oil Shale Environmental ...... 64 Incentives...... Water Resources ...... 64 68 Socioeconomic ...... 65 Policy Considerations...... 66 Technology ...... 66 Economic and Financial ...... 67 Institutional ...... 71 Environmental ...... 74 Water Resources ...... 75 Socioeconomic ...... 78 List of Figures Scenario Evaluation...... 80 Figure No. Page ListofTables 10. Some Present and Potential Oil Shale Development Sites in Colorado and Utah 59 ‘I’able No. Page 11. The Relative Degree to Which the 7. Requirements for the Production Production Targets Would Attain the Scenarios ...... 58 Objectives for Development...... 81 ——

CHAPTER 3 Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints

Introduction

This chapter describes the requirements these considerations all bear on decisions for establishing an oil shale industry by 1990, about the future of oil shale, even though they discusses potential constraints to its estab- may not be discussed here as barriers to its lishment, and presents policy options to ad- development. dress them, The effects of oil shale develop- This chapter is organized as follows: ment on the physical, social, and economic environments are discussed in this chapter ● Alternative objectives for development only to the extent that they are obstructions are identified. To provide a framework to development, Not all of these effects hinder for analysis, production scenarios are development, and those not judged to be bar- presented that might result from pursu- riers are not included here, For instance, filling different combinations of these ob- ing a canyon with spent shale constitutes an jectives. irrevocable alteration to the locale’s appear- ● The requirements for investment capi- ance; but does not, by itself, bar development. tal, water, labor, and a favorable combination of marketability and land avail- The many important issues not identified ability are summarized for the produc- as constraints are summarized in chapter 1 tion targets of the scenarios. and dealt with at length in the subsequent ● The constraints to achieving the targets chapters. Comprehensive analyses are pre- are identified. sented of the economics of oil shale develop- ● Some policies for dealing with the con- ment (ch. 6), and of the effects production straints are discussed. could have on the air, land, water, worker ● Given the requirements, constraints, health and safety (ch. 8), on regional water and policies, the scenarios are evaluated availability (ch. 9), and on the social and with respect to the relative degree they economic structure of the region’s commu- could attain each of the objectives for nities (ch. 10). As the next section explains, development.

Approaches to Development Possible Objectives erences they show for particular types and rates of development reflect these differ- Whether, how, and to what extent an oil ences. Some of the varied, and often compet- shale industry should be developed will ulti- ing, objectives for development are discussed mately be a political decision. The past ef- below. forts of diverse groups—Government agencies, private firms, public-interest advocates, To position the industry for rapid deploy- and environmental conservationists—to in- ment.—The supporters of this objective ac- fluence public policy on behalf of their goals knowledge that more information is needed will undoubtedly continue, These interests about oiI shale technologies if production is to have different perceptions about the relative be expanded rapidly in times of national importance of certain basic values. The pref- need. Many techniques and sites would be re-

55 .

56 ● An Assessment of Oil Shale Technologies quired to answer most of the remaining ques- To maximize ultimate environmental infor- tions about the technical, economic, and envi- mation and protection.—The desirability of ronmental implications of full-scale devel- maintaining the existing environmental qual- opment. Demonstration plants to allow the ity of the oil shale region and its environs is evaluation of a full spectrum of technologies emphasized by the supporters of this objec- would be needed. Incentives and additional tive. They also believe that oil shale should Federal land might be made available to en- not be promoted more than other potential encourage private sector experiments. All pro- ergy sources that could be less harmful to the grams would be designed to maximize infor- environment. They would prefer that devel- mation generation. Growing international opment proceed slowly, if at all, until its po- tensions, with the consequent potential for se- tential impacts have been determined and vere disruptions in oil supplies, provide a ra- control strategies designed and thoroughly tionale for this objective. tested. The policies in this case would emphasize the enforcement of existing environmen- To maximize domestic energy supplies.— tal regulations, the siting of any new plants to This objective emphasizes the rapid develop- minimize their impacts, continued monitoring ment of a large industry, and has both eco- and R&D to provide information for the pro- nomic and national security implications. The mulgation of new regulations, and public edu- benefits include reduced reliance on oil im- cation and participation in decisions. ports, improved balance of payments, stimulation of private capital investment, in- To maximize the integrity of the social en- creased employment, and lower energy costs vironment.-This objective emphasizes per- over the long term. Policies supporting this sonal and community needs. Its supporters objective emphasize the encouragement of would prefer to see a slow but steady devel- the oil shale industry and the removal of re- opmental pace in order to avoid the poten- straints on its establishment. Among these tially disruptive effects of too-rapid growth. policies might be additional Federal leasing, Well-planned and coordinated growth man- substantial economic incentives, waiving of agement is essential to meet this objective. environmental laws, and direct Government Policies would stress the involvement of local involvement in the production of shale oil. residents in the growth management process, To minimize Federal promotion.—This ob- efforts to avoid exceeding the growth capaci- jective is supported by those who oppose Gov- ties of the communities, the funding of needed ernment involvement in the free market and community improvements, and the allocation with private enterprise. Other supporters of responsibilities for both growth manage- stress that oil shale should not be promoted at ment and impact mitigation among the oil the expense of other energy sources. In both shale developers, and the local, State, and cases, the advocates believe the industry Federal governments. should develop in response to traditional market pressures and opportunities and without To achieve an efficient and cost-effective the active financial participation or support energy supply system.—Supporters of this of the Government. Policies that relate to this objective emphasize the importance of pro- objective emphasize R&D, with particular at- viding a mix of energy alternatives with the tention to technological and environmental best overall ratio of costs to benefits. They uncertainties; this would provide a basis for stress the need to position the industry and its comparing oil shale with other energy alter- technologies for long-term profitable opera- natives and for developing regulations. Plan- tions. Future expansions could then be sup- ning for future programs to mobilize the in- ported with internally generated financing. dustry would be carried out; programs such The related objectives of efficient develop- as leasing, land exchanges, and financial in- ment of the resource and balanced environ- centives would not. mental and social protection are also empha- Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints . 57

sized. The proposed pace of development the other hand, the public trust requires that would allow thorough evaluation of the tech- these resources be developed with good man- nologies so that the elements of production agement practices, with minimum waste and (land, labor, capital, water, energy, and in- inefficiency, and with equitable treatment of cremental environmental changes) could be the affected groups and regions. This man- used most efficiently if a large-scale industry date would lead to a moderate pace of devel- were created. Policies would give attention to opment. Furthermore, the Government is re- incentives that left intact a degree of mana- quired by its own laws to protect the environ- gerial risk, to thorough testing of diverse ment of the oil shale region and to consider technologies and sites, and to advanced R&D the socioeconomic consequences of each of that would provide a basis for comparing oil its major actions. These mandates would lead shale with its alternatives. These policies to slow, carefully managed development. would not require a commitment of funds and Depending. on the emphasis given to the resources to the exclusion of other potential various development objectives, a number of energy sources. future industries could be postulated, from none at all, to the production of several Possible Futures million barrels of shale oil per day. Four scenarios, based largely on shale oil produc- The Government, in preparing its policies tion targets for 1990, will be considered as a for oil shale development, is bound to consid- framework for evaluating the requirements, er and weigh along with others, all of the ob- the effects, and the policy implications of de- jectives discussed above. For example, the velopment. These are: Government is responsible for protecting the Nation from external threats of interruptions Production target of in the supply of essential raw materials like Scenario shale oil (bbl/d) petroleum. This responsibility, when coupled 1 ...... 100,000 with the Government’s ownership of the rich- 2 ...... 200,000 est oil shale deposits, would tend to encour- 3 ...... 400,000 age the rapid development of public lands. On 4 ...... 1,000,000

Requirements for Development In order to proceed, each project will need: tal, water, and labor are shown in table 7. Also shown are the numbers of new residents ● land, who will have to be accommodated by the re- ● water, gion’s communities. Water requirements in- ● adequate mining and processing technol- crease directly with the level of production ogies, because the amount each plant will need is ● access to markets, independent of the others. Ranges are given ● a favorable economic outlook, because different technologies having differ- ● investment capital, ent water requirements could be used. Be- ● compliance with environmental regula- cause of the assumptions made about the tions, phasing of construction, the labor require- ● design and construction services, ments do not always increase directly with ● equipment and construction materials, the level of production. In addition, whereas ● construction and operating labor, and scenario 4 produces 2.5 times more oil than ● housing and community services. scenario 3, it requires from 2.5 to 4 times more capital. This cost escalation is attribu- The requirements of the scenarios for design table to the large demands for labor, materi- and construction services, equipment, capi- als, and equipment for 1 million bbl/d.

i. - ,1- .—

58 . An Assessment of Oil Shale Technologies

Table 7.–Requirements for the Production Scenarios

Requirements Resource Scenario 1 Scenario 2 Scenario 3 Scenario 4 Institutional Design and construction services, % of 1978 U.S. capacity needed each year Minimal Minimal 12 35 Plant equipment, % of 1978 U S. capacity needed each year Minimal Minimal 6-12 15-30 Economic and financiala Loans, $ billion ., ., $09-1.35 $1,8-2,6 $36-4.2 $90-135 Equity, $ billion ., ., 2.1-315 4.2-5.9 84-9,8 21.0-31 5 Total, $ billion ,,, ., ,, 30-4,5 6.0-8,5 12,0 -14,0 30,0 -45.0 Annual, $ billionb 06-0,9 1.2-1 7 24-2.8 6.0-9,0 Water availability Water, acre-ft/yrc ., ., ., ., ., 9,800-24,600 19,600-49,200 39,200-98,400 100,000-250,000 Socioeconomic Workers. ., ,,, 5,600 8,800-11,200 17,600-22,400 44,000-56,000 New residents requiring housing and community services ., 23,000 41,200-47,200 82,000-95,000 118,000-236,000

aTh!rd-quarler 1979 dollars bMaxlmum annual requlrernerl[s for a 5-year ConstructIon period cAssumes 4900.12300 acre.ft/ yr for produchon of 50000 bbl/d Of shale oll syncrude dAssumes I 200 ~onstructlon ~orker~ and 1 600 operators per 51J OO&bbl/d plant Multlpllers used for [o[al Increase = z 5 x (Corlstruct[r)f) workers ~ + 55 x (O~eralOrS) Ranaes reflect adjustments In conslruct!on work forces assuming phasing ot plant construchon SOURCE OftIce ot Technology Assessment

All projects share certain critical require- might be combined to achieve the production ments that do not appear in the table. First, goals of the scenarios. The locations of tracts permits will have to be obtained. Their num- on which projects could be sited are shown in ber and nature will depend on the project’s figure 10. The ownership of the tracts and the location, on the technologies used, and on status of their development are shown in whether the site is privately owned or is con- table 8. Many other tracts exist that could be trolled by either the Federal Government or a developed, thus the list of possible sites in State. In order to obtain the necessary per- table 8 is far from complete. It does not in- mits, the firm will have to demonstrate its clude any tracts in Wyoming, for example, ability to comply with the regulations pro- because no large-scale projects have been mulgated under the Clean Air Act, the Clean proposed for that State. The only State- Water Act, the Resource Conservation and owned land shown is the tract leased for the Recovery Act, and other laws. Second, each Sand Wash project. Utah has additional land developer must have a transportation system that could be leased. Also, the federally to move the products and byproducts to mar- owned tracts shown total only about 160,000 kets. Third, a project must be economically acres—roughly 3 percent of the public’s oil feasible. That is, market conditions must ap- shale land in Colorado and Utah. pear favorable based on reliable cost estimates, contractor services and equipment In table 9, potential projects on these must be available at reasonable costs, com- tracts are combined in alternative ways to pliance with existing and future regulations reach the production targets of the scenarios. must be possible, and the permitting process The projects are assigned to four categories: must not unduly delay a facility’s construc- active projects, suspended projects, projects tion and operation. Finally, the developer needing additional Federal land, and projects must have land—either public, private, or a on other private tracts. Three alternatives combination of both. are shown for scenarios 1 and 2. The first alternative represents the completion and The interrelationship between the require- possible extension of presently active proj- ments for land, marketability, and a condu- ects. In the second, it is assumed that two cive regulatory environment can be illus- presently active projects are canceled, leav- trated by considering how some projects ing a production shortfall. This is eliminated Ch. 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints 59

Figure 10.—Some Present and Potential Oil Shale Development Sites in Colorado and Utah

\ \ \ I

/ ● Rangely

Green Rwer

UINTA BASIN I ( I \

)2 03 01

u - >HicoLoRADo LEGEND 1 Geokmetlcs (Geokmetlcs T/S) 10 EXXON (Love Ranch) 19 Cltles Serwce 2 NOSR 2 11 Multi Mineral (Integrated MIS) 20 ARCO 3 Texaco 12 Tract C-b (Cattredra/ Bluffs) 21 Occidental (Logan Wash) 4 Tosco (Sand Wash) 13 EXXON (WI//ow Creek) 22 Chevron 5 Tracts U-a & U-b (Wh/te Rwer) 14. Mobd ARCO Equity (Equrty T/S) 23 Umon 6 SOHIO Cleveland Cliffs 15 Chevron 24 Colony (Colony prolecf) 7 Mobil Equity 16. Texaco 25 Umon (Long Ridge) 8 Tract C-a (FfIo Blanco) 17 Getty 26 Mobil 9 Super$or(Super/or pro/ect) 18 SOHIO Cleveland Cliffs 27 NOSR 1 & 3

I ~ Ed~eoftheodshaledeposW., - Stream: ● Towns

SOURCE Office of Technology Assessment by the reactivation of presently suspended will respond to improved conditions before projects in response to substantial improve- the less advanced. However, it should be un- ments in the economic and regulatory cli- derstood that the industry patterns shown mate. In the third alternative, the shortfall is are in part arbitrary, and probably extreme eliminated by the commitment of additional in some cases. For example, the scenario 4 Federal land. Only two alternatives are alternatives require either new projects on shown for scenarios 3 and 4. The first incor- private land or new Federal tracts. In reality, porates the completion and extension of pres- an industry created under this scenario ent projects and the development of new proj- would more likely involve both types of land. ects on private land, in response to favorable Also, the combinations of projects shown are economic and regulatory conditions. The sec- only illustrative; they do-not represent the ond alternative assumes that less favorable recommendations of specific developers, conditions exist, but that Federal land is technologies, projects, sites, or policies. made available. In structuring the alternatives it has been postulated that the more advanced projects 60 ● An Assessment of Oil Shale Technologies

Table 8.–Some Potential Oil Shale Development Sites in Colorado and Utah

Announced Site Location Ownership Developer Project title Status production targetb 1 Utah State Geokinetics Geokinetics TIS Small-scale field tests underway of TIS method At least 2,000 bbl/d 2 Utah Federal a Navy/DOE NOSR 2 No development, None 3 Utah Private Texaco None No development, None 4 Utah State Tosco Sand Wash Baseline monitoring and mine planning 50,000 bbl/d underway, 5 Utah Federal c Phillips/Sundeco/ SOHIO White River Suspended pending resolution of land- 100,000 bbl/d (tracts U-a & U-b) ownership issue. 6 Utah Private SOHIO/Cleveland Cliffs None No development, None 7 Colorado Private Mobil/Equity None No development, None 8 Colorado Federal c Standard of lndiana/Gulf (tract C-a) Rio Blanco Preparing for MIS retort demonstration, 76,000 bbl/d 9 Colorado Private Superior Oil Superior Suspended pending approval of land exchange 11,500 bbl/d proposal. 10 Colorado Federal EXXON Love Ranch Proposal submitted for land exchange, 60,000 bbl/d 11 Colorado Federal Multi Mineral Integrated MIS Negotiations begun for use of USBM mine shaft ,50,000 bbl/d 12 Colorado Federal c Occidental/Tenneco (tract C-b) Cathedral Bluffs Preparing for MIS retort demonstration. 57,000 bbl/d 13 Colorado Federal EXXON WIIIOW Creek Proposal submitted for land exchange, None 14 Colorado Private Mobil/ARCO/Equity BX Small-scale field tests underway of Equity’s None TIS method, 15 Colorado Private Chevron None No development. None 16 Colorado Private Texaco None No development. None 17 Colorado Private Getty None No development. None 18 Colorado Private SOHIO/Cleveland Cliffs None No development, None 19 Colorado Private Cities Service None No development, None 20 Colorado Private ARCO None No development, None 21 Colorado Private Occidental Logan Wash Small-scale field tests of Oxy’s MIS technique. Few hundred bbl/d Results wiII support Cathedral Bluffs project. 22 Colorado Private Chevron None No development. None 23 Colorado Private Union None No development, None 24 Colorado Private Colony Development Colony Suspended because of economic and 46,000 bbl/d regulatory uncertainty, 25 Colorado Private Union Long Ridge Suspended because of economic and 75,000-150,000 regulatory uncertainty, bbl/d 26 Colorado Private Mobil None No development, None 27 Colorado Federal a Navy/DOE NOSR 1 & 3 Development management plan being prepared, None

‘Naval Oil Shale Reserve bBased on developers prehmlnary Plans cLeased under the Federal Prototype 011 Shale Leasing pro9ram SOURCE Ofhce of Technology Assessment

Constraints to Development The factors that will hinder or even pre- could be addressed by Federal action are vent reaching the production goals of the shown. OTA scenarios are shown in table 10. They Each potential constraint is important by were identified by analyzing the scenario re- itself, but the combined effect that more than quirements, given the present state of knowl- one might have on a scenario’s realization edge and the current regulatory structure. should also be considered. Thus, a moderate Constraints judged to be “moderate” will restriction on the availability of land together hamper, but not necessarily preclude, devel- with one on permitting could preclude inves- opment; those judged to be “critical” could tor participation. Similarly, an inadequate become major barriers. When it was incon- community water supply for the workers and clusive whether or to what extent certain fac- their families coupled with a moderate re- tors would impede development, they were striction on the availability of water for a called “possible” constraints. Only those that project could become a critical constraint. Ch 3–Constraints to Oil Shale Commercialization Policy Options to Address These Constraints ● 61

Table 9. –Some Production Alternatives for the Scenarios (barrels of shale oil per day)

Scenario 1 Scenario 2 Scenario 3 Scenario 4 alternatives alternates alternatives alternates Possible projects 1 -A 1 -B 1 -c 2-A 2-B 2-c 3-A 3-B 4-A 4-B Active projects RIO Blanco 76,000 — — 76,000 — — 76,000 I 50,000” 76,000 150,000’ Cathedral Bluffs 57,000 57,000 57,000 57,000 57,000 57,000 57,000 57,000 57,000 100,000 Sand Wash 50,000 — — 50,000 — — 50,000 50,000 50,000 Geokinetics 2,000 2,000 2,000 2,000 2,000 2,000 ) 17000 21,000 20,000 40,000 Equity BX — — — I — . } -} Suspended projects Union Long Ridge — 150,000 — 150,000 150,000 41,000 : 141,000 Colony ‘— } —‘} — 46,000 46,000 46,000 White River — — — — — — 100,000 100,000 Projects needing more Federal land Superior — 11,500 — 11,500 — 11,500 — 11,500 Multi Mineral — — — — 50,000 50,000 — 50,000 EXXON Love Ranch — — 60,000 60,000 60,000 EXXON WIIIOW Creek — 29,500 NOSR 1 — — — — — — 19,500 69,500 242,000 NOSR 2 — — New lease tracts — — — — — — — ‘} — — — — Other private tracts ...... — 501,000 – Total 185,000 100,000 100,000 200,000 200.000 200,000 400,000 400,000 1,000,0001,000,000

‘Possibly ln~ol,,ng open PII mlmng and of flracf hasfe d(sposal SOURLE Of’l~e of Techno ogy Assessmeof

Table 10.–Constraints to Implementing Four Production Targets

1990 production target, bbl/d 100,000 200,000 400,000 1 million Possible deterring factors Severity of Impediment Technological Technological readiness None None None Critical Economic and financial Availability of private capital None None None Moderate Marketability of the shale 011 Possible Possible Possible Possible Investor particlpation None Possible Possible Possible Institutional Availability of land None None Possible Critical Permitting procedures None None Possible Critical Major- pipeline capacity None None None Critical Design and construction services None None Moderate Critical Equipment availability None None Moderate Critical Environmental Compliance with environmental regulations. None None Possible Critical Water availability Availability of surplus surface water None None None Possible Adequacy of existing supply systems None None Critical Critical Socioeconomic Adequacy of community facilities and services None Moderate Moderate Critical

SOURCE Olflce of Technology Assessment 62 ● An Assessment of Oil Shale Technologies

Technological range (e.g., Wyoming Sweet sold in January of 1980 for a posted price of around $35/bbl). Technological readiness will not hinder the The “spot” or noncontract prices for these first three scenarios because the relatively crudes are considerably higher ($40 to $52/ slow pace of their development will allow nor- bbl). Industry sources and petroleum econo- mal scaleup practices to be followed. Sce- mists expect the world price of crude to con- nario 4 presents a different case. To achieve tinue advancing in the future. Consequently, its goals, the construction of almost all plants in a narrow economic sense shale oil appears will have to be started before 1984, which to have reached parity with conventional does not allow sufficient time either to under- crude. take much preliminary experimentation, or to gain experience by modular demonstration or The situation calls into question the need by the operation of pioneer facilities. In addi- for financial incentives for the oil shale in- tion, the necessity to standardize the plant dustry. This assumes, however, that market designs could have a number of unfortunate conditions continue to improve, and that insti- consequences. Among these could be that er- tutional barriers (e.g., regulations, permitting roneous equipment specifications and other requirements, and land availability) do not design flaws would be duplicated, and plant preclude development. Such could be the components would be unreliable and short- case if the developers responded to normal lived. Unanticipated environmental problems market pressures and opportunities. If, how- caused by the failure of pollution control sys- ever, high levels of production must be tems could delay the projects, increase their achieved within a relatively short time, then costs, and have severe ecological conse- Government support will probably be re- quences. Unreliability and less than optimum quired to reduce the remaining risks associ- performance could prevent some plants from ated with oil shale development. The most im- ever operating at their design capacity. portant of these risks are: ● Present capital and operating cost esti- Economic and Financial mates for oil shale plants could substantially underestimate actual costs. No For a project to be economically viable and commercial facility has ever been built, attract investors, it needs to have a favorable and most of the existing engineering de- combination of market conditions, of con- sign estimates are preliminary. Esti- struction and operating costs, and of re- mates for the costs of building plants sources such as land, water, and workers. have consistently increased much faster The necessary permits must also be readily than the rate of general inflation. obtainable. Tradeoffs are possible. Thus, if ● Uncertainties in the regulatory or per- adequate resources are available, and permitting process, or changes in the reg- mits obtainable without undue expenditure of ulations after a plant was built, could time and money, then somewhat less favor- jeopardize a project’s economics or even able market conditions might be acceptable. preclude its development. ● Future petroleum prices might not allow Until late in 1979, it was assumed that siz- shale oil to be profitably marketed once able subsidies would be needed to offset unfa- the plants were built. Since developers vorable market conditions. However, in Janu- do not know precisely what their produc- ary 1980, developers estimated that they tion or construction costs will be, the could profitably market shale oil syncrude at uncertainty of future prices for shale $35 to $40/bbl. * The present selling price for oil’s primary competitor is a crucial risk. similar high-quality crudes is within this Investor participation is not considered to *Whether shale oil requires subsidy for profitable marketing depends in part on the discount rate developers are assumed to be a problem for scenario 1, and the financial require in order to proceed. See table 12, community will be able to supply the neces- Ch 3–Constraints to 0il Shale Commerciailzation Policy Options to Address These Constraints ● 63

sary capital for scenarios 1, 2, and 3. The ting process, design problems could slip by financial requirements of scenario 4 will that would subsequently need to be cor- strain the Nation’s resources of investment rected, introducing additional delays; or, if capital only slightly or moderately. However, not caught, would result in environmental it is questionable whether investors would be damage. Regulatory changes during the de- willing to risk participating in scenarios 2, 3, velopment of the projects could mandate un- and 4 because of such factors as the uncer- anticipated, and possibly uneconomical, proc- tainties in world oil prices, the existence of ess modifications that could have more easily institutional barriers, and the doubtful future been made during the design phase. These of Government policies. “Possible” obstacles factors are likely to discourage some devel- are shown for these scenarios. opers in scenario 3; they would severely impede reaching the targets of scenario 4. Institutional Pipelines Land Under the first three scenarios, the exist- The availability of land is not expected to ing system of major pipelines should be ade- be a problem with scenarios 1 and 2 because quate to convey the shale oil to nearby mar- potential developers already have access to kets as well as to more distant ones in the sufficient private and public lands to achieve Rocky Mountain region. Only relatively small the relatively modest production goals. It pipeline spurs, plus some truck and rail could, however, cause some problems for sce- transport, will be needed to supplement the nario 3, particularly if multimineral recovery system. The system will not be adequate for or open pit mining were to be tested, It will be scenario 4, and new pipelines will be needed a critical obstacle for scenario 4. The produc- to provide access to markets in the Midwest, tion target (1 million bbl/d) will require about 15 to 20 plants each on a tract of approxi- Design and Construction Services mately 5,000 acres, or a smaller number of larger operations, probably including some Only about 20 architectural, engineering, open pit mines. It is doubtful that private and design firms in the United States have the holdings are either large enough or contain capacity to design and build an oil shale fa- enough rich oil shale to support this many cility. The projects that would be needed for projects by 1990. scenario 3 would require about 12 percent of their capacity; those in scenario 4 about 35 Permitting Procedures percent. If other industrial expansion competes for their services, the availability of As a production target increases in size, so these firms could delay the attainment of both will the number of permits that must be ob- scenarios. Contracting with foreign firms tained from the many different Government could be a short-term solution. In the longer agencies. If many projects are involved, these term, as domestic firms expanded and small- agencies are likely to be overwhelmed by the er companies merged, the necessary array of sheer number of applications that must be re- technical expertise would become available. viewed, revised, and approved, The evalua- If the projects were to be completed before tion process could become more lengthy and the 1990 deadline, however, these adjust- complicated, which would increase the risk of ments would have to take place in the early delays in project schedules. Financial losses 1980’s, which may not be possible. In any to the developers would be the outcome. Al- case, the demand for design and construction ternatively, if the agencies bypassed certain services would escalate project costs, espe- review steps in order to expedite the permit- cially in scenario 4. 64 ● An Assessment of 0il Shale Technologies

Equipment lowed. There are also Class I areas nearby, where the air quality must be kept virtually Scenario 3 will require between 6 and 12 unchanged. These could be affected by oil percent of the U.S. production of valves, com- shale operations. One of these, the Flat Tops pressors, heat exchangers, pressure vessels, Wilderness, is less than 40 miles from the and other industrial equipment. If there were edge of the Piceance basin, and about 95 shortages, scenario 4, which will need 15 to miles from the eastern edge of the Uinta 30 percent, could be severely hampered by basin. A preliminary regional modeling study project delays and cost escalations. Deficien- undertaken by the Environmental Protection cies in equipment supplies and design and Agency (EPA) has indicated that by carefully construction services could escalate project siting the plants in the Piceance basin, an in- costs by as much as 50 percent. * dustry of up to 400,000 bbl/d could probably be controlled to satisfy the PSD standards for Environmental Flat Tops. The standards might hinder scenario 3 if all the capacity were concentrated Although harm to the air, water, and land in the eastern Piceance basin, but this is would certainly increase as the industry ex- unlikely. It is more probable that some proj- panded, existing regulations for water quali- ects will be sited in the Uinta basin. Thus the ty, land use, and worker health and safety do scenario’s goal could probably be achieved. not appear, at present, to be obstacles under Under scenario 4, air quality deterioration any of the scenarios. This observation is would be sufficiently large that compliance based only on the results of laboratory tests, would not be possible because at least half of engineering design studies, and experience the capacity (500,000 bbl/d) would be located with small-scale plants. Therefore, it is not in the Piceance basin. possible to accurately evaluate large-scale operations with respect to the efficacies of Water Resources their control systems, the characteristics of their ultimate emissions streams, the conse- The availability of surplus surface water quences of the scaleup necessary to build for large-scale oil shale development depends them, and thus their effects on the environ- on the rate of regional growth holding to the ment. It is not known whether the industry medium levels anticipated by the States, and will be able to meet, in the future, permitting the long-term average flow of the Colorado standards and regulations for environmental River remaining at or very near the levels protection. that have obtained since 1930. If there are The same types of uncertainties also apply higher rates of regional growth, or if the to air quality. Recent studies, however, indi- river’s flows decrease by a few percent, pro- cate that even when the best available conduction could be limited to about 500,000 trol technologies are used, production capac- bbl/d unless water were diverted from other ity will be limited by the standards for pre- users. Shortages of surface water, which vention of significant deterioration (PSD). could hinder scenario 4, could be offset by de- These were promulgated under the Clean Air veloping ground water, by purchasing sur- Act, and specify the maximum allowable in- face water from other users, or by importing creases in the ambient concentrations of sul- water from other areas. However, these fur dioxide and particulate for any area. strategies could encounter institutional obstacles. For example, importation of water is The oil shale region has been designated as presently banned by Federal statutes, and a Class II area, i.e., some additional air pollu- ground water could be developed only if the tion and moderate industrial growth are al- rights of surface water users were protected.

*Such increases occurred in process plant construction dur- All of the scenarios will require additional ing the period from 1973 to 1975. See ch. 6. reservoirs to assure year-round water sup- Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints ● 65

plies. In many cases, these will be small and that presently planned facilities (such as the located at the plantsites. However, a large in- new town of Battlement Mesa) can be built, dustry will need new reservoirs if the proj- the region could accommodate up to 35,000 ects, and all other users, are to have ade- people between 1985 and 1990. (See table quate water supplies, The existing reservoirs 11. ) More could be incorporated if prepara- will not be adequate for scenarios 3 and 4, tions were begun at once. The established and new storage will have to be built in the communities could expand and new towns basins of the White River and the Colorado could be constructed, provided that financing River mainstem. Reservoir siting could be re- were available, regulatory actions could be stricted on some streams by their designation taken in a timely fashion, and the political as wild and scenic rivers, or by the presence and administrative atmosphere were favor- of rare and endangered species. able. However, if community and individual All of the scenarios will require diversion stress became too great and social institu- projects to carry water from the streams and tions faltered, not even the total of 35,000 reservoirs to the oil shale plants. Their con- residents could be absorbed without disrup- struction would also come under environmen- tion. tal laws. Although some social stress can be anticipated, the area should be able to deal with Socioeconomic the growth associated with scenario 1. Sce- nario 2 could probably be accommodated if Social and economic obstacles will arise if project construction were phased, and if the communities are unable to adapt to the some projects were developed in Utah. Se- growth caused by shale development, These vere problems would accompany the growth obstacles have two aspects, The first relates expected for scenario 3, and the growth for to the physical ability of the towns to provide scenario 4 would greatly exceed the capaci- adequate housing, facilities, and services. Table 11 .–Actual and Projected Population and Estimated The second involves the effects of local living Capacity of Oil Shale Communities in Colorado conditions on workers and other residents. Even when physical facilities are adequate, Population the way of life can be unpleasant. In some 1977 1980 1985-90 Western and Great Plains communities Location a censusb projected capacityd Garfield County where large and rapid growth has accompa- Rifle . 2,244 4,362 10,000 nied energy industry construction, living con- Silt : 859 1,211 2,800 ditions have become so intolerable that work- New Castle 543 831 1,000 Grand Valley. ~ ~ 377 589 3,000 ers and their families have simply left. The Battlement Mesae ~ — 198 2,500 consequences for the projects of this labor Other ~ ~ – – 1,700 turnover were construction delays, cost over- Subtotal f . ., 4,023 7,191 21,000 runs, and poor workmanship. Rio Blanco County Meeker 1,848 2,779 6,000 Communities in the oil shale region are pre- Rangely ... 1,871 2,223 6,000 paring for additional growth. In Colorado, for Other. . ——1,381 1,542 2,000— example, the State government, and the oil Subtotal 5,100 6,544 14,000 ——— shale counties and municipalities—with the Total ., ,.. 9,123 13,735 35,000 support and cooperation of industry—have aooes not IflCIUcle MeSa or Mot[at Counties both of which are more dtslanl from the area of devel- been preparing for increased development opment bAc[ua15 from a special U S census for nearly 10 years. Consequently, the region cEnd-of.the year projections by the Colorado West Area Counc[l of Governments dEsllma[ed b OTA from various plannlng and needs assessment documents assumes comple is awaiting expanded oil shale development, y Ilon of currently planned orojects (e g housing waler and sewer system expamlons s{reet and is prepared to absorb a moderate num- and road Improvements etc I ‘A new town Construction antupated 10 begtr (n the early 1980 s ber of new residents. Assuming there are no f/nC/udes only Ihe Immedla!e 011 shale vlClnlty breakdowns from boomtown stresses, and SOURCE Off Ice of Technology Assessment 66 . An Assessment of Oil Shale Technologies ties of the communities. Not only would the cal stress would be inevitable for scenario 4, existing towns have to double or triple in size, and there is little doubt that adverse living but several new ones would have to be estab- conditions would prevent the realization of its lished. Disruption from social and psychologi- production goal.

Policy Considerations

Some possible Federal policy responses to production units. Union, Colony, and Paraho the constraints that would inhibit or preclude have progressed through this sequence to the the expansion of the oil shale industry are semiworks scale of operation—about one- discussed in this section. Other issues and im- tenth of commercial module scale. Larger pacts that have not been identified as con- demonstration projects will be needed to ac- straints are dealt with in the subsequent curately determine the performance, reliabil- chapters and summarized in chapter 1. Some ity, and costs of processing technologies un- examples are the efficacies, over the long der commercial operating conditions. For term, of the proposed solid waste disposal Union and Paraho, the next step is a modular practices, and the consequences of de- demonstration facility that would incorporate creases in the flows of the Colorado River only one retort. Although costing several hun- system. dred million dollars, this facility would provide the necessary experience and the techni- Technology cal and economic data to decide whether to Accelerated research, development, and commit much larger sums to commercial demonstration would be needed to remove the plants. Rio Blanco and Cathedral Bluffs are technological barriers to scenario 4. The also following the modular demonstration following programs might be considered. path. Colony regards the pioneer commercial plant as more suitable for demonstrating the TOSCO II technology. R&D Policy Options As discussed in the section on economic Some of the remaining technical questions and financial policies, whether the Federal could be answered in small-scale R&D pro- Government plays an active role in fund- grams. These could be conducted by Govern- ing and operating the demonstration projects ment agencies or by the private sector, with will strongly influence the balance that is or without Federal participation. If Federal achieved between information generation involvement is desired, the R&D programs and dissemination, timing of development, could be implemented through the congres- and cost to the Treasury. There are four sional budgetary process by adjusting the ap- possible structures for demonstration pro- propriations for the Department of Energy grams. In all cases, the net cost of the pro- and other executive branch agencies, by program will depend on where the facilities are viding additional appropriations earmarked sited. If the site could be subsequently devel- for oil shale R&D, or by passing new legisla- oped for commercial production (e.g., a pri- tion specifically for R&D on oil shale technol- vate tract, a potential lease tract, or a can- ogies. didate for land exchange), the facility would have substantial resale value. Otherwise, it Demonstration Options would have only scrap value. In general, potential developers would A single module on a single site.—This op- prefer to follow conventional engineering tion would provide comprehensive informa- practice, and to approach commercialization tion about one process on one site. Either through a sequence of increasingly larger underground or surface mining experiments Ch 3–Constraints to 0il Shale Commercialization. POlicy Options to Address These Constraints ● 67 could be performed, but probably not both. amount of investment. Each project would re- The costs would be small overall but large on semble the several-module/single-site option; a per-barrel basis, because there would be no the collection would constitute a pioneer economies of scale. Some of the mined shale commercial-scale industry. could be wasted because the single retort might not be able to process all of it economically. Economic and Financial Several modules on a single site.—This Continuing uncertainties over eventual program might consist of an MIS operation plant costs, along with present regulatory coupled with a Union retort for the coarse deterrents, may mean that financial incen- portion of the mined oil shale and a TOSCO II tives will be needed. Government action to for the fine portion. As with the single-module allow easier access to public oil shale land, or option, either surface or underground mining to remove regulatory impediments, could re- could be tested, or possibly both if the plant duce this need. If, however, assuring the pro- had sufficient production capacity. The total duction for scenarios 3 or 4 by 1990 is a ma- costs would be larger than for the single-mod- jor objective, then financial incentives should ule program, but unit costs would be much be seriously considered. They would be par- lower. For example, a three-module demon- ticularly important in meeting the goals of stration plant would cost about twice as scenario 4, because the rapid deployment of a much as a single-module facility; a six-module large number of projects within 10 years is plant about four times as much. Different likely to create cost overruns and jeopardize technologies could be combined to maximize project economics. resource utilization, and detailed information could be obtained for each. However, all of Government Financial Support the information would be applicable to only one site. If many modules were tested, the Several types of Government financial sup- demonstration project would be equivalent to ports are discussed below. These are basical- a pioneer commercial plant, except that a ly of two kinds: incentives to private industry, true pioneer operation would probably not and direct Government ownership or partici- use such a wide variety of technologies. pation. Single modules on several sites.—Several Incentives to industry.—An effective in- technologies might be demonstrated, each at centive must avert one or more economic a separate location. For example, an under- risks. It should also be cost-effective: its cost ground mine could be combined with a to the Government should be low and its sub- TOSCO II retort on one site; a surface mine sidy effect high. It should promote, or at least with a Paraho retort at another. Total costs not impede, efficient investment and produc- would be large, as would unit costs, which tion decisions, and should encourage competi- would be comparable with those of the single- tion. It should facilitate access to capital. It module/single-site option. The principal ad- should entail small administrative and bu- vantage would be that different site charac- reaucratic costs. Finally, it should be phased teristics, mining methods, and processing out as market conditions improve and risks technologies could be studied in one program. are reduced. The following analysis assumes Several modules on several sites.—For that only temporary incentives will be re- each site, a combination of mining and proc- quired for the first generation of oil shale essing methods could be selected that would facilities. If this assumption proves incorrect, be appropriate for the site’s characteristics the implications of subsidizing the industry and the nature of its oil shale deposits. The should be reevaluated; permanent subsidies maximum amount of information would thus are a very different economic proposition be acquired in exchange for the maximum from temporary ones. ——— -. . ——.—

68 ● An Assessment of 011 Shale Technologies

OTA analyzed 10 possible economic incen- also important to note that the corporate, fi- tives. These differ with respect to the criteria nancial, technical, and fiscal circumstances described above and also with respect to of the potential developers will show consid- whether the Government provides the incen- erable differences. Consequently, it is un- tive before or after production begins. The likely that any single “best” incentive will be latter option is desirable because the Govern- revealed. However, some are clearly superior ment could phase in the subsidy disburse- to others from the viewpoints of both the Gov- ment. Production incentives (those applied ernment and developers. An optimal policy after production begins) limit the Govern- might be to provide a variety of incentives of ment’s financial exposure and risk. The use approximately equal dollar value, and to of production subsidies alone, however, may allow each company to choose the one that is encourage only large corporations with ex- most appropriate to its particular circum- ceptional debt capacity. stances. The implications of each of the incentives follow. * The net cost to the Government of a particular incentive can directly reflect the extent ● Construction grant. —The Government proof its subsidy effect, but the relationship is vides a direct grant to cover a prespecified not necessarily linear: some incentives defi- percentage of total construction costs. nitely provide more subsidy at a lower cost to the Treasury than others. (See table 12.) It is *Fu1l discussion is found inch. 6.

Table 12.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (12-percent rate of return on invested capital)

(15-percent rate of return on invested capital)

Change in Total expected cost Total expected expected profit Probability to Government Breakeven Incentive profit ($ million) ($ million) of loss ($ million) price ($/bbl) Construction grant (50%) $281 — $477 0.00 $494 $4060 Construction grant (33%) ., ~ ~ ~ ~ ~ 119 315 0.19 327 47,70 Low-Interest loan 81 277 0.23 453 5470 Production tax credit ($3) ~ ., ~ ~ -61 135 063 252 56.10 Price support ($55) ., ., ... -88 108 077 172 NA Increased depletion allowance (27%) ., ., -110 86 0.75 197 57.20 Increased Investment tax credit (20%) ., -131 65 0.77 87 58,80 Accelerated depreciation (5 years) ., ... – 127 69 0.76 79 5890 Purchase agreement ($55) ,.. -150 46 092 0 NA None ., ... ., ., ., ., ~ ~ ~ ., -196 0 093 0 61.70 aThe calcUlallonS assume a $3!j/bbl price for conventional premtum crude that escalates at a real rate of 3 percent per year Thus the predicted S48/bbl breakeven price fOr lhe 12-perCent discount rate ‘Will be reached 10 11 years or In the I[tth year of produchon Therelore tn narrow economic Ierms 011 shale plants starting construction now which assume a 12.percent discount rate WIII be profitable over the hle of the project wlthoul subsmy (See discussion for caveats concerning Ihls conclusion ) The calculations are for a 50,000 -bbl/d plant costing $1 7 blllton All monetary values are In 1979 dollars SOURCE Resource Plannlng Associates Inc Washington O C Ch 3–Constraints to Oil Shale Commercialization: Policy Options 10 Address These Constraints ● 69

(OTA analyzed both 50- and 33-percent sirable feature. * Its availability would also grants.) This incentive has a strong effect help developers obtain project financing. on project financing. It benefits all devel- Price supports would benefit all firms. opers, and does not distort investment or However, they might not be sufficient for production decisions. However, it would firms with limited debt capacity (i.e., firms impose large administrative burdens on that could not borrow the required capi- both the Government and industry. There tal), especially if they were considering would be no assurance that production costly commercial-size plants. The admin- would occur even with the grants. Large istrative burden would range from slight to initial lump-sum payments would be re- moderate. This subsidy is supported by a quired rather than phased-in treasury dis- variety of potential developers. Its char- bursements. The subsidy would probably acteristics make it attractive to both devel- be politically unpopular. opers and the Government. Production tax credit.—The developer is Purchase agreement.—A developer con- allowed a credit against corporate income tracts with the Government to sell shale oil taxes for each barrel of shale oil produced. at a specified price that is usually some- (A $3 credit per bbl of crude shale oil was what above the expected market price. analyzed. ) This incentive provides a strong (OTA’s analysis assumed a price of $55/bbl subsidy effect, and moderately shares in- in constant 1979 dollars. ) This incentive is vestment cost uncertainty. It imposes min- similar to a price support except that the imal administrative burdens. It only slight- developer must sell the oil to the Govern- ly improves project financing, however, ment; he does not have the option of selling and entails some distortion of product it in the open market. Purchase agreements price, It most strongly affects firms that increase profitability to a lesser extent have large tax liabilities, and its net cost to because the firm does not benefit if the the Government is high compared with market price is above the contract price. other possible incentives. It is widely sup- On the other hand, the Government shares ported by potential developers. in both the risks and the potential benefits of shale oil production. Consequently, the Price support.—A minimum price for shale average cost to the Government is some- oil is guaranteed for a long enough period what lower than with a price support. Pur- to allow developers to recover their capi- chase agreements limit the possibility of tal. (OTA analyzed a minimum price of $55/ loss, but also reduce the likelihood of large bbl of shale oil syncrude-the Government profits. They are less popular with indus- would pay the difference if the market try than are price supports. The adminis- price were lower.) This incentive has a trative costs are also higher than those of very strong effect on project economics. It price supports, but their severity can be removes most of the risk of price fluctua- controlled, to some extent, by the manner tions in foreign oil. On the other hand, it in which the subsidy is constructed. does not prevent shale oil from being sold in the private market if prices there are Low-interest loan. —The developer bor- higher than the supported price. With rows a specified percentage of capital present and projected world oil prices, it is costs from the Government at an interest very possible that no Government pur- rate below the prevailing market rate. chases would be necessary. In this case, (OTA’s analysis assumed 70-percent fi- the Government would gain income since the developers would pay taxes on their *As indicated in table 12, the net cost to the Government of providing such an incentive —even if developers chose to sell to production. This incentive limits the Gov- the Government-would be low relative to most other incen- ernment’s financial exposure—a highly de- tives, 70 . An Assessment of Oil Shale Technologies

nancing at 3 percentage points below the tive characteristics are discussed in market rate. ) This incentive requires the chapter 6. Government to share significantly in the risk of project failure, and it has a marked Direct Government Participation or Ownership effect on a developer’s ability to obtain financing, but it tends to distort input The Government could share the capital costs, and to bias investment decisions in and operating costs with industry, and there- favor of capital-intensive technologies. It by become a part owner of the project. The also imposes large administrative burdens. consequences would be similar to the con- This type of subsidy is usually designed to struction grant option, except that the Gov- provide the greatest benefits to firms with ernment would share all of the risks and ben- weak financial capability. In practice, efits. Almost without exception, potential de- however, it is difficult to deny loans to velopers believe that active Government par- strong firms. ticipation would increase managerial complexity and inefficiency. Administrative bur- ● Debt guarantees.—The Government dens would be very high. agrees to pay back a loan if the developer defaults. With this insurance, a firm can The Government could also contract for the usually obtain lower interest rates. Usual- construction of several modular plants it ly, only a fraction of the total loan is in- would then operate, either alone or through sured, and the borrower is required to pay contracts. It could thus conduct operations to a premium for the insurance. This incen- obtain accurate information on technical fea- tive only slightly subsidizes the investment, sibility, project economics, and the relative but it provides maximum sharing of the merits of different processes. This would be risk of project failure. It considerably of assistance in evaluating its future policies eases borrowing problems. Loan guaran- towards oil shale, in disseminating technical tees primarily benefit financially weak information, and in improving its understand- firms. They distort input cost, and they ing of the value of its oil shale resources. bias investment decisions toward capital- After enough information had been obtained, intensive technologies. They also impose a the facility could be scrapped or sold to a pri- significant administrative burden. Perhaps vate operator. This policy would provide the the most obvious drawback is the uncer- Government with information and experi- tain financial exposure of the Government. ence, but the cost would be much higher than The Government’s costs would be zero if no that of incentives to private developers. plants failed, but huge if even a few fail- Because industrial partners would insist ures occurred. The Government has had on some protection of proprietary informa- considerable experience with debt insur- tion, the Government would probably not be ance programs during the last 15 years, able to disseminate all project data as it and the fees paid by firms for the protec- chose. In addition, its experience in design- tion have, in sum, yielded it net income. If ing, financing, managing, and obtaining per- the participation of small- and medium- mits for an oil shale plant may not resemble sized firms is desired, then either debt that of private industry. Thus, the informa- guarantees or low-interest loans will prob- tion acquired may be of only limited use to ably be necessary. subsequent private developers. ● Investment tax credit (10 percent), accel- Most of the information secured through erated depreciation (5 years), and in- Government ownership could be made avail- creased depletion allowance.—None of able as a condition of granting private finan- these would be likely to have a major im- cial incentives. Furthermore, this kind of pact on oil shale development. Their incen- Government intervention is likely to discour- Ch 3–Constraints to 011 Shale Commercialization: Policy Options to Address These Constraints ● 71

age private developers from undertaking Additional Federal land would not be their own modular development and R&D pro- needed to achieve the goal of scenario 1, nor grams. Government programs of this kind to reach that of scenario 2 if economic condi- tend to reduce the benefits that a particular tions favored oil shale development. The goal firm could obtain from R&D or modular test- of scenario 3 could also be met without more ing. Finally, when patenting and licensing Federal land if regulatory and economic un- technologies, definite provision is made for certainties were sufficiently reduced to en- the dissemination of technical information on courage Tosco, Colony, Union, and Rio Blanco both gratis and fee terms to possible users of to continue their commercialization pro- the processes, grams. On the other hand, implementation of scenario 4 would require a highly favorable Institutional economic and regulatory climate (probably including Federal subsidies), or the use of ad- Use of Federal Land* ditional Federal land, or both. In any of the The Federal Government owns over 70 per- scenarios, more public land may be required cent of the oil shale lands and nearly 80 per- if large-scale multimineral recovery proc- cent of the best shale resources. Essentially esses or open pit mining are to be tested in the near future. all of thex large deposits of nahcolite and dawsonite in the Piceance basin are federally The land could be leased, exchanged for owned. No permanent leasing program exists private land, or developed by the Govern- for these lands, and the current Prototype Oil ment. All three options may be affected by the Shale Leasing Program is limited to no more fact that much of the best Federal oil shale than six tracts of 5,120 acres each. To date, land is subject to unpatented mining claims four tracts have been leased: Utah tracts U-a by private parties. The validity of some of and U-b (the White River project) and Col- these claims will be determined by the Su- orado tracts C-a (Rio Blanco) and C-b preme Court in 1980. If the Court’s ruling fa- (Cathedral Bluffs). The other two tracts were vors the claimants, much less Federal land proposed for Wyoming, but no bids were re- may be available for disposition. ceived when their leases were offered in 1974. Development is proceeding on the Col- Leasing.—Under the Mineral Leasing Act orado tracts, but the ones in Utah have been of 1920, the Department of the Interior (DOI) stalled by litigation between the State and the has the authority to lease public oil shale Federal Government. *** lands to private developers. The Act limits the number of leases to one per person or firm, and restricts the maximum size of a *On May 27, 1980 the Department of the Interior (DOI) an- 2 nounced several oil shale decisions. Up to four new tracts will single tract to 5,120 acres (8 mi ). Individuals be leased under the Prototype Program and preparations and firms are allowed to hold shares in sever- started for a permanent leasing program. At least one multimineral tract will be included in the renewed Prototype Pro- al leases, but the total area covered by these gram. Land exchanges will not be given special emphasis, and shares cannot exceed 5,120 acres. no decision will be made to settle mining claims until the Su- preme Court rules on Andrus v. Shell Oil (the oil shale mining Whether the acreage limitation will im- discovery standard case). [NOTE: This case was decided on pede development will depend on the location June 2, 1980. No. 78-1815.] The administration will propose to Congress legislation to give DOI the authority to grant leases of the tract and on the types of development bigger than the present statutory limitation of 5,120 acres, to technologies to be employed. It might pre- provide for off-lease disposal of shale and siting of facilities, clude large-scale operations in the thinner, and to allow the holding of a maximum of 4 leases nationwide and 2 per State. leaner deposits in Wyoming. However, a * *Nahcolite is a mineral containing sodium; dawsonite con- 5,120-acre tract in the relatively rich areas of tains aluminum. the Piceance and Uinta basins could easily ***On May 19, 1980, the U.S. Supreme Court reversed the lower court decisions and held that the Secretary of the Interi- support a commercial-scale operation over its or could reject Utah’s applications for oil shale lands as school economic lifetime. On the other hand, if a land indemnity selections (Andrus v. Utah, No. 78-1522). very large facility were desired, the acreage 72 . An Assessment of 01/ Shale Technologies limitation could impede efficient resource de- gram. Opportunities exist for leasing at least velopment, especially if surface mining were two additional tracts within the Prototype to be used. If the entire tract were suitable Program because of the two Wyoming leases for surface mining, the need to dispose of min- that were not purchased during the 1974 of- ing and processing wastes within the tract fering. No congressional action would be re- boundaries would reduce overall resource required to extend the Prototype Program, but covery, and might allow only relatively ineffi- its extension would constitute a major Feder- cient development. One solution would be to al action. Therefore, a supplementary envi- include in the tract an area (such as a dry ronmental impact statement (EIS) would be canyon) that contains no oil shale resources required. Its preparation could take from 1 to but that could be used for waste disposal. 2 years. This option would not require amending the Leasing Act, but it could complicate mining Nomination of the tracts and preparation operations and would reduce the value of the of leasing regulations could add several tract to the private sector. Another option months to a year to the front end of the sched- would be to allow disposal in similar areas ule. Unless the preliminary steps were expe- outside the tract boundaries, as was original- dited, the leases could probably not be sold ly proposed for tract C-a, but this would re- until about 1983. If the leases were similar to quire amending the Federal Land Policy and those for the existing Prototype tracts, a Management Act of 1976 (FLPMA). 2-year environmental monitoring program would be mandated before site development The argument in favor of limiting the num- could proceed. Thus, the first construction ber of leases per individual or firm is that it work could not begin until about 1985. If a prevents a small number of entrepreneurs commercial plant were built without a pre- from cornering the lease market. The argu- liminary demonstration phase, commercial ment against the restriction is that it prevents production could start in about 1990. With a a developer from acquiring experience and demonstration phase, commercial production technical information on one tract and then could not begin before 1992 or 1993. applying it to another while the first is still operating. The latter position is valid for The timespan could be reduced somewhat potential developers who do not have their by offering the tracts that were considered in own oil shale land, but not for those whose the mid-1970’s as replacements for the Wyo- privately owned tracts could be developed ming tracts. The nomination process was commercially if the company could acquire completed for these tracts, and work was be- the necessary expertise in the richer deposits gun on a supplemental EIS. They were origi- on public land. The options are to increase nally selected as sites for in situ operations, the number of leases allowed to two or three and to offer them now for this type of devel- per company or individual, regardless of the opment would be inconsistent with one of the locations of the tracts; or to allow one lease Program’s major goals, which was to test a per developer per State. The latter would variety of processing technologies. (Both of allow a developer to obtain experience with the active Prototype tracts are being devel- the richer oil shales in Colorado, for example, oped by in situ techniques. ) If they were also which could then be applied in Utah or Wyo- suitable for aboveground processing, their ming. Potential developers prefer the first op- use in the program extension would shorten tion because the shales in Utah and Wyoming the commercialization schedule by about a are much poorer than those in Colorado. Both year. options would require amending the Mineral Leasing Act. The other leasing option would be a new, permanent leasing program that would be in- If additional leasing is desired, it could be dependent of the Prototype Program and carried out either in a new, permanent leas- therefore not restricted by its six-tract limit. ing program, or as part of the Prototype Pro- Implementing this option would take longer Ch 3–Constraints to 0il Shale Commercialization Policy Options to Address These Constraints ● 73 than extending the Prototype Program, be- Both options are allowed by FLPMA. Under cause of the need to prepare new leasing reg- FLPMA, the Government may exchange pub- ulations and an entirely new EIS. No congres- lic land for private land, provided that the ex- sional action would be required, unless the change is in the public interest and that the program were to be coupled with an incen- properties involved are within 25 percent of tives package or with amendments to the Min- equal value. The difference can be made up eral Leasing Act. with cash. The major problem with exchanges under FLPMA is that the procedures The adoption of a new leasing program are time-consuming, complex, and costly. Sev- would imply the abandonment of another ob- eral Federal agencies must be involved in jective of the Prototype Program, namely to estimating the relative values of the tracts in obtain the technical, economic, and environ- question and in determining whether the ex- mental information needed to design a permanent leasing program. For a variety of rea- change is in the public interest. An EIS may sons, the Prototype Program has not yet pro- be needed; its preparation could take as long vided this information. (See vol. II. ) Its aban- as 2 years. The overall process, including review, evaluation, and approval by the agen- donment would engender political opposition from the individuals and groups that criticize cies plus a period for public comment, can oil shale development, especially where pub- take even more time. lic land is involved. There are several ways to improve the ex- Land exchange. —Private interests own change process. One would be to streamline several million acres of oil shale land. Of the the review procedures, perhaps by setting up approximately 400,000 acres of privately a task force within DOI to deal with exchange proposals involving oil shale lands. Another owned land in Colorado, at least 170,000 acres contain beds that are at least 10 ft deep option would be for DOI to nominate Federal with a potential yield of 25 gal/ton, It has tracts, to characterize their environments, been estimated that the total potential oil and to evaluate their resources, even if no ex- yield from these richer tracts is at least 80 change proposals had been received from pri- billion bbl. However, much of the privately vate parties. With this advance preparation, held land is located on the fringes of the oil the exchange process would be shortened, shale basins, and contains thinner, leaner de- and the Government would be able to control posits than does the adjacent Federal land, the location of the future oil shale plants. Furthermore, many of the private tracts are Both options would be costly and would en- in small, noncontiguous parcels (mainly for- large the bureaucracy. Additional appropria- mer homesteads and small mining claims) tions, and possibly authorizing legislation, that cannot be economically developed. Pri- would have to be provided by Congress. vate oil shale development would be encour- A third option would be to exchange pri- aged if these lands were exchanged for more vate land for Federal land that is adjacent to economically attractive Federal tracts. State-owned tracts. The mix of private and State land could then be developed under a There are essentially two land exchange State-controlled leasing program. This option options. The first involves “blocking up’ scat- would be most applicable to the Uinta basin, tered or oddly shaped private tracts by ex- where the State’s extensive holdings are in- changing some of them for adjacent Federal termingled with Federal and private tracts. lands. (Superior Oil Co. proposed such an exchange for its tract near the northern edge of Government development.—The Govern- the Piceance basin. ) The second option in- ment could also develop its own oil shale volves the exchange of large privately owned lands. Two likely tracts are the 40,000-acre parcels for equivalent Federal tracts, per- Naval Oil Shale Reserve I (NOSR 1) in Colora- haps in an area that is more suitable for a do and the 90,000-acre NOSR 2 in Utah. (The specific development method. resources on NOSR 2 are of much poorer 74 . An Assessment of 0il Shale Technologies quality.) These sites could be developed across Federal land and eminent domain either with a Government-owned corporation, rights to private land, as well as extensive or through a cost-sharing arrangement with regulatory actions and EISs. Congressional industry. The advantages and disadvantages action might be needed to facilitate such a of different types of Government participa- project. tion are discussed in the section on economic and financial policies. Design and Construction Services and Equipment Permitting Procedures To achieve the goals of scenario 4, Federal Developers view the costs and potential assistance might be needed to deal with scar- risks of the present regulatory process as one cities of heavy equipment and limited design of two primary impediments to development. and construction services. The following pol- Reaching the production goals of scenarios 1 icies might be developed: and 2 will probably not require expediting the ● permitting process, but it will be needed to Training programs could be set up for meet the goals of scenario 3, and is even more construction workers to provide a skilled important for scenario 4. One or more of the work force when construction begins. following actions could speed up the process: ● Equipment with long delivery times require regulatory agencies to make deci- could be identified and supplies in- sions in a specified period of time; “grand- creased by either expanding existing ca- father” projects under development to make pacity, stimulating additional capacity, new laws and regulations inapplicable to or encouraging early orders. them; create an energy board or authority ● Tariffs and quotas on imported equip- with the power to overrule Federal regula- ment could be reduced or eliminated. tory decisions; or limit litigation as was done ● Federally sponsored R&D programs with the Alaskan oil pipeline. The first two could address the technical questions of options are likely to be a part of the powers of scaling up to commercial-sized facilities. the Energy Mobilization Board. ● Developers, local governmental units, related industries, concerned interest Another possibility would be for regulatory groups, and appropriate Federal agen- agencies themselves to take the lead in simpli- cies could be encouraged to coordinate fying their own permitting procedures. This their efforts. This would help avoid con- could be done by the imposition of internal struction delays, time limits on the period of review, and could ● Standardization of plant designs could be combined with an arrangement whereby be used to reduce complexity and simpli- developers applied for a package of related fy construction. permits. This would consolidate the number of permits required, and eliminate some of the existing permit duplication. EPA Region Environmental VIII appears to be adopting these procedures, although it is not clear whether and to what Air Quality extent they will actually expedite the permit- The PSD standards promulgated under the ting process. Clean Air Act could hinder scenario 3 and will, with current “best available control Pipelines technologies, ” prevent achieving scenario 4. Policy options for addressing these obstacles A major pipeline would have to be built to include: ship most of the l-million-bbl/d target of scenario 4 because existing pipelines to Wyo- ● Coordinate the issuance of PSD permits.— ming and Midwestern refineries are inade- This option would not alter the PSD regula- quate. Its construction could require access tions nor relax air quality standards, but Ch. 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints ● 75

would change the methods for issuing the the developers from maintaining the visi- PSD permits that are needed before con- bility and air quality of nearby Class I struction of the plants can begin. Rather areas. This would remove both the major than issuing the permits on a first-come uncertainties surrounding the siting of fa- first-served basis, EPA would encourage cilities within the resource region itself all prospective developers to coordinate and any siting barriers connected with the their development plans before applying degradation of the Class I areas. Such an for their permits. The goal would be a sit- option should allow achievement of the sce- ing pattern that maximized production nario 4 production goal at the cost of in- while complying with air quality stand- creased air pollution in the oil shale and ards. This might relieve some of the siting nearby regions. difficulties envisioned for the Piceance basin as a result of its proximity to the Flat Environmental R&D Tops Wilderness area. The implementation of this type of option, however, could be The public and private sectors have car- complicated by factors such as antitrust ried out extensive work on the environmental laws. impacts of oil shale development and on pollu- ● Redesignate the oil shale region from tion control technologies to reduce these im- Class 11 to Class III.—This option would be pacts. Yet many questions remain about the initiated at the State level, with a require- effects that a commercial-size industry would ment for final approval from EPA. The cri- have both on the physical environment and on teria that would have to be satisfied in- worker health and safety. It is essential, clude: therefore, that R&D keep pace with the indus- —the Governors of Colorado, Utah, or try’s development. The information generated Wyoming must specifically approve the would also assist regulatory agencies to de- redesignation after consultation with velop emission and effluent standards for the legislators, and with final approval of industry. local government units representing a Options at the Federal level for improving majority of the residents of the area to technical information include improved coor- be redesignated, and dination of R&D among executive branch —the redesignation must not lead to pollu- agencies, increased appropriations for oil tion in excess of allowable increments in shale R&D, the use of existing national com- any other areas. missions (e.g., the National Commission on This option would allow greater degrada- Air Quality) and the passage of legislation tion of air quality, but would permit more specifically directed to R&D on the environ- industrial development. While it would ap- mental impacts of oil shale technologies. (En- pear that with such an option there could vironmental R&D needs are discussed in ch. 8 be about twice as much oil shale develop- and summarized in ch. I.) ment as presently possible, there would still be limitations owing to nearby Class I Water Resources areas. With this option it is expected that the production target of scenario 3 could Policy options for removing obstacles asso- be achieved, but not that of scenario 4. ciated with water resources are discussed ● Amend the Clean Air Act.—This congres- below. sional option would exempt the oil shale region from compliance with certain provi- Financing and Building New Reservoirs sions of the Act. Under this option Con- gress might direct EPA and the States to Major new reservoirs will be needed for redesignate the oil shale region from a scenarios 3 and 4 to ensure that the water Class 11 to a Class III area, and to exempt needs of oil shale developers as well as all —.——————

76 . An Assessment of 01/ Shale Technologies

other users can be satisfied. They could be fi- Wilderness Act. Potential problems could be nanced and built by the Federal Government, reduced by the following mechanisms. by State organizations, or by the developers. The options for Federal involvement are dis- ● Identifying endangered or threatened spe- cussed below. (Those for the States and the cies.—Two federally designated rare and developers are discussed inch. 9.) endangered fish species, the humpback chub and the Colorado River squawfish, Congress could provide for the construc- have already been found in the waters of tion and financing of new water projects the oil shale region, and additional species through two mechanisms. First, funds could requiring protection may be found during be appropriated for a projector projects that future studies. The Endangered Species have already been authorized. Several have Act may be interpreted as restricting activ- already been evaluated by the Water and ities that might affect the critical habitats Power Resources Service (WPRS), * and their of such species, although no critical habi- construction approved. Actual construction tat has been declared for the squawfish or cannot not be started until they are funded. humpback chub. Knowing the approximate However, not all of these projects have been location of the critical habitats of endan- evaluated for their suitability to supply water gered species would be helpful if it were for oil shale development, and some projects decided to establish an oil shale industry may not be optimally located to serve oil shale because the timely siting of reservoirs and plants. A second option would be to pass leg- direct flow diversions could be affected by islation that would specify both the construc- agency interpretations involving instream tion and funding of new, but not previously flows. Should construction of these facili- authorized, Federal water projects. Unless ties begin before the critical areas were language were included to expedite construc- identified, there could be opposition to tion, these projects would require a long re- their completion, and water supplies from view process. They could, however, be de- a particular reach of a river could be designed and sited as water sources for oil layed or interrupted. If the locations of all shale (as well as other possible uses). An ex- designated critical habitats were identified ample would be constructing irrigation reser- by DOI and the required biological opinions voirs with additional capacity for oil shale re- obtained, the facilities could be sited to quirements. minimize interference and delay. Under either option, DOI, through WPRS, Alternatively, Congress could designate could operate these reservoirs in accordance such reservoirs to be in the national inter- with State water law. Their costs could be re- est, and could allow their construction in covered over the operating life of the facil- spite of the effect this might have on endan- ities from revenues generated by selling wa- gered species. ter to oil shale developers and other users, in accordance with authorizing legislation. ● Designating wild and scenic rivers and wilderness areas.—To date, no rivers in The Siting of Reservoirs and Direct the oil shale region have been designated for inclusion in the Wild and Scenic Rivers Flow Diversions System; however, several within the basins The construction of new reservoirs and di- of the Colorado River mainstem are being rect flow diversions (e.g., pipelines) might be considered, Diversions of water from spe- hampered, delayed, or even disallowed under cific stream reaches could be affected if provisions of the Endangered Species Act, the they are set aside. An early designation of National Wild and Scenic Rivers Act, and the the eligible rivers would assist in the planning for future shale oil production. Given this information, direct flow diversions *Formerly the U.S. Bureau of Reclamation (USBR). could be sited downstream from the por- Ch 3–Constraints to 0il Shale Commercialization, Policy Options to Address These Constraints ● 77

tions designated as wild or scenic. This the use of their water for this purpose. The would avoid a direct conflict within a given objective of this action would be to overcome river stretch but could add to the water any administrative reluctance to permit the supply costs. (Supply costs are discussed in use of water for oil shale development under detail inch. 9.) an authorization that did not specifically To date, four areas in the basins of the mention oil shale, White River and the Colorado River main- The power of Congress over reserved wa- stem have been designated under the Wil- ters is more limited than its power over derness Act. Other areas are being consid- waters in congressionally funded projects. ered pursuant to the Roadless Area Review Water rights covered by the reserved right and Evaluation II (RARE II) program. * New doctrine must be used “in furtherance of the reservoirs would not be permitted in the purpose of the reservation. ” For this reason, designated areas. A complete listing of wil- Federal water rights do not seem to be likely derness areas that might be considered in sources for oil shale development, except the near future would allow potential de- perhaps in the case of lands set aside for the velopers to locate their water storage facil- Naval Oil Shale Reserves. This question, how- ities elsewhere. Alternatively, Congress ever, is in the early stages of litigation. could specifically exclude rivers and/or new areas in the oil shale region from designation as wild and scenic rivers or wil- Interbasin Diversion derness areas. Interbasin diversion is a technically feasible although costly option for bringing addi- Federal Sources of Water for tional water to the oil shale region, There are Oil Shale Development also serious political obstacles to this alternative. The Reclamation Safety of Dams Act of Congress, under its constitutional powers, 1978, amending the Colorado River Basin could make water available from Federal wa- Project Act, prohibits the Secretary of the In- ter projects, or potentially from the reserved terior from studying the importation of water rights doctrine. (See ch, 9.) If Congress de- into the Colorado River Basin until 1988. If it cides that water from congressionally funded were decided to pursue this option as a projects should be made available for oil means of supplying water to an oil shale in- shale development, then any legislation dustry coming online in 1990, this prohibition enacted should provide that the term “indus- would have to be lifted. trial use or purpose” includes the use of water for oil shale development,** Congress Interbasin transfers could be used to re- could also amend the authorizing legislation lieve the water problems of the oil shale re- for those projects from which water for oil gion in several ways, Water could be trans- shale development might be sought, to permit ferred directly to the oil shale region, either exclusively for oil shale development or for *“1’he Forest Service, in its RARE 11 progr~m, is evaluating all users. Alternatively, the water needs of over 66 million acres of land to determine their suitability for Colorado’s eastern slope cities, presently designation as wilderness, During the period of initial evalua- being supplied in part from the Upper Col- tion, and up to final recommendation by Congress, these lands orado River Basin, could be met from other will be in some form of restrictive management. **A Memorandum of Understanding ex ists between DOI and hydrologic basins. The water presently being the State of Colorado with respect to the use of water from ex- exported from the Upper Basin then could be isting or authorized U.S. Bureau of Reclamation (now WPRS) used for oil shale development. In a third ap- projects, The State desires thfit the water not be changed from agricultural, municipal, or light industrial uses to energy pro- plication of interbasin transfers, all or a por- duct ion (including oil shale] that are inconsistent with State pol- tion of the 750,000 acre-ft/yr presently being icies. Under this memorandum, the State WT ill review any applications to redistribute water from conventional uses to energy supplied to Mexico by the Upper Basin States production. The memorandum could be superseded bV direct under the Mexican Water Treaty of 1944-45, congressional directives of overriding national importance. could be taken from another hydrological 78 ● An Assessment of Oil Shale Technologies basin (perhaps the Mississippi basin). The procedures in securing a water supply, and water thus freed in the Upper Basin could be provide that the established State appropria- assigned in part to oil shale development tion system has the same authority to grant, (750,000 acre-ft/yr would be sufficient for a deny, or place conditions on a water right and 3-million- to 7.5-million-bbl/d shale oil in- permit as would prevail in the absence of the dustry). legislation. The Allocation of Water Resources If Congress were to attempt to remove the water supply for oil shale production from If Congress were to pass legislation encour- the control of the State, strong legal and aging the development of an oil shale indus- political resistance would ensue. Such resist- try, it might wish to address the issue of how ance could delay oil shale development. the necessary water would be supplied and how oil shale legislation might affect water allocation. Socioeconomic Water in the oil shale region is presently The social and economic effects of oil shale distributed by a complex framework of inter- development are not unique to the resource state and interregional compacts, State and being produced or to the technologies in- Federal laws, Supreme Court decisions, an involved. Rather, they derive from an influx of ternational treaty, and administrative deci- people, regardless of the cause. In this re- sions. Within the Western States, water spect, they are similar to the effects of rights are apportioned by the States to com- growth in other energy industries, such as peting users according to a doctrine of prior coal or oil and gas. Before looking at specific appropriation under which water rights are a policy options for the effects of oil shale de- form of property separate from the land. velopment, the perspective from which they Oil shale developers presently hold exten- are viewed and the role of the Federal Gov- sive, but largely junior (i.e., low priority) sur- ernment in impact mitigation must be con- face water rights. Therefore, if water short- sidered. ages were to occur, existing developer supplies could be interrupted. More reliable sup- Congress can view socioeconomic impacts plies may be provided through development from one of three policy perspectives: of ground water not tributary to the surface, ● As part of the consequences of all kinds purchase of the consumptive portion of irriga- of energy development.—In recent ses- tion rights during the irrigation season, pur- sions, Congress has considered bills that chase of surplus water from Federal reser- would provide assistance to communi- voirs, or importation of water from more dis- ties faced with problems from the tant hydrological basins. (The last two op- growth of many different energy indus- tions have been discussed above). A discus- tries, and programs for oil shale could be sion of the amount of water needed for oil included in such legislation. shale development is presented in detail in ● chapter 9. As an aspect of specific energy initiatives.— Proposed amendments to the If control over the water supply for oil Powerplant and Industrial Fuel Use Act shale is to be left to the States, then Congress of 1978 are illustrative of this more lim- should probably so specify that decision in oil ited approach. These amendments are shale legislation to avoid any question of the directed to the adverse effects of major preemption of State water laws. Legislation energy developments, which could in- that would confirm preservation to the States clude oil shale. They authorize grants, of the same power over water for oil shale as loans, loan guarantees, and payments of they have over other water supplies should interest on loans; and propose an expe- require the developer to comply with State diting process for present Federal pro- Ch 3–Constraints to Oil Shale Commercialization: Policy Options to Address These Constraints ● 79

grams as well as an interagency council ● efforts to improve the delivery of Fed- to coordinate Federal impact assistance. eral programs should continue; ● As the result of oil shale development ● State appropriations from funds desig- alone. —In this case, specific language nated to assist the oil shale communities dealing with socioeconomic effects could will be necessary; and be included in bills providing for the de- ● support services, such as technical as- velopment of oil shale resources. sistance to the local governments, should The ways in which Congress deals with the not be reduced. impacts will depend on which perspective is Increased Federal participation will be adopted. needed if the region is to accommodate the Policy decisions must also consider the role growth anticipated under scenarios 3 and 4. of the Federal Government in impact mitiga- Several kinds of support could be given. One tion. Assistance in coping with the conse- option would be to provide additional financ- quences of growth is not expected in the usu- ing for expanding the communities and for al course of economic development. Recently, planning and establishing new ones. Another domestic energy development has become an would be to create Federal programs to solve exception when the distinction has been problems for which local groups have neither drawn between effects that can be handled the time nor the resources. For instance, dif- by local communities—i.e., those that can be ficulties may arise from inequities in the dis- considered a normal adjunct of development, tribution of revenues among States. These and those that cannot be readily solved with could be evaluated, and Federal actions local resources—boomtown problems. The taken for their correction. Such problems will extent and nature of Federal involvement in occur if the workers for Utah developments impact mitigation is highly controversial. On choose to live in Colorado; Utah will gain tax the one side, it is argued that social and revenues from the plants but Colorado will have to pay for the consequences of in- economic difficulties are State and local problems that should be viewed as the inevi- creased growth in its rural areas. Yet table consequences of industrial growth, and another option would be to expand Federal thus the Federal Government need not be in- R&D efforts. As an example, it would be valu- volved with their amelioration. On the other able to have estimates of the maximum rate side, the position is taken that national energy at which the communities could grow without requirements are the root causes of impacts, experiencing severe disruption. These esti- therefore a Federal role is appropriate. Sev- mates could be used by policymakers to ad- eral Western States propose that for reasons just the timing and location of additional Fed- of equity, the national goal of accelerated eral oil shale leases to take into account so- domestic energy production requires direct cioeconomic impacts. Federal participation in alleviating negative Which of the options would be best will de- impacts. This question about the Federal role pend on the success of local preparations and must be faced before decisions can be made on the nature and timing of new development. about appropriate Federal actions for dealing If the industry grows slowly, Federal partic- with the impacts of oil shale development. ipation might be limited to R&D and other supporting activities. If it expands rapidly, sub- No new Federal initiatives appear to be stantial direct financial support and active needed for scenarios 1 and 2, as long as the growth management efforts will be needed. existing mechanisms are effective. Several For example, a coordinated strategy will be requirements must be met, however: required to cope with the growth that would ● both Federal and State actions must sup- accompany the production of 1 million bbl/d, port already established growth man- as envisioned by scenario 4; and the respon- agement processes; sibilities would have to be shared by Federal, 80 An Assessment of Oil Shale Technologies

State, regional, and local governmental units be financed. This will involve private parties as well as by all private sectors. Extensive like lending institutions, and possibly the oil Federal participation would be unavoidable. shale developers. But where private capital is One option would be to create a new Federal insufficient, the Federal or State govern- regional authority, for the impacts will ex- ments will have to step in. Housing is only one tend into Utah and Wyoming. The powers sector where the needs can be expected to granted to such an authority would depend on outstrip the resources, and where combined the degree of coordination and cooperation efforts to meet them will be essential. Many between the public and private sectors, and agencies, operating in many areas and at all on the severity of the negative impacts. For levels, would have to be involved to cope with instance, construction of new homes, apart- the growth that would accompany the estab- ments, and other living facilities will have to lishment of a l-million-bbl/d industry by 1990.

Scenario Evaluation

As has been shown for the four scenarios, ● To minimize Federal promotion.—The different development strategies entail sub- 100,000-bbl/d target is rated highest be- stantially different requirements, conse- cause it could be achieved by completing quences, and Federal actions. Regardless of the presently active projects. The 200,000- the strategy selected, tradeoffs among objec- bbl/d goal probably would require some in- tives and requirements are inevitable. This is centives, and the 400,000-bbl/d” one would indicated in figure 11, where the scenarios require incentives, a small land exchange, are rated according to the relative degrees to and the short-term leasing of a Federal which they are expected to attain the objec- R&D facility in Colorado for a demonstra- tives for development. The following summa- tion project. The l-million-bbl/d target rizes how the attainment of each objective would require much stronger subsidies, ad- varies with the production goals. ditional leasing of public land for a longer To position the industry for rapid deploy- period, permitting modifications, vari- ment.—The 400,000-bbl/d industry is given ances, and extensive Federal involvement the highest rating because a wide variety in growth management. of technologies and sites would be evaluated and substantial technical, environmental, and economic information would ● To maximize ultimate environmental infor- be obtained; all of which would place the mation and protection.—The quantity of industry in a good position for rapid scale- pollutants and wastes generated will increase in proportion to the rate of produc- up. The l-million-bbl/d goal is rated next tion. Establishing a l-million-bbl/d industry since production at this level would consti- in 10 years would cause the most disturb- tute a major industry; further rapid deploy- ance per unit of production because there ment could then follow. It is rated lower would not be enough time to improve the than the 400,000-bbl/d” scenario because its control technologies. The 100,000-bbl/d in- accelerated construction schedule would dustry is also given a low rating because preclude valuable precommercial experi- the limited number of technologies tested ments and would probably not result in the would provide neither extensive informa- most technically efficient plants. The other tion on impacts nor guidance for the im- goals are rated lower because fewer proc- provement of controls and regulations. The esses could be evaluated. 400,000-bbl/d target would meet the needs To maximize energy supplies.—The bene- for information and testing of control tech- fits, and thus the ratings, are proportional nologies but would incur a greater environ- to the production rate. mental risk per unit of production than Ch 3–Constraints to 011 Shale Commercialization Policy Options to Address These Constraints ● 81

Figure 11 .—The Relative Degree to Which the Production Targets Would Attain the Objectives for Development

1990 production target, bbl/d 100,000 200,000 400,000 1 million 1 I To position the industry for rapid deployment I I I To maximize energy supplies

To minimize federal promotion

I To maximize environmental information and I protection I To maximize the integrity of the social environment To achieve an efficient and cost-effective energy supply system

Lowest degree of attainment I I _ Highest degree of attainment

SOURCE Off Ice of Technology Assessment

200,000 bbl/d. The latter would maximize ● To achieve an efficient and cost-effective the attainment of this objective. energy supply system.—The 400,000-bbl/d target has the highest rating because, ● To maximize the integrity of the social en- among other factors, it would provide a vironment. —The 100,000-bbl/d target is balance of information generation and rated high because this level of growth process development and demonstration. should be within the physical capacities of The 100,000- and 200,000-bbl/d targets are the communities. The 200,000-bbl/d” goal rated lower because only a few technol- would create some strain in the ability of ogies and sites would be tested. The l-mil- the towns to absorb the number of ex- lion-bbl/d industry is also rated low be- pected new residents; the degree of stress cause its deployment strategy would poorly would depend on the location of the devel- utilize many of the elements of production. opment. Adjusting to the growth associated Furthermore, the plants might not generate with a 400,000 -bbl/d industry would be sufficient profit capital for subsequent ex- possible if the plantsites were dispersed in pansion. Utah and Colorado, if plant construction An illustration of the need for tradeoffs be- were phased, and if preparations for the tween objectives can be seen at the l-million- construction of new towns were started at bbl/d level. This choice has high attainment of once; but there would be a high probability the positioning and energy production objec- that boomtown effects would accompany tives (e.g., it would displace about 16 percent this level of growth. A l-million-bbl/d indus- of the imported oil and reduce the balance of try would require coordinated growth man- payments significantly). However, reaching agement strategies and extensive financial the target requires tradeoffs in all the other outlays. Severe social disruption could be areas. (For example, it would violate the anticipated. Clean Air Act.) — ——

CHAPTER 4 Background Contents

Page Page Introduction ...... 85 Status of U.S. Oil Shale Projects ...... 113 The Need for a New Energy Supply System. , . 85 The Purpose and Organization of This Chapter 86 Chapter 4 References...... 114 Oil Shale Resources ...... 87 The Genesis of Oil Shale...... 87 List of Tables Worldwide Deposits ...... 87 Table No. Page Deposits in the United States ...... 88 13. Potential Shale Oil in Place in the Oil Description of the Oil Shale Resource Region. 93 Shale Deposits of theUnited States . . . . . 89 Location ...... 93 14 Potential Shale Oil in Place in the Green Topography and Geology...... 93 River Formation: Colorado, Utah, and Climate and Meteorology...... 99 Wyoming ...... 91 Plants and Animals. ... , ...... 100 15 Potential Shale Oil Resources of the Air and Water Quality and Economic Base. .. 103 Green River Formation ...... 92 16. Composition and Pyrolysis Products of Oil Shale Products and Their Potential Typical Colorado Oil Shale ...... 106 Applications ...... 105 17. Status of MajorU.S. Oil Shale Projects. . 114 The Nature of Oil Shale ...... 105 Kerogen Pyrolysis...... 105 List of Figures Associated Minerals...... 107 The History of Oil ShaleDevelopment...... 108 Figure No, Page Scotland ...... ,108 12. Oil Shale Deposits of the United States. . 89 Sweden ...... ,..108 13. Oil Shale Deposits of the Green River France ...... ,...... 109 Formation ...... 90 Spain ...... 109 14. The Oil Shale Resource Region of the Germany ...... 109 Green River Formation: Colorado, Utah, South Africa ..,...... 109 and Wyoming...... 94 Australia. .,...... 109 15. Major Mountain Systems in the Vicinity United States, ...... ,.110 of the Green River Formation ...... 95 16. Topographic Relief of the piceance Status of Foreign Oil Shale Industries ...... 111 Basin, Colo,...... 96 Morocco ...... 111 17. Stratigraphy and Landform Units Along Soviet Union ...... 111 Parachute Creek,Piceance Basin, Colo. . 97 People’s Republic of China...... ,..,.....112 18. Idealized Cross Section of the Piceance Brazil. ...,...... 112 Basin, Colo...... 98 CHAPTER 4 Background

Introduction

The United States has obtained energy for hydroelectric dams, nuclear powerplants, human comfort, security, and productivity geothermal sources, biomass, and other ener- from a variety of sources over the past 200 gy resources. Wood, once the principal ener- years. The availability of energy was instru- gy source for the Nation, was used largely by mental in its transformation from a largely some lumber mills and wood-processing facil- agricultural society until the late 18th cen- ities. tury to a major industrial power in the 20th. During all of the 18th century and early The Need for a New Energy 19th, human muscles and those of beasts of Supply System burden did most of the useful work. Through- out this period, wood was the primary fuel, In 1973, Arab oil exporting nations insti- supplemented by relatively small amounts of tuted an embargo against the United States coal, coal oil, whale oil, mechanical energy and other nations that supported Israel. Re- from falling water, and kerosene derived duced petroleum availability was followed by from natural petroleum seeps. By the middle a recession that lasted through 1974 and into of the 19th century, coal had become the 1975. As a consequence, energy consumption chief fuel and dominated the Nation’s energy declined slightly, bottoming out at about 71 supply system for about a hundred years. Quads in 1975. By 1976, energy demand had Petroleum-based fuels and natural gas en- returned to its 1973 level of about 74.5 tered the picture after 1859, the year in Quads/yr. It has continued to rise, although which the first commercial oil well was somewhat less rapidly than prior to the em- drilled in Pennsylvania. The use of petroleum bargo. grew rapidly. It was further accelerated by the arrival of the automobile age in the early In 1978, approximately 78 Quads of energy 1900’s. Natural gas, which was originally were consumed in the United States—the burned or vented as a waste product from oil equivalent of 13.4 billion bbl of fuel oil. wells, became a major fuel for domestic, com- Energy supply patterns had altered slightly since 1972. In 1978, petroleum supplied about mercial, and industrial heating by the end of 48 percent of the energy, natural gas about World War II. 25 percent, and coal about 18 percent. Geo- By the middle of the 20th century, oil and thermal and biomass use had increased sub- gas had become the leading sources of energy stantially, but these resources, together with in the United States, having displaced coal nuclear and hydropower, still provided only because of their convenience. In 1972, ac- about 9 percent of the Nation’s energy. cording to the Department of Energy (DOE), It is likely that energy consumption will the Nation’s economy consumed approxi- continue to rise until conservation strategies mately 72 Quads of energy from primary of which approximately 46 percent are adopted by all sectors of the economy. If sources, * historical growth trends for energy consump- was obtained from petroleum, 32 percent tion are followed, the annual energy con- from natural gas, and 17 percent from coal. Relatively small amounts were supplied by sumption will reach 135 Quads by the year 2000-the equivalent of over 23 billion bbl of fuel oil per year or nearly twice the 1978 con- *One Quad equals 1 quadrillion ( 101 Btu. A primary energy source is one that may be converted to another form prior to sumption. Actual consumption should be con- end use. Coal burned for power genera t ion is an example. siderably lower, because energy demand is

85 86 ● An Assessment of 01/ Shale Technologies now growing more slowly than in the past. sion. Other, less tangible effects (such as Conservation should slow it down further. threats to national security and the social Several implications may be drawn from and economic impacts of supply disruptions), this discussion. First, the United States con- although more difficult to quantify may prove sumes enormous amounts of energy. (The to be much more significant. It has become 1978 consumption was equivalent to over apparent that an energy supply system needs 2,500 gal of fuel oil per citizen per year, ) Sec- to be evolved that is more appropriate to the ond, energy demand will continue to rise in Nation’s present and projected needs and in- the near future. Third, the Nation runs on ternal resources. Just as wood was displaced fossil fuel, with petroleum satisfying nearly by coal, coal by domestic petroleum and gas, 50 percent of the total energy demand. and domestic petroleum by imported oil, it appears that imported energy must be replaced This last implication is crucial because it by new sources of domestic energy. appears that the United States no longer has An initial step in developing a new energy adequate petroleum reserves of its own. New supply system should involve formulating a petroleum discoveries peaked in the 1950’s. Domestic oil production followed suit in about comprehensive policy that reduces demand through conservation, increases availability 1970, except for the fields in Alaska and on from domestic resources, and restricts im- the Continental Shelf. Domestic discoveries ports. Conservation must be an important ele- are increasing, at present, because of higher ment of any such policy. However, there are oil prices, but it is unlikely that sufficient U.S. reserves exist to provide secure supplies be- limits to the savings that can be accomplished yond the end of the 20th century. Because of through conservation. Thus, it appears that it the inability of domestic petroleum develop- will be necessary to develop new energy re- ment to keep pace with growing demands for sources. Potential sources include additional liquid fuels, the United States has become in- reserves of conventional oil and gas, en- creasingly dependent on imported oil. In hanced oil recovery, expanded coal develop- 1978, the United States imported nearly 24 ment, solar-thermal and photovoltaics, wind percent of its total energy supply and nearly energy, tidal energy, ocean thermal gradi- 45 percent of its requirement for crude oil ents, increased nuclear fission for power gen- and refined petroleum products. A barrel of eration, nuclear fusion, biomass combustion, imported petroleum now costs five to six and the recovery of synthetic liquid and gas- times as much as it did in 1972. eous fuels by the conversion of coal, tar sands, biomass, and oil shale. The challenge The short-term reliability of imported oil is to derive optimal combinations of these supplies is very uncertain, as exemplified by sources which, when coupled with conserva- disruptions arising from the Suez crisis of tion and restricted imports, will provide suffi- 1956, the Arab-Israeli War of 1967, the Arab cient energy for future economic growth and oil embargos of 1973 and 1974, and the pres- development, while simultaneously protecting ent Iranian situation. Long-term reliability is the Nation’s physical and social environ- also questionable because worldwide oil pro- ments. duction is expected to peak within the next few decades and to decline rapidly there- The Purpose and Organization after. Eventually, it may be impossible to import oil at any price. of This Chapter Growing reliance on increasingly scarce As noted in the Introduction to this report, and expensive energy imports has had many this assessment is concerned with only one of adverse effects. Some of the economic im- the Nation’s energy supply opportunities, oil pacts (such as balance-of-payments deficits) shale—specifically with deposits in the Green can be quantified with some degree of preci- River formation of Colorado, Utah, and Wyo- Ch 4–Background ● 87 ming. Although the oil shale literature is ex- ● the characteristics of the resource re- tensive, the information is inadequate con- gion in Colorado, Utah, and Wyoming, in- cerning certain environmental, socioeconom- cluding brief descriptions of the geogra- ic, technological, and financial aspects of oil phy, the geology, the climate, and the shale development. However, the assess- physical and social environments; ment’s overall analysis has been facilitated by the extensive body of background information acquired during the Nation’s long but ● the potential applications for materials sporadic involvement with oil shale as an derived from the Green River oil shales, energy resource. The purpose of this chapter including oil, fuel gases, minerals, and is to organize this background information spent shale; and into a supporting framework for the detailed analyses found in subsequent chapters. The ● following subjects are discussed: the history and status of development efforts in the United States and other ● the location and extent of the oil shale countries, with emphasis on the efforts resources of the United States and for- currently underway in the Green River eign nations; formation.

Oil Shale Resources The Genesis of Oil Shale Oil shale is a sedimentary rock that contains organic matter, which although not appreciably soluble in conventional petroleum solvents can be converted to soluble liquids by heating. Oil shale was formed in the distant past by the simultaneous deposition of mineral silt and organic debris on lakebeds and sea bottoms. As the raw materials accumulated, heat and pressure transformed them into a stable mixture of inorganic minerals and solidified organic sludge. The formation processes that yielded petroleum, tar sands, and coal were conceptually similar, but differed with respect to key physical and chemical conditions. In oil shale, these condi- Photo credlf Department of the /nfer/or tions resulted in the formation of chemical bonds between individual organic molecules. Oil shale sample showing layers of organic composition The large size of the molecules formed by this bonding prevents them from dissolving in normal solvents. When heated in processes Worldwide Deposits known as pyrolysis and destructive distillation, the bonds rupture forming smaller liquid Oil shale deposits have been found on all of or gaseous molecules. These can then be sep- the inhabited continents. The extent of the arated from the inorganic matrix, which re- worldwide resources cannot be accurately mains behind as the spent shale waste prod- determined, but it appears to be very large in- uct . deed. In 1965, the U.S. Geological Survey 88 ● An Assessment 01 01/ Shale Technologies

(USGS) estimated that the world’s oil shale hydrogen to carbon in their organic compo- deposits comprised over 4 quadrillion tons, nent. having a total potential shale oil yield of over Some of the eastern shales have attracted 2 quadrillion bbl. If all of this oil were ex- interest because of the natural gas resources tracted and distributed among the world’s locked within the shale formations. DOE is residents, each person would receive about presently supporting a research and develop- 600,000 bbl. However, the spent shale waste ment (R&D) program to evaluate the potential would cover the entire surface of the world, of eastern shales for producing this fuel, with land areas and oceans included, to a depth of special attention given to stimulating gas pro- about 10 ft. duction from the Devonian shales that occur The deposits in Asia contain the largest in and around eastern Ohio and the western amount of potential shale oil resources, over part of West Virginia. The Antrim shales in 700 trillion bbl; Africa is second, with nearly southern Michigan are also being investi- 500 trillion bbl; North America contains over gated as potential sources of synthetic pipe- 300 trillion bbl; South America (principally line gas, which would be obtained by under- Brazil) about 250 trillion bbl; Europe has ground gasification methods. DOE is also about 170 trillion bbl; and Australia and New investigating the Chattanooga oil shales in Zealand together have only about 120 trillion Tennessee and Kentucky. In addition to their bbl. organic component these shales contain low- grade uranium and thorium ores. But they do Many of the world’s deposits have been not appear to have much commercial poten- subjected to commercial-scale development tial because the beds are thin and unfavor- at various times in the past. Those in Scot- ably located, and ore concentrations are very land, France, Germany, Australia, Sweden, low. Spain, and South Africa are of historical interest because of the industries that once The Green River Formation flourished in those countries. The deposits in The Green River formation is a geologic en- Estonia, Manchuria, Brazil, and Morocco are 2 of current interest because they are the sites tity underlying some 34,000 mi of terrain in of present or projected commercial develop- northwestern Colorado, southwestern Wyo- ment. ming, and northeastern Utah. (See figure 13. ) The formation has been divided into several distinct geologic basins. The Green River, Deposits in the United States Great Divide, and Washakie basins occur primarily in Wyoming. Together with the Sand Overview Wash basin in northern Colorado, these ba- 2 The oil shale deposits in the United States sins underlie about 14,000 mi . About 35 mil- are shown in figure 12, and their theoretical lion years ago they were occupied by a single shale oil yields are given in table 13. The de- large and long-lasting freshwater lake. posits in the Green River formation in Colora- The Uinta basin in northeastern Utah and do, Utah, and Wyoming are particularly note- northwestern Colorado and the Piceance ba- worthy because they contain the largest con- sin in Colorado underlie about 20,000 mi2 of centration of potential shale oil in the world. terrain, and were once occupied by a second Because deposits in the Central and Eastern freshwater lake. Most of Colorado’s Piceance United States underlie a larger area, they ap- basin lies north of the Colorado River, but it pear more impressive on maps than do those includes oil shale deposits within Battlement of the Green River. However, they contain Mesa and Grand Mesa on the south side of less than half the oil shale in the Green River the river. Colorado oil shale also occurs in the formation, and do not yield as much oil on a Sand Wash basin, which is north of the Pice- unit basis because of a lower proportion of ance basin near the Wyoming border. Ch 4–Background ● 89

Figure 12.—Oil Shale Deposits of the United States

/u_ --—4’ ‘1

Monterey Formation, Califorma; I middle Tertiary deposits In Montana. Black areas are I _- —-- +-\ known htgh-grade deposits. i “’=’~ ‘Y -—+.+.— -- (_- ‘). ‘,71, )- - ~ Mesozoic deposts ,/ Marine shale m Alaska i~--- r - -%’ --- I— --

~-— . 1 i Permian deposits r’ 1’ Phosphoric Formation, “) Montana ‘-./-’; ‘“ \ o 200 400 600 ‘\.. ~ Devonian and Mississippian T MILES deposits (resource estimates included for hatchured areas only). Boundary dashed where concealed or where location is uncertain,

SOURCE D C Duncan and V E Swanson, Orgarr/cR/ch Sha/es of the Urr/fed States arrd Wor/d Larrd Areas, U S Geological Survey Ctrcular 523, 1965

Table 13.–Potential Shale Oil in Place in the Oil Uinta, Green River, and Washakie basins. Shale Deposits of the United States (billions of barrels) These areas, and in particular the Piceance Range of shale oiI yields, basin, are among the most intensely explored gallons per ton geologic regions in the United States. The U.S. Location 5- 10a 10- 25a 25- 100a Bureau of Mines (USBM), USGS, and private Colorado, Utah, and Wyoming (the industry have drilled hundreds of exploratory Green River formation) 4,000 2,800 1,200 coreholes into the basin rocks. The earliest of Central and Eastern States (Includes Antrim, Chattanooga, Devonian, and USBM’s efforts took place during World War other shales) 2,000 1,000 (?) H. As a result, there is a considerable body of Alaska Large 200 250 (7) geological information about some areas of Other deposits 134,000 22,500 the deposits. Other deposits, particularly Total 140,000+ 26,000 2,000(?) near the fringes of the Uinta basin and the ba- ar)rder of magnitude est[mate Includes known deposits extrapolahon and !nterpolallon of known sins in Wyoming, are still largely unexplored. deposits and anhc!paled deposits Dala from D C Duncan and V E Swanson Orgarr/c-R/ch SJWes of Me LMed Safes md Wor/d Larid Afeas U S Geological Survey Circular 523 1965 To comprehend the potential value of the oil shale in the Green River formation, it is Oil shale resources have been found under necessary to distinguish among deposits, re- some 17,000 mi2, or 11 million acres, of the sources, and reserves. A deposit is simply a basins of the Green River formation. The natural accumulation. A resource is a natu- principal deposits are found in the Piceance, rally occurring substance with properties

63-898 0 - 80 - 7 90 ● An Assessment of 011 Shale Technologies

Figure 13.—Oil Shale Deposits of the Green River Formation

I IDAHO 8 I .!. - *. , - GREAT DIVIDE —.. BASIN + I WYOMING I

SAND ● Salt Lake City WASH UTAH BASIN

I :R -’”’”s !’ WP”:L EXPLANATION Area underlain by the Green River Formation Area underiain by oil shale more than in which the oil shale is unappraised or 10 feet thick, which yields 25 gallons low grade. or more oil per ton of shale.

SOURCE D C Duncan and V E Swanson, Orgarrlc-R/ch Shales of the Urvfed States and Wodd Land Areas, U S Geological Survey Circular 523, 1965 that can be put to use. A reserve is the equiv- mercial development. However, if the cost of alent of money in the bank. All of the rocks in extracting fuels from the resource is greater the Green River formation occur in deposits. than the value of the fuels obtained, the re- Some of the deposits are also resources be- source is not a reserve. Reserves exist only cause they contain sufficient oil shale, which when the resource can be extracted and when properly manipulated can yield useful processed to yield products that can be mar- fuels to warrant being considered for com- keted at a profit. Ch 4–Background ● 91

The total oil shale deposits of the Green richness, accessibility to underground min- River formation contain, in place, * the equiv- ing, and the extent to which they had been ex- alent of over 8 trillion bbl of crude shale oil, plored. A summary of the results appears in including all rocks that would yield from 5 to table 15. Data are presented for four classes 100 gal/ton of oil on destructive distillation. of oil shale resources. Classes 1 and 2 were However, many of these deposits are too thin, considered economically attractive for ex- too deeply buried, or too low in oil yield to be isting aboveground recovery technologies. included in a survey of oil shale resources, They include only the more favorably located because it would not be economically feasible and better defined shale beds, which are at to develop them. least 30 ft thick and would yield at least 30 In table 14, the quality of the Green River gal/ton. These two classes contain about 130 shale is evaluated according to thickness and billion bbl of shale oil, in place. The shales in potential oil yield. Only deposits that yield at class 3 might also be economically attractive, least 15 gal/ton and are at least 15 ft thick are but they are less well-defined, and their unfa- considered even marginally attractive. This vorable locations could hinder commercial group includes shales containing as much as development. Class 3 shales contain about 1.4 trillion bbl of shale oil in place. The high- 186 billion bbl. The bulk of the Green River grade shales are further defined as shale resources are in class 4, which includes beds that are at least 100 ft thick that would lower grade, poorly defined, and unfavorably yield at least 30 gal/ton. Their in-place oil con- located deposits. Class 4 shales contain near- tent is an additional 0.4 trillion bbl, for a total ly 1.5 trillion bbl. Some of the deposits in shale oil resource of about 1.8 trillion bbl, in classes 3 and 4 may be suitable only for in place. situ processing. The extent of the oil shale reserves cannot The total estimate shown in table 15 (about be determined at present. Resources can be 1.8 trillion bbl) agrees well with the total regarded as reserves only when processes for shown in table 14. However, the higher quali- developing them appear to be economically ty resources in the first three classes contain feasible. This has yet to be demonstrated for only 315 billion bbl, which is about 2 percent oil shale processes. However, several at- of the total estimated. The potential yield of tempts have been made to delineate particu- these deposits can be estimated by taking into lar Green River resources that would present consideration the inevitable losses that would a greater potential for profitable extraction. occur during mining and processing. Conven- In 1972, the National Petroleum Council tional underground mining methods can re- (NPC) used published geological data to clas- cover from 60 to 70 percent of the oil shale in sify the shale beds according to thickness and a mining zone; large-scale aboveground mining can recover about 90 percent. Processing the mined ore in aboveground retorts recov- “~he ter-rn “in place” is used to indicate the quantity of oil that would be created if the shale were retorted. As noted, oil ers approximately 90 to 100 percent of the oil shale deposits contain essentially no oil as such. that would be recovered if the shale were dis-

Table 14.–PotentiaI Shale Oil in Place in the Green River Formation: Colorado, Utah, and Wyoming (billions of barrels)

Nature of the deposit Colorado Utah Wyoming Total At least 100 ft thick with oil yields averaging at least 30 gal/ton ., 355 50 13 418 At least 15 ft thick with oil yields averaging at least 15 gal/ton, excluding the deposits shown above 840 270 290 1,400 Totals (rounded) 1,200 320 300 1,820

SOURCE W C Culberfson and J K Pllman 011 Shale In Um(ed Slates Mmera/ Resources U S Geological Survey Professional Paper 8?0 1973 pp 497503 92 An Assessment of Oil Shale Technologies

Table 15.–Potential Shale Oil Resources of the Green River Formation (billions of barrels)

Resource classa Location 1 2 3 4 Total Piceance basin (Colorado), ., ., ... 34 83 167 916 1,200 Uinta basin (Utah and Colorado) . . . . – 12 15 294 321 Wyoming basins .,, . . . . .,, ...... – – 4 256 260 Totals .,.,.,.,,,,.,,,.,,.,...,,,,,, 34 95 186 1,466 1,781

a 1 Deposits atleast 30 ftthlck andaveraglng 359al/ton 2 Dei)ost sat least 30 ftthlckandaveragmg 30gal/ton 3 Deposits slmllar to classes 1 and 2 but less well defined arm not as Iavorabley located 4 Poorly dehned depostts ranging down to 15 gal/lon SOURCE An Inmal Appraisal by the 011 Shale Task Group t971-1985 U S Energy Oul/ook–An /rMerm Repofl, The Nahonal Petroleum Council, Washington D C 1972 tilled under carefully controlled laboratory ment. It is also possible that some favorably conditions. If it is assumed that about 60 per- located resources could not be developed be- cent of the oil in the shale deposits could be cause of particular geotechnical characteris- recovered, the resources in classes 1 through tics (such as highly fractured ore zones or the 3 could yield 189 billion bbl of crude shale oil. presence of excessive amounts of ground wa- The projected yield of 189 billion bbl of ter) that were not considered in NPC’s analysis. In any case, the economic aspects of de- shale oil is only a small fraction of the total velopment are not well-understood because potential yield estimated—1.8 trillion bbl. It large-scale technologies have not as yet been is very small compared with the total in-place shale oil content of the Green River deposits built and operated. As previously observed, the key criterion in estimating reserves is eco- (some 8 trillion bbl). To put the figure in a meaningful perspective, the United States nomic feasibility. consumed about 6.5 billion bbl of crude petroleum in 1978, of which about 2.8 billion bbl of If all the above factors were given careful crude oil and refined products were im- consideration, it is possible that actual reported. At the 1978 consumption levels, the serves would be very small. On the other higher quality Green River resources have hand, it is also possible that an evaluation of the potential to supply all of the Nation’s the potential of known resources for in situ crude oil needs for 29 years or to replace im- processing along with additional exploration ports for nearly 68 years. Looked at another and research, could increase the reserve esti- way, the resources in the first three classes mate. There are deficiencies in the NPC esti- could sustain a l-million-bbl/d shale oil in- mate that largely reflect the current status of dustry for over 500 years. The class 1 re- technical and geological knowledge. For example, over 75 percent of the Uinta basin de- sources in Colorado’s Piceance basin alone posits were placed in class 4 because they could supply it for nearly 56 years. have not been as thoroughly explored as With existing data, a preliminary evalua- those of the Piceance basin. The analysis also tion of the Green River resources can be downgraded deposits that are not well-suited made with respect to their promise of com- to mining and aboveground retorting but mercial development, but the actual reserve might be ideal for underground processing. If value is still highly uncertain. It is likely that the survey were revised in the light of present some of the deposits could not be developed knowledge, it is possible that the reserve esti- without unacceptably damaging the environ- mate would be substantially increased. Ch 4–Background ● 93

Description of the Oil Shale Resource Region Location the Roan Plateau, which is relatively flat but severely eroded by stream courses. The oil shale deposits of the Green River formation underlie about 17,000 mi2 of ter- The southern escarpments (steep cliffs) rain in northwestern Colorado, northeastern that overlook the valleys of the Colorado and Utah, and southwestern Wyoming. * Major Green Rivers are the most spectacular fea- settlements in the area and major tributaries tures of both the Piceance and Uinta basins. that drain the region’s watershed into the At several locations these sheer cliffs rise to Colorado River system are shown in figure 14. heights of 4,000 ft above the adjacent river valleys. They are nearly continuous for a distance of some ZOO miles from the intersection Topography and Geology of the Roan Cliffs with the Grand Hogback near Rifle along the Cathedral Bluffs on the At the time of their deposition, the oil shale western side of the Piceance basin, to the in- basins probably resembled the fairly uniform tersection of the Book Cliffs with the Wasatch topography of continuous lakebeds. Tectonic Plateau at the western tip of the Uinta basin. upheavals have since elevated them, and substantial erosion by wind and water have al- Escarpments along tributary canyons are tered their terrain. Today, most of the oil similarly impressive. The topography along shale region is very rugged country. The to- one stretch of Parachute Creek in the Pice- pography of both the Uinta and Piceance ba- ance basin is depicted in figure 17. * At the sins is typified by rolling plateaus, cliffs, and location shown, the maximum elevation is ap- canyons. The elevation ranges from approxi- proximately 8,100 ft above sea level at the mately 4,300 ft above sea level along the ridge of the escarpment, and the minimum Green River in the Uinta basin to more than elevation is about 6,100 ft in the adjacent bed 9,000 ft at a point near the southeastern edge of Parachute Creek. The topography in other of the Piceance basin. This irregular topogra- tributary canyons is similar. For example, the phy strongly influences such characteristics Roan Creek Valley (near the southern edge of as climate, air motion and dispersion pat- the Piceance basin) is more than 30 miles long terns, and the duration of the growing sea- and from 2,000 to 3,000 ft deep. The Federal son. oil shale lease tracts are located in less eroded areas of the basin, and their topo- The various mountain systems surrounding graphic relief is much less dramatic. On tract the area of the Green River formation are C-a, for example, the average difference in shown in figure 15, and the general topo- elevation between valley floors and nearby graphic relief of the Piceance basin north of ridge tops is only about 300 to 600 ft. the Colorado River in figure 16. This figure does not show Battlement Mesa and Grand Figure 18 is an idealized cross section of Mesa, which lie to the south of the Colorado the Piceance basin that shows the strati- River. These are part of the Piceance struc- graphic relationships between the various tural basin, but the characteristics of their oil structural members of the Green River forma- shale resources are not well known. tion, the overlying Uinta formation, and the underlying Wasatch formation.** The bound- The main part of the Piceance basin is bounded by the White River on the north, by *The Parachute Creek valley was the site of two oil shale de- the Grand Hogback on the east, by the Roan velopment projects in the 1950’s and 1960’s, and additional projects are currently being considered for the same locations. Cliffs on the south, and by Douglas Creek and **The Uinta formation was previously called the Evacuation the Cathedral Bluffs on the west. Within the Creek member of the Green River formation in this area. See: basin are topographically high areas such as C. W. Keighin, “Resource Appraisal of Oil Shale in the Green River Formation, Piceance Creek Basin, Colorado, ” Quarterly *This area is slightly larger than Vermont and New Hamp- of the Co~orado School of Mines, vol. 70, No. 3, July 1975, pp. shire combined. 57-68. 94 . An Assessment Of Oil Shale Technologies

Figure 14.—The Oil Shale Resource Region of the Green River Formation: Colorado, Utah, and Wyoming

*. Rawlins

k $prlngs \ W-a weuAm VvYolMING

~~3~WASH

1 / Craig .Sttaamhmat .Snrinnc ‘r ----- “ ------r’ ‘“ ‘Y- (/. /

UINTA BASIN F ti”’ER’%KEANCE- rRO\

UTAH

d’:;:;:on\ Cnl nRArm v

F i \ )

I l-. L,.1 Unassayed or low yield

Oil shale more than 15-ft thick and yielding 25 gal of 011 d per ton of shale or more,

SOURCE. E DISante, “A Look at 011 Shale–What’s It All About, ” Sha/e Country Magazine, VOI 1, No 1, January 1975, p 7 Ch 4–Background ● 95

Figure 15.—Major Mountain Systems in the Vicinity of the Green River Formation 113” 112 111” 110” 109” o--- = 44” — r-m=i ‘t%l” “‘-: i’ ‘*

r---l==---+==, - 1 43”

--4x%!!--:-+%m. - -—-- —-1

-.. J

25 0 100 males

SOURCE U S Department of the Interior, F/rra/ Errv/ronrnenta/ SIaternent for the Protofype 0// Sha/e /-eas/rrg Program, GPO stock No 2400-00785, 1973. p 112 aries of these members, which are visible Below the Uinta, at a depth of 500 to 1,000 ft, along Parachute Creek, were shown in figure is the Parachute Creek member of the Green 17. The Green River formation is about 3,000 River formation, which is almost entirely oil ft thick near the center of the basin. shale marlstone with occasional beds of vol- canic material (tuff) and sandstone. Near the The top strata of the section comprise the basin’s depositional center, the Parachute Uinta formation, which underlies the sur- Creek member contains scattered deposits of faces of high plateaus in the Piceance basin. the minerals dawsonite, nahcolite, and halite. The Uinta is largely barren sandstone and Dawsonite, which contains aluminum, is oc- siltstone with some interbedded oil shale. casionally found in thin layers between the oil 96 . An Assessment of Oil Shale Technologies

Figure 16.—Topographic Relief of the Piceance Basin, Colo.

SOURCE Goider Associates, Inc., Water Management m O// Sha/e Mmmg, September 1977, NTIS No PB.276086, p 73 shale beds. More commonly it occurs as mi- The lower extremities of the Garden Gulch croscopic crystals disseminated throughout and Douglas Creek members, which underlie the oil shale. Nahcolite is sodium bicarbon- the Parachute Creek member, roughly coin- ate. It is a source of soda ash, a raw material cide with the bottom of the ancient lake on for glassmaking, and may also be used to which the raw materials for the Green River remove sulfur dioxide from stack gases. oil shales accumulated. The upper 200 to 300 Halite is sodium chloride, from which table ft of the Garden Gulch member contain clay salt is made. The Parachute Creek member beds and deposits of shale having an appre- also includes the Mahogany Zone, which con- ciable organic content. ’ The Garden Gulch tains oil shale yielding up to 70 gal/ton. Below shales are true shales in that their primary the Mahogany Zone, near the center of the inorganic components are aluminum-contain- basin, is a region from which soluble sodium ing illite clays, unlike the oil shales of Para- salts have been leached out by the ground chute Creek, which are primarily composed water flows and which now contains saline of dolomite (calcium and magnesium carbon- ground water. Near the bottom of the Para- ate) rocks. Below the Douglas Creek member chute Creek member is the “saline zone, ” is the Wasatch formation, which is largely which contains high concentrations of nahco- barren sandstone and mudstone. The Wa- lite and other sodium salts that have not been satch rocks generally form valley floors leached. throughout much of the Piceance basin. They Ch 4–Background ● 97

Figure 17.— Stratigraphy and Landform Units Along Parachute Creek, Piceance Basin, Colo.

LANDFORM UNITS STRATIGRAPHY I—CLIFFS (ESCARPMENT) UINTA FORMATION 2—MID-SLOPES GREEN RIVER FORMATION 3—SLIP AND ROCKFALL TERRAIN (TALUS) Tgp--PARACHUTE CREEK MEMBER 4—WASATCH FOOTSLOPES Tgg—GARDEN GULCH MEMBER 5-ALLUVIAL FAN Tgd—DOUGLAS CREEK MEMBER 6-CHANNEL LAND WASATCH FORMATION

SOURCE Bureau of Land Management, Draft ,Env~ronrnenfa/ Stafernenf for Proposed Deve/opfnenf of 0(/ Sha/e Resources by (he Co/ony Oeve/oprnen/ Operat(on In Co/ orado U S Department of the Interior, 1975 p III-101 98 . An Assessment of 01/ Shale Technologies

Figure 18.— Idealized Cross Section of the Piceance Basin, Colo.

SOUTH NORTH Roan Plateau

Ledge

SOURCE Bureau of Land Management, Dralt EnVlr0nIr7ental Stater77ent tor Proposed Development O( 0// Sha/e Resources by the Colony Deve/oprrrent Opera//on m Colorado, U S. Department of the Interior, 1975, p 111.13 do not contain any oil shale of commercial in- mediately above and below the Mahogany terest. Zone are lower in organic content and less Variations in the properties of the various resistant to weathering. Where the zone out- strata have had significant effects on the top- crops along tributary canyons, its richer ographic relief of the region. The Uinta for- shales have resisted erosion, but the leaner mation sandstones cover the oil shale depos- surrounding shales have not. Consequently, its over much of the Piceance basin. Over the the outcropping fringe of the zone is often past several million years, outcrops of the highly visible as an overhanging prominence Uinta rocks have weathered considerably. known as the Mahogany Ledge, which ap- The organic-rich oil shale zones of the under- pears in most areas as a dark band along the lying Parachute Creek member, however, escarpment, as shown near the top of figure have been much more resistant to weather- 17. ing. The Mahogany Zone of the Parachute Gradual deterioration of the ledge has re- Creek member is an outstanding example. It sulted in rockfalls and the formation of talus is from 10 to 225 ft thick, contains oil shale (debris) slopes between the bottom of the that has, in general, a high organic content, ledge and the river valley below. Such slopes and underlies an area of more than 1,200 mi2 were indicated in figure 17 as slip and rock- in the Piceance basin. It also extends into the fall terrain. They are steep and unstable, par- neighboring Uinta basin. * Oil shale beds im- ticularly if naturally or artificially undercut. Because talus slopes are naturally unstable *Green River oil shale has a Iaminar appearance because of variations in the organic content of adjacent strata. Polished and lack sufficient permanent topsoil, they do sections of the richer beds resemble mahogany wood. Most oil not provide favorable growing conditions for shale projects in the near term will be focused on the rich most types of vegetation. However, varying shales of the Mahogany Zone. The other potential source of rich oil shale, the Garden Gulch member, is probably too deep amounts and kinds of vegetation can grow on for near-term commercial development. some slopes depending on their aspect and Ch 4–Background 99 the available moisture. The north-facing low-pressure systems are frequently de- slopes generally have fairly abundant vegeta- flected around the entire region by the Sierra tion; the south-facing slopes much less. Nevadas to the west and the Rocky Moun- tains to the east, Stagnant high-pressure cells sometimes persist for days over the basins, Climate and Meteorology their passage blocked by the surrounding Climate high mountains. Adjacent mountain ranges also contribute to the region’s dry climate. The climate of the oil shale region is clas- Moist air from the Gulf of Mexico is blocked sified on the whole as semiarid to arid. An- by the Rocky Mountains, while moist air from nual precipitation varies from approximately the Pacific is blocked by the Sierra Nevadas. 7 inches in the Wyoming plains to approxi- Flows from both directions lose most of their mately 24 inches in the high plateaus of the moisture before reaching the oil shale area. Piceance basin. Most of this occurs as snow- The frequent presence of dry, high-pressure fall, Snowpack, which commonly exceeds 30 air cells over the basins causes an abundance inches on protected slopes, provides surface of clear sunny days with light winds and runoff during the spring. Summer and fall are large differences between daytime and night- usually dry, but there are short, heavy thun- time temperatures. derstorms occasionally during the late summer months. These can cause flash flooding Air Patterns in low-lying areas, Relative humidity is generally low to moderate, with high evaporation Localized wind patterns and other meteor- rates throughout the region. Because of the ological conditions are very sensitive to topog- region’s abundant sunshine, most valley raphy and elevation. For example, in the Pice- floors and south-facing slopes are usually not ance basin, shielding by the Cathedral Bluffs, covered with snow during winter, the gentle downward slope of the basin to the northeast quadrant and the existence of deep Average temperatures are generally mod- gullies, effectively channel surface wind erate, but maximum daytime temperatures flows and decouple them from the prevailing can reach 100° F (38° C) at lower elevations gradient winds. The shielding effect is pro- during midsummer, and winter temperatures vided by the sheer escarpment of the Cathe- 0 0 may drop to – 40 F ( –40 C) at higher eleva- dral Bluffs and Roan Cliffs along the southern tions. The number of frost-free days varies and western edges of the basin. When pre- from 50 at higher elevations to 125 at lower vailing winds encounter the bluffs they must elevations. The limited rainfall and low rela- rise approximately 3,000 ft to clear the upper tive humidity coupled with the short growing ridges. The rising air increases in speed and season restrict the agricultural use of tillable generates turbulent eddies whose duration is areas. Some forage crops are produced along enhanced by the downward slope of the ba- the tributary valleys within the basins, but sin’s upper surface. The shielding of the es- most food crops are grown outside of the ba- carpments combined with the basin’s down- sin along major rivers where adequate irriga- slope minimizes the effect of gradient winds tion water is available. on surface wind patterns except along very high ridges and plateaus. Airflows in the Col- Meteorology orado River valley, in tributary canyons, and along the valleys and low hills atop the Roan The meteorology of the oil shale region in Plateau are almost entirely determined by lo- Colorado is typified by year-round gradient cal topography. They follow a drainage-wind winds from the west that are interrupted only pattern and are nearly independent of the be- by the passage of frontal systems. Migratory havior of prevailing gradient winds aloft. 100 ● An Assessment of 0il Shale Technologies

The Mountain-Valley Breeze System sion frequencies in the United States. The inversions occur most frequently during the The predominance of drainage-wind pat- winter and persist over 50 percent of the time terns is exemplified by the mountain-valley in the fall and winter months. Inversions breeze system that has been observed on both might be expected to occur less frequently on Federal oil shale lease tracts in Colorado. The the slopes and plateaus of the Piceance basin. phenomenon is characterized by gentle down- However, it has been predicted that inversion valley air flows beginning around sunset and episodes lasting from 3 to 6 days could occur prevailing for about 10 hours in winter, fol- at least once a year over the entire region.3 lowed by gentle up-valley flows starting at Recent investigations performed on the Fed- midmorning. On clear nights, when the upper eral lease tracts have concluded that the pol- atmosphere is stable, layers of dense, cold air lutant dispersion potential of the basin is form near ground level. Any cold air that good when contaminated air is released enters the valley along adjacent slopes will above the higher plateaus, and relatively tend to flow downslope into the stagnant cold poor when fumes are released into the val- layer. In the early morning, sunlight gradual- leys. The same studies have predicted that ly warms the surrounding slopes. The cold air trapping inversions, * such as are associated then disperses and flows upslope to become with the mountain-valley breeze system, entrained in the prevailing gradient winds. At should seldom persist longer than 24 hours. various times during the day and night, circular flow patterns and eddies may prevail within the valley, but they will not carry air Plants and Animals from the valley unless gradient winds along The Green River formation underlies a the upper ridges are quite strong.’ large area. Its soil characteristics show considerable variation over this area. In com- Thermal Inversions and Their Implications bination with climate, meteorology, and topography, soil characteristics largely deter- The mountain-valley breeze system often mine the types of plant communities that can causes a layer of cold stagnant air to form be supported. These, in turn, influence the below a layer of warm air—a thermal inver- diverse animal species that feed directly or sion. Such inversions exacerbate air pollution indirectly on them. problems. There is little air transport out of the cold layer, and pollutants emitted near Plants ground level will tend to accumulate there. In- versions are usually broken by surface heat- The vegetation of the region is highly di- ing during the daylight hours, but under cer- verse, and its makeup is strongly affected by tain adverse conditions they may prevail for elevation. Most of the broader stream valleys several days. Valleys with broad floors are in the region contain fertile alluvial (flood- especially susceptible, particularly after a plain) soils that support relatively luxuriant snowfall. Snow cover reflects sunlight and in- growths of cottonwood, shrubs, and other hibits the warming of the stagnant layer dur- species. In contrast, the surfaces of steep ing the day, thus reducing the upward flow of slopes and some upper plateaus are bare warm air that is essential to disruption of the rocks and ledges with little or no soil develop- inversion. At night, the exposed snow surface ment. Vegetation is often absent or at best enhances the downward flow of air from the quite sparse in such areas, especially in some valley ridges, thus increasing the thickness of plateaus in Utah and Wyoming and in the Pi- the inversion layer. ceance basin where the saline rocks of the Studies have shown that Grand Junction, *A trapping inversion is one that traps contaminated air re- Colo., which is located outside of the oil shale gardless of the temperature at which the contaminants are re- basins, experiences one of the highest inver- leased from their source. Ch 4–Background ● 101

Garden Gulch member are exposed, Some ies included a census of existing plant species gently sloping upland areas contain thin and and a determination of the structural charac- poorly developed soils with occasional local- teristics and successional status of plant com- ized strips of alluvium. Plant cover in these lo- munities. The results of these studies provide cations varies from very sparse in the poorer an indication of the diversity of plant life in areas to relatively abundant over the alluvial the vicinity of proposed oil shale development deposits. In general, the extent of vegetation sites. is strongly influenced by aspect. South-facing slopes have much less vegetation because The plants identified on tract C-a included their greater exposure to sunlight acceler- 5 types of trees, 36 shrub species, and 168 ates the evaporation of critical moisture. herbaceous species, of which 44 were classified as grass or grass-like. One of the plants, In the high plains of southwestern Wyo- dragon milkvetch, is on the Smithsonian In- ming, soils are usually thin and dry, and vege- stitution’s list of endangered plant species. tation is predominantly saltbrush-grease- However, the species is not considered wood and related shrubs. There are limited threatened in Colorado.’ On tract C-b, 37 areas of Douglas fir forests and mountain ma- types of trees, shrubs, and vines were identi- hogany woodlands in the northern fringes of fied, together with 137 species of herbs. the Green River and Washakie basins. Soils Vegetation community types included pinyon- are somewhat thicker in the Uinta basin, but juniper woodlands and rangelands, upland the arid climate inhibits plant growth except and valley sagebrush, Douglas fir forests and along the valleys of the major rivers, Salt- aspen woodlands, mixed mountain shrub- brush-greasewood and other shrubs domi- lands, marshes, riparian areas, agricultural nate, but there are occasional stands of fields, mountain grasslands and communities mountain mahogany, oak shrub, pine, and fir. dominated by bunchgrass, Great Basin wild In the Piceance basin, shrublands and rye, rabbitbush, greasewood, and annual woodlands also dominate, and forestlands wild plants. No threatened or endangered plant species were found on tract C-b or on are sparse. Shrubland plants consist primari- s ly of mixed shrubs on moist soils at higher tracts U-a and U-b, Colony Development{ has elevations and sagebrush, which dominates reported the presence of two endangered in all dry soils. Woodlands occur in thinner plant species (yellow columbine and milkvetch) and one threatened plant species (sulli- soils at lower elevations, and are dominated 6 by pinyon pine and juniper, except where vantia) along the valley of Parachute Creek. grazing and other disruptions have allowed intrusions of brushes and grasses. Forests Animals are primarily cottonwood along streams at lower elevations, and Douglas fir and aspen Many types of mammals, cold-blooded ver- on northern and eastern slopes at higher tebrates, birds, invertebrates, and aquatic systems exist throughout the oil shale re- elevations, gions. The diversity of vertebrates is among Overall, plant life in the Green River for- the highest in the United States, a result of mation area is less abundant than in other the highly diversified habitats of woodland, regions that have ample rainfall and less grassy shrubland, and high desert that char- rugged terrain. However, the area contains acterize the area. In Colorado’s Piceance diverse plant communities that are well basin, for example, more than 300 species of adapted to their environment. Some of the birds, reptiles, mammals, and amphibians communities in the Piceance basin were stud- have been found or are believed to exist. Simi- ied by the developers of Federal lease tracts lar numbers of animal species have been re- C-a and C-b as part of the baseline-monitoring ported in other geologic basins of the Green function required for the preparation of de- River formation. ’ Because of the relatively tailed development plans. The baseline stud- low rainfall, wildlife of the region are highly 102 . An Assessment of Oil Shale Technologies dependent on the stream systems and the lards and other ducks, mourning doves, pi- riparian habitats of their environs. geons, golden and bald eagles, and many other species of migratory waterfowl, shore- COLORADO’S PICEANCE BASIN birds, songbirds, hawks, eagles, and vultures. Fish species include trout, suckers, and min- The Piceance basin is Colorado’s most im- g portant mule deer range. It is the principal news. wintering ground for the White River herd, the largest nonmigratory deer herd in North UTAH’S UINTA BASIN America. Its size has been estimated at ap- Utah’s Uinta basin is more primitive and proximately 100,000 head.8 The northeast isolated than the Piceance basin. It has been corner of the basin normally supports the described as an ideal natural faunal habi- highest deer concentrations in winter, and tat. ’() Parts of the basin are utilized by mule the entire basin is considered to be a deer deer herds as winter feeding areas, and small range in the summer. Antelope are also found numbers of elk are also present in restricted there, but are primarily restricted to the areas. Transplanted antelope have become northern edge. Limited numbers of elk live in established and appear to be flourishing. the general area of the basin and especially Bears have been reported in the area but are on the upper plateaus. A few mountain lions considered scarce. Mountain lions also range roam over it, largely in pursuit of migrating over the basin, but their numbers are un- deer herds and sheep flocks, and a few black known. Other mammal species include coy- bear are found at higher elevations in the otes, porcupine, bobcat, muskrat, beaver, southern part. Coyotes and bobcats are re- mink, rabbits and hares, and others. The Bu- garded as abundant, but there has been no reau of Land Management (BLM) has esti- detailed census of these predators. There mated that about 130 head of wild horse in- may be as many as 150 to 200 cottontail rab- habit Utah’s oil shale lands. Most bird species bits per square mile, and both snowshoe found in the Piceance basin are also found in hares and pine squirrels are found in the the Uinta basin. Fish live in the clear head- Douglas fir forests of the high plateaus. Other waiters of various tributaries but are less mammals present include yellow-bellied mar- abundant in the heavily silted lower reaches mots, prairie dogs, ground squirrels, porcu- of most rivers and streams. 11 pines, chipmunks, red foxes, raccoons, badg- ers, and skunks, and from 150 to 250 wild WYOMING’S BASINS horses range throughout the entire area. The Over 300 animal species have been identi- avian species found in this basin include sage fied in Wyoming’s Green River and Washakie grouse, partridge (stocked), pheasants, mal- basins. Of the larger mammals, elk and moose are believed to inhabit the parts of Wyoming that encompass the oil shale regions. Rela- tively few elk and moose live in the oil shale basins per se, but black bear and lions have been observed. The basins also contain important antelope ranges and habitats. Sizable numbers of wild horses live in the Washakie basin and winter in the highlands where prevailing winds sweep the heavy snowfalls from grazing areas. Several species of grouse, ptarmigan, partridge, wild turkey, pheasant, ducks, and geese have also been observed in the general vicinity of the oil shale lands. Tributaries support several trout varieties in- Phofo credit OTA staff cluding the Colorado River cutthroat, and Ch 4–Background ● 103

some of the better trout habitats are located an oil shale industry, are discussed in within the oil shale area. 12 chapter 10.

ENDANGERED SPECIES Air Quality In compiling an inventory of animal species, the tract C-a lessees recorded sightings In general, air quality is excellent through- of both peregrine falcons, listed as an endan- out most of the region because of the region’s gered species by the U.S. Department of the rural character and lack of industrialization Interior (DOI), and prairie falcons, a fully pro- and urban development. Ambient concentra- tected species, The number of peregrine fal- tions of sulfur dioxide, nitrogen oxides, hy- cons was estimated at from one to four. No drogen sulfide, and carbon monoxide are falcon nesting sites were found in the 170 mi2 very low compared with more densely popu- survey area. It is unlikely that falcons would lated areas in the three oil shale States. In nest within the tract boundaries because of both the Piceance and Uinta basins, however, the absence of large cliff faces (their pre- there are occasionally high ambient concen- ferred nesting location) and the scarcity of trations of nonmethane hydrocarbons, partic- water. Approximately 30 greater sandhill ulate, and ozone, The hydrocarbons are ap- cranes, endangered species in Colorado, parently emitted in aerosol form by sage- were observed in the study area, but no nest- brush and other vegetation, because their ing sites were discovered within a 20-mile concentrations vary with the growing sea- radius of the tract. The tract and its environs sons for these plants. Windstorms and pass- may serve as staging and foraging areas for ing automobile traffic on unpaved roads both the birds during their annual migrations, but contribute to high particulate concentrations. the area does not contain any important Haze is occasionally observed in the valley of crane habitats. 13 the Colorado River and in the canyons of its tributaries. It has not been determined The environmental reconnaissance on whether this haze is caused by photochemical tract C-b did not reveal any rare, endan- smog or by a combination of suspended par- gered, threatened, or protected animal spe- ticulate and local humidity. In general, the cies. However, a prairie falcon was sighted 17 14 area is free from man-induced odors. outside of the tract boundaries. Environ- mental surveys for Colony Development re- Air quality problems may be encountered vealed no endangered or threatened species in the future because of the region’s peculiar within the tract boundaries.15 BLM’s environ- meteorological conditions. As discussed pre- mental statement for the Colony program lists viously, the predominance of the mountain- several species of concern that might be pres- valley breeze system coupled with high alti- ent in the general area. These include the tudes and the effects of surrounding moun- southern bald eagle, the prairie and pere- tain ranges on gradient winds aloft, leads to grine falcons, the humpback chub, the Colo- frequent thermal inversions, especially dur- rado squawfish, the Colorado cutthroat trout, ing winter. To date, such inversions have the bonytail sucker, the black-footed ferret, been offensive only near the larger popula- and the ferruginous hawk. 16 tion centers outside of the oil shale basins, such as Grand Junction. However, inversion- Air and Water Quality and Economic Base related air pollution is likely to become more severe as the region develops, regardless of Regional air and water quality, and their whether such growth is associated with the potential alterations because of oil shale de- creation of an oil shale industry or expan- velopment, are discussed in chapter 8. The sions in other activities. The potential for in- region’s economic base, and the impacts it versions may preclude siting processing might experience during the development of plants in canyons and other low-lying areas, -.

104 ● An Assessment of 0il Shale Technologies thus, limiting them to higher areas such as mg/1 at the discharge point into the White the Roan Plateau of the Piceance basin. River. f’ Dissolved solids in Yellow Creek in the Piceance basin range from about 700 to Water Quality 3,000 mg/1. Water quality deteriorates in the downstream direction because of natural sur- Water quality in the region is highly vari- face runoff, agricultural return flows, and able. It is good to excellent in most of the the discharge of saline ground water from upstream reaches of major tributaries such aquifers in the Green River and Uinta forma- as the Colorado River, but significantly tions. As described in chapters 8 and 9, poorer in the downstream reaches. The grad- ground water quality in the aquifers of the Pi- ual deterioration is caused by discharges ceance basin varies enormously, from a low from numerous point and nonpoint sources. of less than 250 mg/1 in the purer waters of About half of the increase in salinity is re- the upper aquifer above the Mahogany Zone lated to the discharge of naturally saline to over 63,000 mg/1 in the highly saline brines streams into the river system. The rest is gen- of the lower aquifer in the northern portions erally related to the concentration of human of the basin. In general, the ground water activities, such as urban areas, mineral de- from all the aquifers in the Piceance basin velopment sites, and irrigated farmlands. does not satisfy the drinking-water standards A twentyfold increase in salinity has been of the U.S. Public Health Service. There are particular problems with respect to dissolved noted in the Colorado River between its head- 20 waiters and Imperial Dam in Arizona. 18 Salini- solids, fluoride, and barium concentrations. ty is of special concern because the Colorado The quality of surface streams and ground River system is important to the entire South- water in the Uinta basin shows similar ex- west. Irrigated agriculture causes most of the treme variability. The concentration of total human-related salinity effects through salt dissolved solids in the Uinta basin ground loading (picking up soluble salts from field water aquifers range from 350 mg/1 (which is soils) and salt concentration (the evaporation considered potable water) to 72,000 mg/1 and transpiration of relatively pure water in (which is considered brine). In the Wyoming irrigation canals and fields). oil shale basins, surface streams have dissolved solids concentrations from 150 to 855 mg/1, while concentrations in ground water range from about 450 to 7,000 mg/l. 21

Population The population density over the entire oil shale resource region is low, averaging about 3 persons per square mile. The densities in many areas are even lower. For example, when the oil shale resources of a 2,500 mi2 area of the Uinta basin were mapped in 1967, 250 people lived in the entire area, with 200 Photo credit OTA staff of them living in the town of Bonanza. The White River near Meeker, Colo. average population density of the area was therefore about 0.1 persons per square mile. 22 Surface streams within the oil shale basins The population of the entire Green River also show wide variations in water quality. In formation region is approximately 120,000. Piceance Creek, for example, the concentra- About 62 percent live in Colorado, 17 percent tion of dissolved solids range from less than in Utah, and 21 percent in Wyoming. The ma- 400 mg/1 in the upper reaches to over 5,000 jor communities are Grand Junction, Rifle, Ch 4–Background ● 105

Meeker, Craig, and Rangely in Colorado; Ver- region’s present economy is based on agricul- nal in Utah; and Green River and Rock ture (crop raising and sheep and cattle ranch- Springs in Wyoming, Grand Junction, the ing), minerals production (oil, gas, uranium, largest Colorado town, has a population of trona, and coal), and tourism and recrea- approximately 24,000, Vernal ‘has about tion,232425 6,200, and Rock Springs about 28,000, The

Oil Shale Products and Their Potential Applications The Nature of Oil Shale the mineral residue has little cohesive strength and is easily crushed to a fine Green River oil shale is not a shale nor does powder, it contain appreciable amounts of liquid oil. The shale portion is actually a marlstone, and Kerogen Pyrolysis its principal constituents are dolomite, calcite, and quartz. In contrast, true shales are When kerogen is heated above 400” F 0 composed largely of silicate clays. They have (200 C), chemical bonds between and within a finely stratified or laminated structure and the individual organic molecules are rup- tend to fracture along individual bedding tured, forming smaller molecules. Most of planes. Oil shale also has a stratified appear- these can be readily isolated from the mineral ance and tends to fracture in a similar mat- material as liquid and gaseous products. ter, particularly when organic matter is pres- Some of the organic coproducts of kerogen ent in low concentrations. These properties decomposition remain trapped within the in- led early investigators to believe that the organic material as a coke-like residue. Green River oil shales were true shales. How- ever, the appearance and fracture properties A chemical change produced by heat is of Green River shale arise from variations in called pyrolysis, This process can also be the concentrations of organic matter it con- called destructive distillation, when an or- tains, and not to any great extent from the ganic substance is broken down by heat and characteristics of the inorganic component, the products are distilled off, leaving a residue. When pyrolysis is carried out in a vessel Most of the organic component is a solid called a retort, the process is called retorting. material called kerogen, from the Greek Oil shale retorts may vary in size from labora- words for waxmaking, that is insoluble in tory-size Fischer assay* units used to esti- most standard petroleum solvents. About 10 mate the potential oil yield of oil shale rocks, percent of the organic component is a solid to commercial-sized vessels that can process substance called bitumen that can be dis- 10,000 tons of raw oil shale per day, to in situ solved in certain solvents. retorts containing several hundred thousand Kerogen is composed of carbon and hydro- tons of rock. gen molecules cross-linked together by sulfur When kerogen is pyrolyzed, three combus- and oxygen atoms to form relatively large tible products are formed: vaporized oil, three-dimensional macromolecules with mo- which can be condensed by cooling; a gaseous lecular weights of about 3,000. These macro- mixture containing hydrogen, oxides of car- molecules are embedded within the finer bon, hydrogen sulfide, and hydrocarbon grained inorganic or mineral matrix of the oil shale rock. This organic continuous phase gives kerogen-rich oil shale most of its physi- *In a Fischer assay, small samples of crushed oil shale are heated to 9320 F (500° C] under carefully controlled conditions. cal strength and stability. When the organic The oil yield by this method is the standard measure of oil shale matrix is removed from very rich oil shale, quality.

63-398 “) - 80 - 6 106 ● An Assessment of 01/ Shale Technologies

gases such as methane; and a coke-like solid matter was transformed to water vapor by residue that remains behind in the retort. the pyrolysis process. The relative proportions of oil, gases, and Each of the three main products of kerogen coke largely depend on the pyrolysis tempera- decomposition is a potential source of energy. ture and atmospheric conditions in the retort, Crude shale oil can be burned directly as a and to a lesser extent on the organic content fuel or it can be refined to produce fuels simi- of the raw shale. The product yields from a lar to those obtained from conventional petro- typical Green River oil shale pyrolyzed at leum crude oils. As discussed in chapter 6, 932° F (500° C) according to the standard the physical and chemical properties of crude Fischer assay technique are summarized in shale oil differ from those of conventional table 16. As indicated, the raw shale con- crude, thus presenting some refining challenges. However, shale oil can yield high- Table 16.–Composition and Pyrolysis Products quality finished fuels such as gasoline and jet of Typical Colorado Oil Shalea fuel. Mineral constituents The composition and properties of the off- Mineral Weight percent of minerals gas from kerogen pyrolysis vary tremendous- Dolomite 32 ly with the nature of the pyrolysis process. Calcite 16 Quartz ~ 15 Gas from the Fischer retort typically has a Illite ,. 19 heating value comparable to that of natural Low-albite 10 gas. Such high-quality gas could be used as Adularia 6 Pyrite ., . 1 plant fuel in the oil shale facility, or it could Acalcime ~ 1 be pipelined to other areas for commercial or Total. 100 industrial applications. In contrast, gases Ultimate analysis of organic constituent from commercial directly heated retorts are Element Weight percent of organics highly diluted with carbon dioxide (from com- Carbon 765 bustion and from the decomposition of car- Hydrogen 103 bonate minerals) and nitrogen. They have Nitrogen 25 Sulfur 1.2 only about one-tenth the heating value of Oxygen 9.5 natural gas. Such gases could be useful Total 1000 within the oil shale facility but they could not Yields from Fischer assay Pyrolysis be transported economically over any signifi- Weight percent of cant distance, nor could they be upgraded to organic constituent Weight percent of higher heating values at reasonable cost. Sur- Decomposition product in raw shale total raw shale plus retort gases could become valuable by- Oil 63 10,4 products if they were burned for power gen- Noncondensable gas 15 2.5 Fixed-carbon residue 13 2.2 eration. Some developers plan to do this. Water vapor 9 1.4 Total ... ., 100 16,5 The coke residue is also a potential source of energy, but it is a very poor solid fuel com- aPy@yzed by the slafldard Fischer assay procedure at 932° F 011 y(eld = ?6 7 gal/ton pared with coal or with the raw shale itself. SOURCE T A Sladek Recent Trends [n 011 Shale–Pad 1 Htstory Nature and Reserves Mmera/ /nduslrfes f3u/e/in VOI 17 No 6 November 1974 pp 4.5 (A typical shale coke from the Fischer retort has a heating value of about 250 Btu/lb; most tained about 17 percent organic matter by quality coals have heating values of about weight and yielded about 27 gal/ton. Oil was 12,000 Btu/lb.) Transportation of the coke the largest decomposition product. It com- residue for offsite combustion would not be prised 63 percent of the organic matter practical because of its high content of inert originally present in the shale, Noncondensi- mineral matter. Any energy values will have ble gases comprised 15 percent, and the car- to be recovered within the oil shale facility bon residue about 13 percent. The balance of either by burning the residue in the retorts or hydrogen and oxygen content of the organic by converting its carbonaceous component to Ch 4–Background ● 107 fuel gas. If the latter approach is followed, tional center of the Piceance basin and is the gas may be consumed within the plant, found in high concentrations near the bottom upgraded for external sale, or burned onsite of the Parachute Creek member. Nahcolite for power generation. may be processed to yield soda ash, a com- As indicated in table 16, inorganic miner- mon raw material for glass production, and als comprise approximately 80 percent of its ability to adsorb sulfurous gases may be of raw Green River oil shale. These minerals reuse in scrubbing sulfur compounds from pow- main as part of the coke residue after the oil erplant stack gases. and gas products are removed. The proper- Dawsonite (dihydroxy sodium aluminum ties of this retorted or spent shale vary with carbonate) is a potential source of alumina, the type of retorting procedure used. Indi- which can be converted to aluminum. As indirectly heated retorts produce a carbonaceous cated previously, dawsonite is found as dis- spent shale, while directly heated retorts pro- seminated crystals and crystalline planes in duce a shale that is essentially stripped of the Parachute Creek member. Occurrences of carbon. The indirectly heated TOSCO II re- both nahcolite and dawsonite are very exten- tort, for example, produces a spent shale re- sive in this basin. A survey of mineral resources in the basin by USGS estimated that 1 sembling black talcum powder. The directly 2 heated Union “A” retort produces a gray de- mi of terrain in the soda-mineral region carbonized spent shale resembling coal ash overlies 1 billion bbl of potential shale oil in and clinkers. place, 130 million tons of nahcolite with a potential soda ash yield of 82 million tons, and Spent shale will be produced in enormous sufficient dawsonite to produce 42 million quantities by an oil shale industry of any tons of alumina. By comparison, the bauxite significant size. Some potential uses exist for deposits in the rest of the United States con- the spent shale produced by aboveground retain the equivalent of only about 30 million torts. With in situ processing, the spent shale tons of alumina.26 remains underground, and the only option for Trona is a hydrated mixture of sodium car- byproduct recovery is by means of a leaching bonate and sodium bicarbonate. It is also a process. Spent shale on the surface could be source of soda ash for glass production, and converted to cement or building materials, is presently being mined for this purpose in but the output from a single commercial-size Sweetwater County, Wyo. Unlike nahcolite facility will far exceed the market demand and dawsonite, trona does not always occur for such material. Nearly all of the spent in intimate association with oil shale, and its shale will have to be disposed of as a waste commercial development could take place material, and such disposal will have to be either with or without the related develop- done either on or very near the plantsite. ment of hydrocarbon resources. The existing Spent shale disposal is the source of much of facilities in Sweetwater County do not recov- the environmental controversy surrounding er shale oil. Projected plans for multiminerals oil shale development as discussed in chap- operations, such as those of Superior Oil and ter 8. the Multi Minerals Corp., call for the simultaneous production of shale oil, soda ash, and Associated Minerals alumina. 27 28 Both of these projects depend on acquiring In addition to kerogen, some deposits in the access to Federal land through land ex- Green River formation contain several sodi- changes or leasing. No privately owned tracts um-bearing minerals that could be commer- contain sufficient quantities of dawsonite and cially valuabIe. These include nahcolite, daw- nahcolite for their development to be econom- sonite, and trona. Nahcolite (sodium bicar- ically attractive. Some sodium leases have bonate) is chemically identical to commercial been issued for oil shale land, but these ex- baking soda. As mentioned previously, it oc- clude the development of the associated oil curs in scattered deposits near the deposi- shale. 108 ● An Assessment of 011 Shale Technologies

The History of Oil Shale Development Useful hydrocarbons have been extracted forts and defines the status of present indus- from oil shale for many years. In the 14th cen- tries around the world. tury, Austrian and Swiss oil shales were pyrolyzed to yield “petro oleum, ” or “rock oil. ” Scotland This was subsequently processed to yield an ointment called Icthyol, a name derived from Scottish oil shales occur in seams from 4 to the Greek words for fish-oil, in reference to 14 ft thick yielding approximately 22 gal/ton. the fossilized fish remains frequently encoun- Reserves were originally estimated to contain tered in the marine oil shales of central Eur- about 600 million bbl. The first retorting ope.29 In 1694, England issued patent No. 33 plant was built in 1859. Its economic viability for a retorting process that was claimed to was immediately threatened by the rapid de- produce “oyle from a kinde of stone. ”30 velopment of conventional petroleum that In 1859, the first commercial oil well was followed the drilling of the first commercial drilled in Pennsylvania. Prior to that year, at oil well. The production of shale oil and val- least 50 commercial plants existed along the uable byproducts such as waxes, ammonia, Atlantic seaboard of the United States for ex- pyridines, * ammonium sulfate, and building tracting fuel oil from oil shales.]’ Also in 1859, materials enabled the Scottish industry to the first commercial oil shale retort began survive for over 100 years despite the high operating in Scotland. It started an industry cost of the oil in comparison with conven- that lasted for over 100 years. tional crude oil. At its peak, the industry involved about 140 different companies and In 1874, workers on the transcontinental processed about 3.3 million ton/yr of oil shale. rail line found that rocks picked up from ex- In 1919, the companies were consolidated cavations along the Green River in Wyoming into a single corporation that subsequently ignited when used to protect campfires from became a subsidiary of the predecessor of the night winds. The March 1874 issue of Sci- British Petroleum. The industry was subsi- entific American noted that the railroad su- dized by the British Government with tax perintendent :32 credits and other incentives, but competition . . . has caused analyses and experiments to from cheap petroleum forced the last plant to be made with this substance which proves to close in 1962. be a shale rock rich in mineral oils. The oil can be produced in abundant quantities, say Sweden 35 gallons to the ton of rock. The oil thus obtained is of excellent quality. Typical Swedish oil shales are about 50 ft The rocks of interest were pieces of oil shale thick and yield from 6 to 15 gal/ton. The total from the Green River formation. resource is estimated to be about 2.5 billion bbl of shale oil in place. The Swedish oil shale The use of oil shale as a fuel resource thus industry began in the 1920’s, with the largest predates the large-scale use of conventional operations near the city of Kvarntorp. These petroleum by several centuries. In the past facilities featured two types of aboveground 150 years, commercial industries have ex- retorts and a unique type of in situ process in isted in Scotland, France, Germany, Spain, which the deposits were pyrolyzed with elec- South Africa, Australia, and the United tric heaters. The industry reached a maxi- States. At present, industries exist or are mum capacity of 2 million tons of oil shale per being started in Estonia, the People’s Repub- year (6,000 ton/d) and produced as much as lic of China, Brazil, and perhaps the United States. The following section describes the *Nitrogen-containing organic solvents also used to syn- history of foreign and U.S. development ef- thesize other useful products. Ch 4–Background ● 109

550,000 bbl/yr of crude shale oil. Because of 1949. In 1961, a plant was built in the town of the limited quantity of high-quality reserves, Dotterhausen that burns finely crushed oil and price competition from petroleum crude, shale in a fluidized-bed combustor. The heat the industry ceased operation in 1966. of combustion is used for power generation, and the spent shale product is used to make cement. The plant is the only active oil shale France facility in West Germany. French resources total about 500 million bbl of shale oil in place. They are of medium South Africa quality and yield from 10 to 24 gal/ton. They are more properly called bituminous shales, Very rich deposits are found in South Afri- rather than oil shales, because they contain ca. Oil yields reach 100 gal/ton, with an aver- inclusions of asphaltic compounds. The age of 55 gal/ton, and the deposits are located French industry began in 1840 and continued just beneath coalbeds. South African shale oil intermittently until 1957. Its maximum production began in 1935, and the industry throughput was 0,5 million ton/yr of shale, at- attained a maximum throughput of 800 ton/d tained in 1950. For most of its existence, the in the 1950’s, with a corresponding shale oil industry was protected from competition with production of 800 bbl/d. The industry was lo- foreign oil by excise taxes and import duties. cated in the country’s interior, and although it was not directly subsidized by the government, its economic viability was enhanced by Spain the high cost of transporting competing petro- The best Spanish resources yield from 30 leum from the seacoast ports to interior mar- to 36 gal/ton. Reserves have been estimated kets in the vicinity of the plants. The richer at about 280 million bbl of oil in place. The deposits were eventually depleted, and the in- Spanish industry began in 1922 using retorts dustry ceased operations in 1962, similar to those that had been developed in Scotland. Maximum throughput for these Australia units was 220 ton/d, reached in 1947. In 1955, new retorts from Scotland were installed. In Oil shale deposits are found throughout 1960, the enlarged industry processed 1 mil- Australia. Those of New South Wales and lion tons, supplying more than half of Spain’s Tasmania have been developed commercial- requirement of lubricating oil, Obsolete proc- ly. Total reserves are estimated at 270 million essing technology and high operating costs bbl of shale oil in place. Most of the deposits forced the industry to cease operation in are very rich, with oil yields as high as 180 1966. gal/ton. Shale oil production in New South Wales began in 1862, and by 1892, about 100,000 tons of shale were being processed Germany each year. The Australian Government began German resources are estimated to contain subsidizing the industry in 1917, but produc- only about 2 million bbl of shale oil in place. tion ceased in 1925. Production of Tasmanian Oil yields average only 12 gal/ton. German shale oil began in 1910 and ceased in 1935. In shales were developed as early as 1857, and the interim, about 41,000 tons of oil shale several retorts were operated in the 1930’s. were processed, and 85,000 bbl of shale oil A major development effort was initiated dur- were produced. ing World War II in response to wartime fuel Production was resumed in New South shortages. The German industry used two Wales early in World War II under the direc- types of aboveground retorts and one in situ tion of the Australian Government. By 1947, process. A plant with about 30 Lurgi above- annual throughput reached 330,000 tons, and -ground retorts was operated from 1947 to about 100,000 bbl of shale-derived gasoline 110 ● An Assessment of Oil Shale Technologies were produced annually. The production was continued to the present day, although over- equivalent to about 3 percent of Australia’s sight authority was transferred to the Energy gasoline consumption. The plant was closed Research and Development Administration in in 1952 because of resource depletion, high 1974 and to its successor, DOE, in 1978. operating costs, and competition from conventional petroleum. One of USBM’s most significant early acts was the establishment of a research facility United States at Anvil Points on the Naval Oil Shale Reserve near Rifle, Colo. Between 1944 and 1956, the As indicated previously, the U.S. oil shale Anvil Points facility was used for mining industry was an important part of the Na- studies that led to the application of the room- tion’s energy economy before the first oil well and-pillar technique of underground mining. was drilled. At least 50 commercial plants for The gas combustion retort, the predecessor of extraction of fuel oil from eastern oil shales modern directly heated retorts, was also de- existed prior to 1859. The industry disap veloped during this period. In 1964, the facil- peared shortly after commercial petroleum ity was leased by the Colorado School of production began. Mines Research Foundation, and was the site of a 4-year development program in which the Between 1915 and 1920, supplies of domes- gas combustion retort was evaluated and im- tic crude fell below demand, and oil imports proved by a consortium of six major oil com- increased, especially from new oilfields in panies: Mobil, Humble, Continental, Pan Mexico. USGS indicated at that time that the American, Phillips, and Sinclair. United States had only a 9-year reserve of petroleum in the ground and that the outlook In 1973, the facility was leased by Develop- for new discoveries was not good. At about ment Engineering, Inc. (DEI), which operated the same time, USGS announced that large it for 5 years during which the Paraho retort- fuel resources were contained in the oil ing process was developed. This is an im- shales of the Green River formation. When proved version of the gas combustion retort. combined with predictions of forthcoming DEI then used the facility to produce over fuel shortages, the announcement triggered 100,000 bbl of shale oil for refining studies, an oil shale boom. Some 30,000 mining claims and has recently proposed to use Anvil Points were filed on Federal lands, and about 200 for further development work, including the companies were formed to develop the re- construction and operation of a commercial- source. Retort development programs were size module of the Paraho retort. initiated at several locations, and at least 25 retorting processes were advanced to the Between 1963 and 1968, DOI evolved a pilot-plant stage. Total shale oil production leasing proposal that was intended to encour- was negligible, but interest was at an all-time age private development of the Federal oil high. The boom ended abruptly with the dis- shale lands in the Green River formation. The covery of large oilfields in eastern Texas. Oil program failed to attract private partici- prices dropped to a few cents per barrel, and pation. However, it gave rise to the current interest in oil shale development essentially Federal Prototype Oil Shale Leasing Program, disappeared. which was conceived in 1969 and pro- Little R&D was conducted in the United mulgated in 1974 with the sale of leases to States until World War II. In 1944, out of con- four tracts in Colorado and Utah. The his- cern for the hazards of imported energy, Con- tories of these leasing programs are pre- gress passed the Synthetic Liquid Fuels Act, sented in volume II of this report. The status which authorized USBM to establish a liquid of development efforts on the Federal lease fuel supply from domestic oil shale. USBM be- tracts is described in the last section of this gan a comprehensive R&D program that has chapter. Ch 4–Background 111

In addition to these activities on Federal included Tosco, Atlantic Richfield, Cleveland lands, private companies have also engaged Cliffs Iron Co., and Ashland Oil Co. The activ- in exploration and R&D programs on their ities of these companies, and others that are own lands, The companies that have been presently involved in oil shale development, most heavily involved are: Union Oil, Occiden- are summarized in the following section, tal Petroleum and its subsidiary Occidental together with a status report on the indus- Oil Shale, Inc.; Superior Oil Co.; and the Col- tries in other countries. ony Development Operation group, which has

Status of Foreign Oil Shale Industries Morocco cent of the shale was retorted to obtain fuel oil; the rest was burned directly for process Oil shale is found in Morocco at Timahdit, heat and power generation. During World in the Middle Atlas mountains, and at Tar- War II, the area was occupied by Germany, faya, on the Atlantic coast in the southern and the shale oil produced during this period part of the country. Other, smaller deposits was refined to obtain illuminating oil and have also been found. Most of the develop- bunker fuel oil for the German navy. When ment efforts involve the Timahdit deposits, the Estonian S.S.R. was created, the German- which contain an estimated 4 billion to 9 built plants were expanded to provide fuel billion bbl of shale oil in a seam that is as gas for the cities of Tallinn and Leningrad. much as 350 ft thick. The Moroccan Govern- Shale oil and petrochemicals were also pro- ment is actively investigating aboveground duced, but most of the shale mined was retorting, direct combustion of oil shale for burned as a boiler fuel for power generation. power generation, and modified in situ proc- In 1970, about 14 million tons were mined. essing technologies. The present goal is to expand production to 54 million ton/yr. About 75 percent of the Soviet Union present production is burned under boilers to supply about 90 percent of Estonia’s electri- The principal reserves of the U.S.S.R. are cal needs. The rest is retorted to produce fuel in the Baltic Basin, with additional deposits in oil, gasoline, fuel gas, and chemicals. the Ukranian S.S.R. and the Central Asian Re- publics. The latter resources have been little The Soviet industry is estimated to have explored and are not being developed; most mined about 560 million tons of kukersite development activity is centered on the “ku- between 1945 and 1975. As noted, only one- kersite” oil shales in the Baltic basin. The fourth of the mined shale is retorted. If all of total Baltic resource is estimated to be about the shale had been converted to oil, the aver- 21 billion tons, with about 11.3 billion tons age production rate would have been about regarded as having commercial potential. 67,000 bbl/d, slightly more than would be pro- About 8.4 billion tons occur in the Estonian duced by a single commercial-scale oil shale S. S. R., with about 2.9 billion tons in the Lenin- facility in the United States. The present grad area. The Estonian shales occur in beds target of 54 million ton/yr is equivalent to about 10 ft thick and are buried beneath 30 to about 200,000 bbl/d. 130 ft of overburden. They are of good quali- Two types of large-scale retorts are used: ty, yielding about 50 gal/ton. the Kiviter gas generator which is similar to The Estonian deposits were first developed the gas combustion and Paraho directly in the 1920’s after the State achieved inde- heated retorts; and the Galoter retort which pendence from Finland. In 1939, about 1.7 uses spent shale as a heat carrier and is million tons were processed. About 60 per- remarkably similar to the TOSCO II indirectly 112 . An Assessment of 01/ Shale Technologies heated design. At present, the largest Kiviter distance of about 1,000 miles to the border retort has a capacity of about 1,000 ton/d, with Uruguay. Irati shale yields about 20 about one-tenth the size of retorts planned for gal/ton on retorting, which is comparable to a U.S. plants. The largest Galoter unit has a medium grade of Green River shale. capacity of about 500 ton/d. A 3,30()-ton/d nit is under construction. * Small retorts have been used intermittently in Brazil since 1862. Early operations produced illuminating gases for home use. Re- People’s Republic of China torting was discontinued in 1946 but resumed in the 1950’s under control of the national Oil shale is found near Fushun in Manchu- government. In 1970, a 2,200-ton/d” demon- a, and near Maoming in the Province of stration retorting plant was completed at Sao Kwantung. The Manchuria deposits occur in Mateus do Sul in the State of Parana. The 450-f t-thick seams and overlie thick coal plant has operated on an experimental basis. seams. The shale is mined by open pit meth- The Petrosix retorting process is used. It was ods, together with the coal, Oil yields average developed by the engineering staff of Petro- only about 15 gal/ton. The deposits were first bras, the national oil company, with the as- developed by the Japanese when they invaded sistance of Cameron Engineers, a U.S. engi- Manchuria during World War II. About 1.3 neering firm. Little information has been re- million bbl of shale oil were recovered during leased about the demonstration but, given the the war through use of retorts similar to the properties of the Irati shale and assuming gas combustion design. Most of the oil was re- high oil recoveries from the retort, the plant fined into fuel oil for the Japanese navy. Dur- could produce about 1,000 bbl/d of shale oil, ing the Korean war, production was ex- eve. a million cubic feet of high-Btu gas per panded to about 50,000 bbl/d. Byproducts in- day, and about 15 ton/d of elemental sulfur. cluded chemical fertilizer from the nitrogen in the shale oil and cement from the spent At present, Petrobras is attempting to raise shale. Additional shale was mined, mixed about $1.5 billion to build a commercial-size with coal, and burned directly for power gen- plant with a capacity of about 45,000 bbl/d. eration. The plant would be sited near the present demonstration facility. About 20 Petrosix re- During the past decade, the capacity of the torts would be used. Current plans call for a Manchuria industry has remained fairly 25,000-bbl/d operation by 1983, with subse- constant, but six retorting plants have been quent expansion to full capacity by 1985. The built in the Kwantung Province. The total pro- deposits in the immediate vicinity of the plant- duction from the Chinese plants is unknown, site could supply the full-size facility for but it is unlikely to be more than about 50,000 about 30 years. Two additional plants of simi- to 70,000 bbl/d. About two-thirds of the oil is lar size are contemplated for the State of Rio refined, the rest is burned directly for power Grande do Sul, which is south of the demon- generation. stration plant. Brazil’s enduring interest in oil shale de- Brazil velopment is related to its oil-import problem. Brazil has very large deposits which could It consumes about a million barrels of crude contain as much as 3 trillion bbl of potential oil per day, of which about 960,000 bbl/d are shale oil. The largest deposits of commercial imported. The net drain of the national econ- interest are those of the Irati formation, omy is about $11 billion per year, which con- which begins in the State of Sao Paulo and ex- tributes to a net deficit in the balance of inter- tends southward in an S-shaped curve for a national payments of about $1.55 billion. It is difficult to track the effect of this deficit in an *For additional information on retorting technologies see ch. economy with a 60-percent annual inflation 5. rate, but the currency drain to purchase im- Ch 4–Background ● 113 ported oil is estimated to be equivalent to same proportion of its GNP on imported oil, about 6 percent of the nation’s gross national about 15 million bbl/d would be imported, or product (GNP). If the United States spent the nearly twice the present rate.

Status of U.S. Oil Shale Projects The characteristics and status of 11 proj- project is also on a Federal lease tract, but it ects that are at least at the stage of field test- is inactive at present because of legal uncer- ing in the Green River shales are summarized tainties.* Tosco’s Sand Wash project is Pro- in table 17. The list does not include several ceeding towards commercialization at a rela- relatively new projects (such as Multi Miner- tively leisurely pace to maintain compliance al Corp. ’s project for extraction of oil, nahco- with the due-diligence provisions of the Utah lite, and alumina from deeply buried deposits leases. Three projects—Logan Wash, Geoki- in the Piceance basin) or projects that are be- netics, and BX—are of an experimental na- ing conducted in the eastern shales. It also ture and are being partially funded by DOE. does not include the numerous theoretical in- The four other projects—Colony, Union, Su- vestigations and laboratory-scale experi- perior, and Paraho—are aimed towards ulti- ments that are being conducted by Federal mate commercial-scale operations but are in- and State agencies and private companies. active at present for a variety of reasons, Two of the projects—Rio Blanco and principally economic. Cathedral Bluffs—are actively proceeding *The Rio Blanco, Cathedral Bluffs, and White River projects towards commercial-scale operations on Fed- are parts of the Federal Prototype oil Shale Leasing !Y )grarn, eral lease tracts in Colorado. The White River which is discussed in vol. II of this report. 114 An Assessment of 01/ Shale Technologies

Table 17.–Status of Major U.S. Oil Shale Projects

Production target Project Location Proposed technology (barrels per day) Status summary Rio Blanco Oil Shale Co.: Federal lease tract C-a, MISa and Lurgi-Ruhrgas 76,000 Shaft sinking for MIS module development. Gulf, Standard of Indiana Colorado aboveground retorts (1987) Designing Lurgi-Ruhrgas module, PSDb permit obtained for 1,000 bbl/d. Cathedral Bluffs 011 Shale Federal lease tract C-b; Occidental MIS 57,000 Shaft sinking for MIS module development, project: Occidental Oil Colorado (1986) Process development work being done at Shale: Tenneco Logan Wash, PSD permit obtained for 5,000 bbl/d. White River Shale project: Federal lease tracts U-a Paraho aboveground 100,000 Inactive because of litigation between Utah, Sundeco; Philips; SOHIO and U-b; Utah retorts the Federal Government, and private claimants over landownership Colony Development Opera- Colony Dow West TOSCO II aboveground 46,000 Inactive pending improved economic tion: ARCO; Tosco property ;Colorado retorts conditions. PSD permit obtained for 46,000 bbl/d. Long Ridge project: Union Union property; Colorado Union ‘‘B’ aboveground 9,000 Inactive pending improved economic 011 of California retort conditions. PSD permit obtained for 9,000 bbl/d. Superior Oil Co. Superior property; Superior aboveground 11,500 Inactive pending BLM approval of land Colorado retort plus nahcolite, soda exchange proposal. PSD permit obtained ash, and alumina for 11,500 bbl/d. Sand Wash project: Tosco State-leased land; Utah TOSCO II aboveground 50,000 Site evaluation and feasibility studies retorts underway. Lease terms require $8 million investment by 1985, Paraho Development Corp. Anvil Points: Colorado Paraho aboveground 7,000 Inactive following completion of pilot plant and retorts semiworks testing. Seeking Federal and private funding for a modular demonstration program, Logan Wash project, Occi- D. A. Shale property; Occidental MIS 500 Two commercial-size MIS retorts planned for dental Oil Shale: DOE Colorado 1980 m support of the tract C-b project. PSD permit obtained for 1,000 bbl/d, Geokinetics, Inc., DOE State-leased land, Utah Horizontal-burn true in situ 2,000 Continuation of field experiments, About (1982) 5,000 bbl have been produced to date. BX 0il Shale project Equity Equity property; Colorado True in situ retorting with Unknown Steam injection begun and will continue for 0il Co. ; DOE superheated steam about 2 years. Oil production expected in (Equity process) 1980. Production rate has not been predicted

aModdled In SIIU processing

bpreventlon of Slgnif[canl delerloratlon–an alr quallty permit that must be obtained before conslrucllon can be91fl (See ch 8 ] SOURCE Off Ice ol Technology Assessment

Chapter 4 References

‘C. E. Banks and B. C. Franciscotti, “Resource “Rio Blanco Oil Shale Project, Detailed Develop- Appraisal and Preliminary Planning for Surface ment Plan—Tract C-a, Gulf Oil Corp. and Stand- Mining of Oil Shale, Piceance Creek Basin, Col- ard Oil Corp. (Indiana), March 1976, p. 3-6-12. orado,” Quarterly of the Colorado School of 5Environmental Protection Agency, Assessment Mines, vol. 71, No. 4, October 1976, pp. 257-285. of the Environmental Impacts From Oil Shale De- ‘R. Nelson, “Meteorological Dispersion Poten- velopment, EPA-600/7-77-069, July 1977, p. 100, tial in the Piceance Creek Basin,” Quarterly of the ‘Supra No. 3, at p. 111-121. Colorado School of Mines, vol. 70, No, 4, October 7Supra No. 4, at p. 9-11-18. 1975, pp. 223-238. 6 De partment of the Interior, Final Environmen- ‘Bureau of Land Management, Draft Environ- tal Statement for the Prototype Oil Shale Leasing mental Impact Statement—Proposed Develop- Program, Washington, D. C., 1973, pp. H-79 to ment of Oil Shale Resources by Colony Develop- 11-90. ment Operation in Colorado, Department of the In- ‘Supra No,4,atp.9-11-16. terior, Dec. 12, 1975, p. 111-9, %upra No. 8, at p. 11-231. Ch 4–Background ● 115

‘l Supra No. 8, at p. II-232. “C. Edmonds, “Vernal, Utah: From Dinosaurs to 1%upra No. 8, at p. II-292. Shale,” ShaJe Country Magazine, vol. 1, No. 3, 1 !3upra No. 4, at p. 9-11-16. March 1975, pp. IO-12. ‘qC-b Shale Oil Project, Oil Shale Tract C-b—De- ‘%upra No. 17, at p. 1-15. tailed Development Plan and Related Materials, ‘OR. J. Hite and J, R. Dyni, “Potential Resources Ashland Oil, Inc., and Shell Oil Co., February of Dawsonite and Nahcolite in the Piceance Creek 1976, pp. VII-5 and XI-63. Basin, Northwest Colorado,’” Quarterly of the Co~- 1%upra No. 3, at p. III-47. orado School of Mines, vol. 62, No. 3, July 1967, %upra No. 3, at pp. III-9 and III-11. pp. 25-38. 17 Environmental Protection Agency, Pol)ution ‘7B. Weichman, Saline Zone Oil Shale and the Guidance Control for Oil Shale Development (Re- Integrated In Situ Process—The Unrecognized vised Dru~t Report), Cincinnati, Ohio, July 1979. p. Solution for Crude Imports, Multi Mineral Corp., 1-14. Houston, Tex., May 1979. ‘“Bureau of Reclamation, Critical Water Prob- ‘8J. H. Knight and J. W. Fishback, “Superior’s lems Facing the Eleven Western States—West- Circular Grate Oil Shale Retorting Process and wide Study, vol. I, Department of the Interior, Australian Oil Shale Process Design, ” Twelfth Oil April 1975, p. 176, Shale Symposium Proceedings, Golden, Colo., Col- “J. B. Weeks, et al., Simulated Effects of Oil orado School of Mines Press, August 1979, pp. Shale Development on the Hydrology of Piceance 1-16, Basin, Colorado, U.S. Geological Survey Profes- I°F. C. Jaffe, “Oil Shale. Part I: Nomenclature, sional Paper No, 908, 1967, pp. 19-22. Uses, Reserves, and Production, ” Mineral Indus- ‘(’Ibid. tries Bulletin, vol. 5, No, 2, March 1962. ‘lSupra No. 17, at pp. 1-15 to 1-17, IOJ. H, Gary, “Foreword to the Seventh Oil Shale “W, B. Cashion, Geology and Fuel Resources of Symposium, ” Quarterly of the Colorado School of the Green River Formation, Southeastern Uinta Mines, vol. 69, No. 2, April 1974, p. v. Basin, Utah and Colorado, U.S. Geological Survey 31R, D, George, “Geology and Distribution of Oil Professional Paper No, 548, 1967. Shales,’” in R. H. McKee, cd., Shale OiJ, New York: “C. Edmonds, “Rock Springs: ‘Sinking City’ on The Chemical Catalog Co., Inc., 1925, pp. 37-42. the Rise, ” Shale Country Magazine, vol. 2, No. 9, ‘2 Supra No. 30. September 1976, pp. 10-12. CHAPTER 5 Technology

Page Page Introduction ● .*. ... . * * ,, *,, , **,,.*.,. 119 Demonstration ...... 173 Summary of Findings...... 119 Chapter 5 References...... 175 An Overview of Oil Shale Processing ...... 120 List of Tables Oil Shale Mining...... 123 Surface Mining...... 123 Table No. Page Underground Mining ...... 125 18. Overall Shale Oil Recoveries for Several Processing Options ...... 155 Oil Shale Retorting...... ,128 19. Properties of Crude Shale Oil From True In Situ...... ,...... 128 Various Retorting Processes...... 156 Modified In Situ ...... 131 20. Supply of Finished Petroleum Products Aboveground Retorting ...... 137 in PADDs 2, 3, and 4 in1978 ...... 165 Advantages and Disadvantages of the 21. Technological Readiness of Oil Shale Processing Options...... 153 Mining, Retorting, and Refining Oil Recovery ...... 154 Technologies ...... 168 Properties of Crude Shale Oil ...... 155 List of Figures Shale Oil Refining...... ,..157 Shale Oil Upgrading Processes . ....,...... 158 FigureNo. Page Total Refining Processes ...... 160 19. Oil Shale Utilization ...... 121 Cost of Upgrading and Refining ...... 162 20. The Components of an Underground Mining and Aboveground Retorting Oil Markets for Shale Oil...... 163 Shale Complex...... 122 Shale Oil as a BoilerFuel ...... 163 21. An Open Pit Oil Shale Mine...... 124 Shale Oil as a Refinery Feedstock ...... 164 22. Open Pit Oil Shale Mining...... 125 Shale Oil as a Petrochemical Feedstock .. ...166 23. The Colony Room-and-PillarMining Issues and Uncertainties ...... 167 Concept ...... 126 24, Room-and-Pillar Mining on MultipIe R&D Needs and Present Programs...... 170 Levels ...... 127 R&D Needs ...... 170 25. The Original Mine Development Plan Present Programs...... ,..,...172 for Tract C-b ...... 128 Policy Options ...... **.,*,.. 173 26. True In Situ Oil Shale Retorting ...... 129 R&D...... ,.....173 27. Modified In Situ Retorting...... 132 Page Paqe 28. The RISE Method of MIS Oil Shale 42. The Superior Oil Shale Retort.. , . . . . . 150 Retorting ...... ,. 134 43. The Colony Semiworks Test Facility 29. Initial Modular MIS Retort Near Grand Valley, Colo...... 151 Development Plan for Tract C-a ...... 135 44, The TOSCO II Oil Shale Retorting 30. Present MIS Retort Development Plan System .,, , . . . . . 0 ., . . . . ., .,....,, 152 for Tract C-a ...... 136 45* The Lurgi-Ruhrgas Oil Shale Retorting 31. Retort Development Plan for the . ,0 ,0 ...... 153 Multi Mineral MIS Concept...... 136 46. Refining Scheme Used by the U.S. 32. Preparation of a Multi Mineral MIS Bureau of Mines to Maximize Gasoline Retort ...... 137 Production From Shale Oil ...... 161 33. A Set of Multi Mineral Misreports . . . 138 47* Refining Scheme Employing Coking 34. The Operation of an NTU Retort...... 140 Before an Initial Fractionation, Used by 35, Discharging Spent Shale Ash Froma Chevron U.S.A. in Refining 40-Ton NTU Retort...... , . . 141 Experiments. ., ...... 161 36. The Paraho Oil Shale Retorting System 143 48. Refining Scheme Employing Initial 37, The Paraho Semiworks Unit at Hydrotreating, Used by Chevron U.S.A. Anvil Points, Colo. ● , ● ● ● ● ● ● . ● . . . ● , . ● 143 in Refining Experiments ...... 161 38. The Petrosix Oil Shale Retorting 49. Refining Scheme Employing Initial System . .,..,.,...... ,,..0.,.,0. 145 Fractionation, Used by SOHIO in 39. The Petrosix Demonstration Plant, Prerefining Studies ...... , . . 162 Sao Mateus do Sul, Brazil...... 146 50. The Petroleum Administration for 4U. The Union Oil “B” Retorting Process.. 147 Defense Districts...... 165 41. Block Diagram for the Superior Multi Mineral Concept ...... 149 CHAPTER 5 Technology

Introduction

The mining and processing technologies that could be used to convert the oil

that can be used to convert kerogenf the or- shale to liquid and gaseous fuels; ganic component of oil shale, into marketable ● the upgrading and refining methods that fuels are discussed in this chapter. The char- could be used to convert crude shale oil acteristics of these technologies will influ- to finished products; ence the effects that an oil shale industry will ● the potential markets for shale-derived have on the physical environment, and their fuels; technological readiness will affect the rate at ● the technological readiness of the major which an industry can be established. The steps in the oil shale conversion system; following subjects are discussed: ● the uncertainties and the research and development (R&D) needs that are asso- ● the general types of processing methods and their major unit operations; ciated with each major unit operation; ● and the mining methods that could be used to ● remove oil shale from the ground and the policies available to the Government prepare it for aboveground processing; for dealing with the uncertainties, ● the generic types of retorting methods

Summary of Findings

Oil shale contains a solid hydrocarbon called advanced with other minerals. More oil shale ex- kerogen that when heated (retorted) yields combusti- perience has been acquired with underground ble gases, crude shale oil, and a solid residue called mining, particularly room-and-pillar mining, and spent, retorted, or processed shale. Crude shale oil preparing MIS retorts. Although uncertainties re- can be obtained by either aboveground or in situ (in main, the mining technologies should advance place) processing. In aboveground retorting (AGR), rapidly if presently active projects continue and the shale is mined and then heated in retorting suspended ones resume. vessels. In a true in situ (TIS) process, a deposit is first fractured by explosives and then retorted under- ● TIS is presently a very primitive process, although ground. In modified in situ (MIS) processing, a por- R&D and field tests are being conducted. The prin- tion of the deposit is mined and the rest is shattered cipal advantages of TIS are that mining is not (rubbled) by explosives and retorted underground. needed and surface disturbance from facility siting The crude shale oil can be burned directly as boiler and waste disposal is minimized. The principal fuel, or it can be converted into a synthetic crude oil disadvantages are a low level of technological (syncrude) by adding hydrogen. The syncrude can readiness, low recovery of the shale oil, and a po- also be burned as boiler fuel, or it can be converted tential for surface subsidence and leaching of the to petrochemicals or refined to obtain finished fuels. spent shale by ground water. Some of OTA’s major findings concerning these min- ● MIS is a more advanced in situ method. It is being ing and processing technologies are: further developed on two lease tracts and a pri- ● Limited areas of the oil shale deposits may be vately owned site. The Department of Energy amenable to open pit mining. This technique has (DOE) is providing substantial R&D support. The never been tested with oil shale but it is well- principal advantages of MIS are that large depos-

119 120 ● An Assessment of Oil Shale Technologies

its can be retorted, oil recoveries per acre affected $2.00 more per bbl than refining some of the are high, and relatively few surface facilities are poorer grades of domestic crude. required. However, some mining and some disposal of solid wastes on the surface are required, ● The initial output from the pioneer oil shale in- and the oil recovery per unit of ore processed is dustry will probably be marketed near the oil shale low relative to AGR methods. The burned-out MIS region. Once the industry is established, the shale retorts have a potential for ground water pollution. oil will probably be used as boiler fuel or refined in the Rocky Mountain States. A large industry will ● AGR also has a medium level of technological most likely supply oil to Midwest markets. A 1- readiness. Three retorts have been tested for sev- million-bbl/d industry could completely displace eral months at rates approaching one-tenth the ca- the quantities of jet, diesel, and distillate heating pacity of commercial-size modules. Others are still fuels that are presently obtained from foreign at the laboratory or pilot-plant stages. The princi- sources in the entire Midwest. pal advantage of AGR processing is high oil recovery per unit of ore processed. However, with some ● With the present technical status of the critical mining methods, oil recoveries per acre may be retorting processes, deploying a major oil shale in- lower than with MIS. Surface disturbance is high- dustry would entail appreciable risks of techno- est with AGR because of the extensive surface fa- logical and economic failure. Although much R&D cilities, and because large quantities of solid has been conducted, and development is proceed- waste are generated. ing, the total amount of shale oil produced to date ● The physical and chemical properties of crude is equivalent to only 10 days of production from a shale oil differ from those of many conventional single 50,000-bbl/d plant. Because of its primi- crudes. However, depending on the nature of the tive status, much basic and applied R&D is needed upgrading techniques applied, the syncrude can for the TIS method. The MIS approach and some be a premium-quality refinery feedstock, compar- of the AGR processes are ready for the next stage able with the best grades of conventional crude. of development—either modular retort demonstra- Shale oil is a better source of jet fuel, diesel fuel, tions or pioneer commercial-scale plants. Such and distillate heating oil than it is of gasoline. Al- demonstrations would be costly, but they would though some technical questions remain, the up- substantially reduce the risks associated with the grading and refining processes are well-ad- much larger capital investments needed to create vanced. Refining shale oil may cost from $0.25 to an industry,

An Overview of Oil Shale Processing Converting shale in the ground to finished broken with explosives to create a highly fuels and other products for consumer mar- permeable zone through which hot fluids kets involves a series of processing steps. can be circulated; and Their number and nature are determined by ● AGR processes in which the shale is the desired mix of products and byproducts mined, crushed, and heated in vessels and by the generic approach that is followed near the minesite. in developing the resource. The alternative approaches are: Figure 19 is a flow sheet for the steps common to all three options. How the steps would ● TIS processes in which the shale is left be integrated in an AGR facility is shown in underground, and is heated by injecting figure 20. In the first step, the oil shale is hot fluids; mined and crushed for aboveground process- ● MIS processes in which a portion of the ing, or the deposit is fractured and rubbled shale deposit is mined out, and the rest is for in situ processing. The main product is Ch 5– Technology 121

Figure 19.– Oil Shale Utilization

Mining & Crushing Wastes & or In situ retort b preparation byproducts 7 Treated Re-Use ~ % * Reinfection m ~ water Discharge a ~ o

Y ? - # Wastes & Residues Retorting Treatment # \ Disposal byproducts T A ~ ~ @ 6 ~ Sulfur, NH3, Industrial ● * byproducts markets 7 1 f Wastes & Upgrading< byproducts

9 ‘ransportatonm ‘ef’n’ng l’=% “strbut”n t-+ C==l aMay not be nee~e(j for some in S1 tu methods

SOURCE Off Ice of Technology Assessment raw oil shale with a particle size appropriate that contain sulfur and nitrogen compounds. for rapid heat transfer. Nahcolite ore can be Depending on the extent of the treatment, the one of the various byproducts from this step. upgraded product—shale oil syncrude-can Dust and contaminated water are among its be a high-quality refinery feedstock, compar- wastes, In the retorting step, the raw oil shale able with the best grades of conventional is heated to pyrolysis temperatures (about crude. In the refining step, which may be con- 1,000° F (535° C)) to obtain crude shale oil. ducted either onsite or offsite, hydrogen is Other products are the spent shale residue, added to convert the syncrude to finished pyrolysis gases, carbon dioxide, contami- fuels such as gasoline, diesel fuel, and jet nated water, and in some cases additional fuel. The syncrude, or the crude shale oil, nahcolite and dawsonite ore. The crude shale could also be used directly as boiler fuel. oil may be sent to an upgrading section in After refining, the fuels are distributed to which it is physically and chemically modified consumer markets. Refining also produces to improve its transportation properties, to waste gases and various contaminated con- remove nitrogen and sulfur, and to increase densates. its hydrogen content. (Crude shale oils from some in situ processes may not need upgrad- To protect the environment, contaminated ing before transportation. ) Contaminated air water must be treated for reuse in the oil and water, and in some units refinery coke, shale facility, for reinfection into the ground are the wastes produced along with gases water aquifer source, or for discharge into 122 ● An Assessment of 01/ Shale Technologies

Figure 20.—The Components of an Underground Mining and Aboveground Retorting Oil Shale Complex

FUEL PRODUCTS AND BYPRODUCTS FROM UPGRADING UNITS . Low Sulfur Fuel Oil . Ammorwa ● Liquefied Petroleum Gas ● Sulfur . Coke

UPGRADING UNITS u RETORT UNITS

-— . . w- -. == . - . ,.- . + . . . .. < -– , ,... ., . Shade Convevors, !* .; ;...... : - - ““ -= - . ,—. .s. . Processed . ., /. - L

. . . . . — - Y \ . b, 7 “ . . - ‘ Catchment Dam HEADFRAME DISCHARGE / Surface Runoff STATION Water reused -.=. r~L ~

Roof Upper Bench ---:, .4*! Loading Dnllmg and Blasting x . -’ BOMng ScaImg ,. -1 .-. — ——

gr~~;g;$f~

—. —- - - .“ 1? .

SOURCE C b Shale 01 I Project Defa(led Deve/oprnenf Plan and Re/ated Mater/a/: Ashland 011, Inc and Shell 011 Co , February 1976, p 1-24 surface streams. Contaminated air and proc- bing) and dawsonite (a source of aluminum ess gases must be purified to meet Federal metal). In any case, spent shale from above- and State air pollution standards before they -ground processing must be moistened, com- can be discharged to the atmosphere. The pacted, and revegetated to prevent erosion waste gases from retorting, upgrading, and and leaching. Retorted shale in in situ retorts, refining are potential sources of ammonia and spent shale from surface operations that (for fertilizer and other uses) and sulfur (for is backfilled into underground openings, must sulfuric acid and many other materials). be protected from leaching by ground water. These can be recovered during the treatment steps and sold to industrial processors. In This chapter deals with the processing some portions of the Green River formation, technologies used in mining, retorting, up- the solid residues from mining and retorting grading, and refining. Technologies for treat- will contain nahcolite (which can be used to ing air, water, and solid wastes are discussed produce soda ash and for stack gas scrub- in chapter 8. Ch 5– Technology ● 123

Oil Shale Mining Both MIS and AGR require mining. In the the San Manuel copper mine in Arizona, case of AGR, the mined shale is conveyed to which yields about 50,000 ton/d of ore, About retorts where it is processed to recover shale 70,000 ton/d of 30 gal/ton oil shale would oil. With MIS, the shale may also be retorted have to be mined to support a single 50,000- aboveground, or it may be discarded on the bbl/d plant that used aboveground retorts. * surface as a solid waste. This mine would be substantially larger than Green River oil shale deposits are charac- the San Manuel mine. A 400,000-bbl/d indus- terized by their extreme thickness and by try of aboveground retorts would have to their extensiveness. The richer shale zones in mine about 560,000 ton/d—the equivalent of the Piceance basin, for example, are more 5 Bingham Canyon pits or 11 San Manuel than a thousand feet thick, in places, and are mines. If the same industry used only MIS, 2 about 230,000 to 460,000 ton/d would have to continuous over an area of 1,200 mi . Depos- be mined—the equivalent of four to seven its of this nature could be amenable to either ** Some of the mining surface mining (strip or open pit) or to under- San Manuel mines. ground mining methods (such as room and pil- techniques that could be used to achieve lar), depending on topographical features, ac- these levels of production are described cessibility, overburden thickness, presence of below. ground water in the mining zone, and many other factors. Surface mining may be feasible Surface Mining for very thick oil shale zones that are not deeply buried, especially if their average oil The two principal types of surface mining yield is not high, Because of the thickness of —open pit and strip—both have been widely the overburden, only a limited area of the used to develop coal seams and deposits of Piceance basin and somewhat more of the many other minerals. Their technical aspects Uinta basin and the Wyoming basins is amen- are fairly well-understood for these minerals. able to surface mining. In other areas, However, their feasibilities and effects vary streams have eroded gulleys and canyons with the nature of the ore body. Neither tech- through the shale beds, exposing some of the nique has yet been applied to the oil shales of richer shale zones. Shale that outcrops in the Green River formation. these areas, plus the shale in all deeply Surface mining is economically attractive buried beds, will probably be extracted by for large, low-grade ore deposits because it underground mining, permits high recovery of the resource and Despite the high price of crude oil, oil shale allows sufficient space for very large and ef- is a lean ore compared with many ores that ficient mining equipment. An open pit mine contain valuable metals. Economies of scale could recover almost 90 percent of the oil encourage massive mining installations, re- shale in a very thick deposit. Strip mining gardless of the mining method selected. A could provide even higher recoveries. In con- prospective developer once characterized trast, underground mining would recover less commercial-scale oil shale mines as “prodi- than 60 percent. One of the reasons that in- gious, ” because it connotated a larger size dustry’s bids on a lease for Federal tract C-a than “giant.’” A sense of this can be con- were so high was that the deposit could be veyed by comparing their capacities with those of more conventional mines. At present, *This assumes recovery of 100 percent of Fischer assay oil, the largest surface mine in the United States a recoverv efficiency that h:)s been achieved in tests of the is Kennecott Copper’s Bingham Canyon pit in “rOSCO 11 technology. **This assumes mining of 20 to 40 percent of the shnle in the Utah, which produces about 110,000 ton/d of retort volume, and an oil recovery of 60 percent of Fischer copper ore. The largest underground mine is assay. 124 ● An Assessment of 011 Shale Technologies mined by open pit methods. About five times wards to transmit the pressure without col- as much shale could be recovered by open pit, lapsing. which could have mined the entire deposit, Open pit mining was originally proposed than by underground room-and-pillar mining, for tract C-a by the Rio Blanco Oil Shale Co., which would have been limited to a relatively 2 the lessee. The pit was to have started in the thin zone. northwest corner of the tract, and eventually A mature open pit mine is shown in figure to have covered its entire surface. After a 21 and the steps in its operation in figure 22. few decades, freshly removed overburden In the first step, overburden is drilled and and spent shale from the aboveground retorts blasted loose over a large area above the oil would have been returned to the pit as back- shale zone. The burden is carried by trucks or fill. In the interim, the solid wastes would conveyors to an offsite disposal area. When have been disposed of on a highland to the enough burden is removed to expose the shale northeast of the tract boundaries. This con- beds, the shale itself is drilled and blasted, cept was abandoned when the Department of and is hauled from the pit for processing in the Interior (DOI) refused to allow offtract aboveground retorts. As mining proceeds, a waste disposal. Rio Blanco later switched to huge hole is formed, extending from the top of MIS techniques because the alternative—un- the overburden to deep into the oil shale de- derground mining—would have reduced re- posit. The walls of the pit are under pressure source recovery and threatened profitable from the overburden, and must be angled out- operations. * At present, there are no plans for any open pit mines, although Rio Blanco may reconsider its original plan if offsite dis- 3 Figure 21 .— An Open Pit Oil Shale Mine posal were allowed. In strip mining, overburden is removed with a dragline—a massive type of scraper shovel. When the dragline has filled its scoop, it pivots and dumps the burden into an adjacent mined-out area. One difference between open pit and strip mines is that in strip mining, the burden is simply cast into a nearby area; in open pit, it must be moved far from the minesite to prevent interfering with the development of the pit. Strip mining has not been proposed for any of the Green River deposits. Surface mining of most oil shale deposits is made difficult by the great thickness of the overburden that covers them. In the center of Off site disposal the Piceance basin, for example, the 2,000-ft- thick oil shale zones are buried under about Ov n 1,000 ft of inert rock and very lean oil shale. This does not necessarily preclude surface mining, because the deposits are generally characterized by a favorable stripping ratio—the ratio of overburden thickness to ore- body thickness. The thick beds in the center of the Piceance basin have 1 ft of overburden SOURCE Hear/rigs on 0// Sha/e Leasing, Subcommittee on Minerals, Materials, and Fuels of the Senate Commltee on Interior and Insular Affairs, 94th Cong 2d sess , Mar 17, 1976, p 84 *This change in plans is discussed in vol. 11, Ch 5–Technology 125

Figure 22.—Open Pit Oil Shale Mining

I Jl-.- OVERBURDEN I t 40 -– —“— “—— “

OIL SHALE 1

SOURCE U S Energy Oullook–An Ifrtenrn RePort The National Petroleum Council Washington D C 1972 for every 2 ft of oil shale—a stripping ratio of Underground Mining 1:2. With coal, a stripping ratio of 10:1 is often economically acceptable. A study by the Many underground mining procedures National Petroleum Council indicates that have been proposed for oil shale deposits5-10 open pit mining would be favored for strip- but to date only room-and-pillar mining and ping ratios between 2:1 and 5:1, strip mining mining in support of MIS retorting have been for smaller ratios, and underground mining tested at any significant scale. In room-and- for larger ratios than 5:1.’ pillar mining, some shale is removed to form large rooms and some is left in place, as pil- However, the economic principles of coal lars, to support the mine roof, The relative mining should be applied with caution to oil sizes of rooms and pillars are determined by shale. Removing 1,000 ft of overburden to re- the physical properties of the shale, by the cover 2,000 ft of shale might be possible in thickness of the overburden, and by the theory, but the pit’s boundaries would be so height of the mine roof. Most of the deposits extensive that it would have to be located on of commercial interest are very thick and a very large tract. Furthermore, the large have relatively few natural faults and fis- “front-end” investment in removing overbur- sures. The ore itself resists compression and den many years in advance of retorting would vertical shear stresses. These properties probably make open pit mining of deep depos- allow the use of large rooms, and relatively its uneconomical. Also, strip mining would little shale needs to be left as unrecoverable not be feasible in many parts of the oil shale pillars. region, even those with favorable stripping ratios, because the dragline would have to The U.S. Bureau of Mines (USBM) studied reach to the bottom of a 3,000-ft-thick layer of underground mining of oil shale at the Anvil overburden and oil shale. It is not clear that Points Experimental Station in the late 1940’s 11 such a machine could be built. and early 1950's. The primary purpose of 126 ● An Assessment of 011 Shale Technologies

the mining program was to supply raw shale mining plan proposed for Colony Develop- for the Bureau’s retorting experiments, but ment’s 46,000-bbl/d facility in the Piceance the program was also designed to develop a basin. 12 The rooms are 60 ft wide; the pillars safe, low-cost mining method. The room-and- are 60 ft square; and the mine roof is 60 ft pillar technique was adopted after extensive high. Mining is conducted in two 30-ft-high testing. From their studies, which included benches. The upper bench is mined first by enlarging the rooms until the roof failed, the drilling blastholes into the walls of a produc- investigators concluded that for safe mining tion room, and breaking the shale loose with conditions the rooms should be 60 ft wide explosives. The broken shale is carried by with pillars that are 60 ft on a side. trucks to the crushers where it is crushed to the size range required by the TOSCO 11 Many of the modern mine designs have aboveground retorts. The walls and the roof been patterned after the USBM experimental of the new room are then “scaled” to remove mine. The design depicted in figure 23 is the shale that was loosened by the blasting but

Figure 23.—The Colony Room-and-Pillar Mining Concept

SOURCE R W Marshall Colony Development Operation Room. andPlllar 011 Shale Mlnlng, ” Quarterly 01 the Colorado School o/ Mines, VOI 69, No 2 April 1974. PP 171 184 Ch 5–Technology ● 127 did not fall. Holes are drilled into the roof, coveries would be possible if the pillars were and roof bolts are inserted to assure its integ- subsequently mined out or if the mining were rity, thus protecting the miners from roof conducted on multiple levels. (See figure 24, ) falls. The USBM studies indicated that roof bolts would have to be installed in the access Figure 24. —Room-and-Pillar Mining passageways but not in areas that were ac- on Multiple Levels tively being mined. These production rooms would be vacated long before there was any serious danger of roof falls. & The lower bench is mined next, The sequence is similar except the blastholes are drilled into the floor of the upper bench, and additional roof bolting is not needed, The cy- \ cle of drilling, blasting, loading, scaling, and ~ Pillar roof bolting was designed to produce about . Room 66,000 ton/d of shale. About 60 percent of the , >ill shale in the mining zone was to be removed ~ Mining for processing in the aboveground retorts. Level The rest was to remain in the support pillars. Colony estimated that enough shale is present in the 60-ft seam to support the retorting facility for at least 20 years. The same type of mine was proposed by the Colony partners for development of tract C-b, after considering longwall mining, long-hole blasting, continuous mining, block caving, open pit mining, in situ processing, and many other options. The major advantages of the 13 SOURCE Hearing on 0// Shale Leas/rig Subcommittee on Minerals Materials room-and-pillar method were identified as: and Fuels of the Senate Comm It lee on I n Ierlo r and I n su Iar Affairs 94th Cong 2d sess Mar 17 1976 p 83 it is highly flexible and can easily be modified to accommodate new condi- The mine eventually would have extended tions, new equipment, or technological under the entire surface of tract C-b, as advances: shown in figure 25. However, the concept it can be highly mechanized and high was abandoned when it was discovered that overall production rates can be achieved the shale in the mining zone was highly frac- because many areas can be mined simul- tured—a condition that would have required taneously: large support pillars thus reducing resource the mine openings are relatively easy to recovery to uneconomic levels. All of the ventilate: original partners subsequently withdrew development of access passageways is from the tract, and it is now being developed also a production operation because oil by MIS methods by Occidental Oil Shale and shale would be removed; and Tenneco Oil Co. the mine could be designed to minimize Mining to prepare for MIS retorts is dis- surface subsidence. tinguished from room and pillar both by the disadvantages were the high cost of the volume of the deposit that is disturbed and by roof support system and the relatively low re- the configuration of the disturbed areas. As covery. In this regard, it was estimated that indicated, the underground mines both on the only 30 to 50 percent of the shale in a 75-ft- Colony property and on tract C-b would have thick interval could be recovered. Higher re- been developed in a 60-ft-high mining zone; .

128 ● An Assessment of 01/ Shale Technologies

Figure 25.—The Original Mine Development Plan for Tract C-b

#~– BoUNDARy OF TRACT C-B

...1

/ - :...--. 1------+------J- mlllr--nll-----~”--!n ‘- -- I , i ~I ~- ! I N ~ 1 i 1~------l------il ! II . 11 II - II1------!1: ,II II I 1 -.. .-. -. J . -. J 4111} 1- I t ‘------1 11 l--~ ‘-J: I I RAISE TO I o 20m 0: ~ ‘ uRFACE \ I I ~: I -i II 1--- ’’-----;1 ‘---”----1 ------‘ II Lc!_!_J[ i - ::::::T-- .- ., —— — —. I/_ EXHAUST I ST- / : 11111 -––- ‘- - - –-=---” / “ 7 SHAFT 1. /’ ~ ------.:- .“. 1 I sHAm, .tqw i I 1. , ‘ 1------,1 ‘-’ - Z%i‘ ?!’;’:;‘“i ‘ ] ‘ [....-..-:::-”:::::;T / r - - -... ~ - ~- ; ~-- -- .–. -- SHOP EXHAUST RAISES i 000000[ I I /[ I noooooc.--.._A. I ‘i I------. . . . . j II I I I I ~------II I! 11111 I I I l:%%% 1 L------j= PLANT 8SHA~ PILLAR - - } ‘ --- ”---; +i 1“--- ‘--- ‘ ‘\ I 11 I+w I ‘-

SOURCE C-b Shale 011 Project, Detaded Deve/OPmefrt plan and Relafed MaterlalS, Ashland 011, Iflc , and Shell 011 Co , February 1976, p IV-1 1 present plans for the MIS operations on in which the MIS retorts will be created, plus tracts C-a and C-b call for recovering oil from shafts from the surface for ventilation, drain- the shale in a 750-ft-high zone. However, the age, passageways for the miners, and trans- actual mining required to support this devel- portation of combustion air and retorting opment will take place in relatively confined products. Some of the mining plans are dis- areas. The mine will consist primarily of fair- cussed later in the section on MIS retorting ly small underground openings in the region methods.

Oil Shale Retorting The three generic methods for recovering True In Situ shale oil from oil shale deposits are described below. Brief discussions of some of the more The sequential steps in TIS processing are: significant R&D programs that have been conducted as part of their development are in- 1. dewatering, if the deposit occurs in a eluded. ground water area; Ch. 5–Technology ● 129

2. fracturing or rubbling if the deposit is of the Piceance basin where ground water not already permeable to fluid flow; has dissolved salt deposits to leave large 3. injection of a hot fluid or ignition of a rubble-filled zones. It is estimated to contain portion of the bed to provide heat for py- about 550 billion bbl of shale oil in place. 14 rolysis; and There are interconnected fractures and voids 4. recovery of the oil and gases through in other areas of the formation, but these, in wells. general, have only a very limited permeabili- The principles of TIS processing are illus- ty. The permeability of most of the zones that trated in figure 26. Several types have been appear to have commercial promise is essen- proposed that differ from each other with re- tially zero. Deposits that lie near the surface spect to the methods for preparing and heat- could be fractured by injecting water or ex- ing the deposit. All use a system of injection plosive slurries, but mining would probably and production wells that are drilled accord- be needed to increase the permeability of ing to a prescribed pattern. One that is com- deeply buried deposits. MIS or AGR proc- monly used is the “five-spot” pattern in which esses are more appropriate for the deeper re- four production wells are drilled at the cor- sources. ners of a square and an injection well is In 1961, Equity Oil Co. began developing a drilled at its center. The deposit is heated TIS process for the Leached Zone, which was through the injection well and the products tested in the Piceance basin between 1966 are recovered through the production wells, and 1968. It involved dewatering a portion of For efficient TIS processing, the deposit the zone followed by injecting hot natural gas. must be highly permeable to fluid flow, which Pyrolysis gases and a small amount of oil is true of portions of the Green River oil were swept in the natural gas stream to pro- shales. A good example is the Leached Zone duction wells through which they were

Figure 26. —True In Situ Oil Shale Retorting

1? 11 PRC‘DUC1NGWWQM13

SOURCE B F Grant Retorting 011 Shale Underground—Problems and Posslbllltles, ouarfedy of the Co/orado Schoo/ of M(nes VOI 59, No 3, July 1964, p 40 130 . An Assessment of 01/ Shale Technologies

pumped to the surface. The gas was sepa- of the fracturing techniques used have been rated from the oil, reheated, and reinfected chemical explosives, electricity, and injecting into the deposit. The oil had a much lower high-pressure air and water. These methods pour point, viscosity, and nitrogen content have been used to enhance recovery of con- than oils from aboveground retorts. * These ventional petroleum; oil shale fracturing favorable characteristics may have been re- poses a similar problem. Nuclear explosives lated to the solvent properties of the natural were also proposed in the 1960’s, but were gas, and to the absence of oxygen from the re- not tested because of their potential for harm- torting zone. The quality of the retort gases ing the environment, A nuclear test—Project was also good, partly because of their natural Rio Blanco—was conducted in the Piceance gas component, and partly because during re- basin to fracture sand formations containing torting combustion and the decomposition of natural gas. The test failed. carbonate minerals were minimal. ** The earliest TIS work was by Sinclair Oil Process development was not pursued be- Co., between 1953 and 1966. A thin section of cause too much of the natural gas was lost in shale in the Mahogany Zone of the Piceance the unconfined formation. In 1968, Atlantic basin was fractured by injecting air. The bed Richfield Co. (ARCO) purchased an interest in was ignited, although with difficulty, and a the process and resumed its development. In small quantity of shale oil was collected be- 1971, a revised concept was announced in fore the hot shale swelled and sealed the which superheated steam, rather than natu- fractures. After additional tests, Sinclair con- ral gas, was to be used to heat the deposits. In cluded that the zone’s limited permeability 1977, DOE contracted with Equity to test the would not permit profitable operations. * concept in a 50()-f t-thick seam in the Leached Research on TIS processing began at Zone of the Piceance basin. The seam under- USBM in the early 1960’s. In 1974, the pro- lies about 0.7 acre of surface, and contains grams and personnel were transferred to the about 700,000 bbl of oil in place. It has been Energy Research and Development Adminis- estimated that as much as 300,000 bbl could tration, and in 1978, they moved to DOE. The be recovered over a 2-year period, with about R&D programs have included laboratory ex- half of the oil produced in the first 7 months. ’s periments, computer simulations, pilot-plant Steam injection has begun at the site, and will studies, and field tests. Among the latter continue through 1981. No detailed estimates were tests of electrical, hydraulic, and ex- have yet been released of production rates or plosive fracturing and combustion retorting retorting efficiency. If the process proves to near Rock Springs, Wyo. These revealed be technically and economically feasible, it some of the problems associated with the TIS could be applied in portions of both the Pice- approach. In one early test, for example, ance and the Uinta basins. after inert gas at about 1,300° F (7050 C) was At present, no work is being done in slight- pumped into a fractured formation for a peri- ly fractured formations, but much research is od of 2 weeks, about 1 gal of shale oil was re- being performed to develop methods for in- covered. In another experiment in a zone that creasing their permeability by enlarging nat- contained 7,800 bbl of shale oil in place, it ural fractures and creating new ones. Some was estimated that only 60 bbl of the close to 1,000 bbl that were released were actually *rI’hese properties have economic significance. Pour point is recovered. the lowest temperature at which oil will flow. Oils with high pour points are hard to transport because they solidify at nor- Low oil recoveries are often associated mal ambient temperatures. Viscosity is a measure of a fluid ”s with TIS processing because of the large im- resistance to flow. Oils with high viscosity are expensive to pump. Reducing the high nitrogen content of most crude shale oils consumes hydrogen, which is costly. *rI’he results of a mathematical simulation indicated that **Both of these processes produce carbon dioxide, which is about 18 years of continuous steam injections would be re- a major constituent of gases produced by some above-ground re- c~uired to heat the shale to pyrolysis temperatures within a 30- torts. ft radius of a fracture. Ch 5–Technology ● 131 permeable blocks of shale in the fractured process can be demonstrated for thin depos- formation. These cannot be fully retorted in a its that are covered by less than 100 ft of reasonable length of time. Irregular fractur- overburden. It has been estimated that there ing patterns that can cause the heat carrier are at least 6 billion bbl of shale oil in place in to bypass large sections of the deposit are this type of deposit. It is common in the Uinta another problem. Oil shale that is located in basin,16) and at present, would be most eco- the bypassed regions will not be retorted, nomically developed by strip mining. And, even if all of the shale in a fractured area were retorted, much of the oil would not Geokinetics has been investigating the sur- reach the production wells, but would remain face uplift approach since 1973, and is pres- trapped in the pores of the spent shale or ently burning its 20th retort in Utah. The would diffuse beyond the production wells, to largest retort prior to 1979 measured 130 ft be lost in surrounding areas. by 180 ft by 30 ft thick. A retort about 200 ft on a side and 30 ft thick will be required to To develop methods for improving recov- demonstrate the technical feasibility of the ery, an extensive R&D program has been con- process. By 1982, DOE and Geokinetics hope ducted at the Federal research center in Lar- to have developed a commercial-scale opera- amie, Wyo. Aboveground batch retorts with tion with a production capacity of 2,000 capacities of both 10 and 150 tons of shale bbl/d.17 have been used to simulate in situ retorting, but under more controlled conditions than ex- Modified In Situ ist underground. Oil recoveries of up to 67 percent have been achieved, and an experi- In MIS processing, the permeability of oil ment in a “controlled-state” retort achieved shale deposits is increased by mining some 95-percent oil recovery. * shale from the deposit and then blasting the In 1976 and 1977, the program was ex- remainder into the void thus created. The panded to include field tests of different frac- two-step process is depicted in figure 27. In turing and retorting techniques under cost- the first step, a tunnel is dug to the bottom of sharing contracts with Equity Oil, Talley - an oil shale bed, and enough shale is removed Frac, Inc., and Geokinetics, Inc.** The Equity to create a room with the same cross-section- program has been described. The Talley-Frac al area as the future retort. Holes are drilled program was terminated after the fracturing through the roof of the room to the desired method failed. The Geokinetics process uses a height of the retort. They are packed with ex- fracturing technique called surface uplift in plosives that are detonated in the second which an explosive is injected into several step. A chimney-shaped underground retort wells and detonated to fracture the shale and filled with broken shale results. The access make it permeable to fluid flow, The shale is tunnel is then sealed, an injection hole is ignited by injecting air and burning fuel gas drilled from the surface (or from a higher through one well. It is pyrolyzed by the heat mining level) to the top of the rubble pile. The that sweeps through the bed in the gas pile is ignited by injecting air and burning stream, Oil and gases are pumped to the sur- fuel gas, and heat from the combustion of the face through outlying production wells. It is top layers is carried downward in the gas hoped that the technical feasibility of the stream. The lower layers are pyrolyzed, and the oil vapors are swept down the retort to a *rI’he large retorls resemble the classic Newia-Tex:]s-Utah sump at the bottom from which they are (N’I’U) retort that is described later in this chapter. Because of pumped to the surface. The burning zone the higher percentage of void volume in the rubble, these retorts provided better simulations of hlIS processing thtin of moves slowly down the retort, fueled by the ‘1’1S. “1’he controlled-state retort was much smfiller and was residual carbon in the retorted layers. When equipped for better cent rol of retortin~ renditions. the zone reaches the bottom of the retort, the **Tbe procurement also included a contract with Occidental Oil Shale, Inc., to develop its MIS process, which is discussed in flow of air is stopped, causing combustion to the next section. cease. 132 An Assessment of Oil Shale Technologies

Figure 27. —Modified In Situ Retorting

STEP A STEP B GAS TO ---– –~ PURIFICATION ~~, ~BLOWER RECYCLE GAS . .COMBUSTION — AIR .—

OVERBURDEN OVERBURDEN / — ,- d:——. F--- ~7— 7– 7— BLASTHOLES ,/,/ /, ’ <-b-, .< , /‘, , / //, ,/ ‘/ ‘/ ,/ ,!’ , /// , , /,/ 1:/ (![, ‘,,/ /, // ,’/ , / {’/// k, . J nv’ ] //,/1‘ ‘ i \ RUBBLED SHALE

LEAN SHALE ‘/////Al REMOVED FOR

//////l I OR DISPOSAL

/ P-——————=——————”’

SOURCE T A Sladek Recent Trends In 011 Shale — Part 2 Mlnlng and Shale 011 Extraction Processes Mjnera/ /rrdus/rles Bu//e/lrr VOI 18 No 1 January 1975, p 18

Occidental Oil Shale, Inc., a subsidiary of Occidental Petroleum (Oxy) has demonstrated the MIS process, 18 Oxy’s work began in 1972 on the D. A. Shale property along Logan Wash—a private tract on the southern fringe of the Piceance basin about 50 miles northeast of Grand Junction, Colo. To date, six retorts have been burned at the site, with varying degrees of success. The first retort was about 32 ft on each side and 70 ft high. About 60 percent (1,200 bbl) of the shale oil in place was recovered, comparable to the best results from USBM’s experiments at Lara- mie, The next two retorts were slightly larger, and performed similarly, The fourth retort was of nearly commercial size—120 ft on each side and 270 ft high. It contained about 32 times as much shale as the first retort and yielded about 25 times as much oil. The fifth was the same size but was designed for a much lower void volume. The rubbling

Phofo credif OTA staff step did not evenly distribute the void volume, and the performance was poor. Only 40 per- Head frame at tract C-a cent of the oil was recovered. The burning of Ch 5–Technology ● 133 retort 6 began in 1978, but the sill pillar—the wall mining or mechanical underreaming, layer of unbroken shale that caps a retort— could be used in other areas. It might be pos- collapsed into the rubble pile. Operations sible to operate mechanical underreaming were disturbed while the top was resealed, machines by remote control from the surface, but retorting was eventually completed, and thus reducing or even eliminating the need about 40 percent of the oil was recovered. for miners to work underground. None of DOE will share the costs of retorts 7 and 8, these approaches has been tested in any oil which are scheduled for 1980 and 1981, shale deposit. The oil shale at the Logan Wash site is not Other MIS techniques that use vertical- considered to be of commercial quality be- burn patterns have also been developed. For cause of its low kerogen content. In 1976, Oxy example, the firm of Fenix and Scisson de- acquired access to the higher quality resigned two systems for underground mining, sources of tract C-b by exchanging its tech- rubbling, and retorting in the vertical mode. z’) nical knowledge for a half interest in the To date, they have been tested only with a lease. In 1978, Ashland Oil Co., Oxy’s partner computer model. DOE’S Lawrence Livermore in the C-b Shale Oil Venture, withdrew and Laboratory has also developed an MIS tech- left Oxy in full charge. In 1979, Tenneco Oil nique called rubble in situ extraction (RISE) Co. purchased a half interest in the lease for with the aid of computer simulation and lab- $110 million and is proceeding to develop the oratory experiments in pilot-scale above- tract in cooperation with Oxy, If present -ground retorts.21-23 (See figure 28. ) Several plans are followed, Oxy’s technology could be levels are mined, and a portion of the deposit used to produce about 57,000 bbl/d by 1985. is removed at each. The remaining shale is Oxy’s technique uses a vertical burn con- broken with explosives. Sufficient broken figuration— that is, the combustion zone pro- shale is then removed so that there is a total gresses vertically through the shale bed. It is void volume of 20 percent in the retort area. also theoretically possible to advance the The rubble is then ignited at the top, and re- burn front horizontally, in much the same torting proceeds as in the Oxy system. way as it is done in TIS processing. A crude The RISE approach was originally pro- version of this approach was implemented in posed by Rio Blanco Oil Shale Co. for tract Germany during World War II, when a few C-a, but the firm is now going ahead with its MIS retorts were created by digging tunnels own process, which has benefited from tech- into oil shale deposits and then collapsing nical information acquired under a licensing their walls into the void volume. These opera- arrangement with Oxy. Livermore’s modeling tions were short-lived because oil recoveries studies and laboratory experiments are con- were extremely low, and they were very hard tinuing. to control. 19 The initial plans for developing tract C-a by Horizontal MIS might be practical if a tech- MIS methods are shown in figure 29. They nique could be developed to remove large sec- would have involved five precommercial re- tions of oil shale strata. One possibility is to torts of increasing size. The present plan, use solution mining: the injection of fluids into which was adopted after purchase of Oxy’s the formation to dissolve soluble salts from MIS technology, is shown in figure 30. In the among the oil shale layers, The result would new development plan, a small pilot retort be a honeycomb pattern of voids that could (retort “O”) will be followed by two demon- then be distributed throughout the area to be stration retorts of increasing size. The largest retorted by injecting and detonating an explo- (retort “2”) will be close to commercial scale. sive slurry. This method would be limited to Several options of different size are being areas like the Leached Zone or the Saline considered for retort 2, with one option a re- Zone that contain significant concentrations tort with dimensions 60 ft by 150 ft by 400 ft of soluble salts. Other methods, such as long- high, The method by which the shale is rub- 134 An Assessment of Oil Shale Technologies

Figure 28.—The RISE Method of MIS Oil Shale Retorting . — --- —-- —--- —- ——— ~“” ~~~--.—-~ --- -—-—-— ‘- .—.— =.

/ / -/5 OIL OUT /

A. Isometric

I 1 I

. . . . . ? .“ .“.’.s+ I 1 Development proceeds simultaneously on several levels. At each Level A level, horizontal drifts are driven the full width of the retort block, and a vertical slot is bored to provide void volume for blasting. About 200/. of the broken shale is removed after each blasting operation. The rest is left in the retort volume. (1 . . . . : Sublevel Level B 4 Starting slot ...... ~Leve’c‘“’”””””””””””””’!!;:- B. Elevation

SOURCES: 01/ Shale Retorting Technology, prepared for OTA by Cameron Engineers, Inc., 1978; and C. K. Jee, et al., Rewew and Analyws of Od Shale Techno/ogy— Vo/ume 3. Mod/tied In Situ Tec/rrro/ogy, report prepared for the U.S Department of Energy by Booz-Allen & Hamilton, Inc , under contract No, EX-76-C- 01-2343, August 1977, p. 6. Ch 5–Technology ● 135

Figure 29.— Initial Modular MIS Retort Development Plan for Tract C-a

COMMERCIAL FIELD 2 1 ,, .’ ~., ,. - .- r c’ ‘r) / ‘> t -“

SOURCE RIO Blanco 011 Shale Project Revised Deta~/ed De~e/OP~eflt P/an Tracf C a Gulf 011 Corp and Standard 011 Co (Indiana), May 1977 P 125 bled, and the fraction of the shale that is volume before the next higher layer is mined from each retort area are two of the blasted. Through this technique, Rio Blanco major differences between the Rio Blanco ap- hopes to obtain uniform size distribution in proach and Oxy’s technique. Oxy has tested the rubble. This is believed to be a key techni- several rubbling methods, including drilling cal requirement for efficient MIS retorting. blastholes up from a room at the bottom of the Rio Blanco also proposes to mine twice the retort, drilling down from the top, and boring volume (40 v. 20 percent) as is contemplated a central shaft the full length of the retort by Oxy. and then blasting the surrounding shale into the shaft. In Rio Blanco’s approach, a room will be created at the bottom of the future re- Another MIS method that is still being de- tort, blastholes will be drilled from the sur- signed is the integrated in situ technology pro- face into the roof of the room, and explosives posed by Multi Mineral Corp. for recovering will be detonated sequentially at different shale oil, nahcolite, alumina, and soda ash levels, The shale above the room will thereby from oil shale deposits in the Saline Zone of be blasted loose in layers, with each layer of the Piceance basin. This zone underlies the rubble falling to the bottom of the retort Leached Zone, is relatively free from ground 136 ● An Assessment of Oil Shale Technologies

Figure 30.— Present MIS Retort figure 31, If technical and economic feasibili- Development Plan for Tract C-a ty is indicated during the test program, Multi Mineral would proceed to a commercial-scale \ Down-Hole facility that would produce 50,000 bbl/d of shale oil, 10,000 ton/d of nahcolite, 1,000 ton/d of alumina, and 20,000 ton/d of soda ash. The Multi Mineral approach resembles the

Escape% Shaft RISE technique in that mining and rubbling are conducted at several levels along the Ventilation Shaft height of the retort, It departs from RISE in Off-Gas Shaft that, after rubbling, the broken shale in the retort is removed from the bottom, crushed I’HF- Access Shaft and screened, and returned to the top in a continuous operation. This part of the retort development plan is shown in figure 32. The rubbled shale will contain free nahcolite and

+1 I I Ill II II II z SeDarator %= Figure 31 .— Retort Development Plan for the Multi Mineral MIS Concept

CROSS CUT

-- (LEVEL B) .-

SOURCE The Pace Co Consultants and Engineers Inc Cameron Synthe(lc Fue/s Report VOI 16 No 3 September 1979 p 28 water, and contains extensive resources of nahcolite and dawsonite in addition to oil shale. Development is hindered because the zone is deeply buried (about 2,000 ft) below the surface of the basin. To reduce the costs of its R&D program, Multi Mineral has proposed to use an 8-ft-diameter shaft that was drilled by USBM in 1978 through the Leached Zone and into the Saline Zone. In the first phase, mining and mine safety methods will be tested, and about 8,000 tons of nahcolite and 11,000 bbl of shale oil will be produced. The nahcolite will be used for stack-gas scrubbing tests in a powerplant. In the sec- (LEVE~D; ond phase, a retorting module will be used to -- produce up to 3,000 ton/d of nahcolite, 10,000 bbl/d of shale oil, 200 ton/d of alumina, and STOPE FLOOR SOURCE B Welchman, Sa//ne Zone 0// Sha/e Deve/opmen/ by [he /nlegrated 3,000 ton/d of soda ash. The modular retort /n S/fU Process Multi Mineral Corp Houston Tex December 1979. and the access shafts and drifts are shown in p9 Ch 5– Technology ● 137

Figure 32.— Preparation of a Multi Mineral residual carbon, and soda ash and aluminum MIS Retort oxide—the products of the thermal decomposition of dawsonite. The last three products remain in the retort rubble. In retort 2, the re- < HOLE NO. 1 sidual carbon is being gasified by injecting a mixture of steam and air. The heat from the gasification reaction is carried to retort 3. In HOLE NO. 2 ➤ retort 1, the hot gasified shale is being cooled by passage of cold recycle gas. The heat thus BACKFILLED n recovered is conveyed to retort 2. After the I shale in retort 1 is cooled, the soda ash and the aluminum oxide can be leached out with water. The leachate is then pumped to the surface and processed to recover its mineral SHAFT values.

Temperature control is the key to the entire operation. Oil alone could be recovered with a combustion-type method, such as Oxy’s, but because of the high temperatures, the decom- 2200’ position of the dawsonite would produce com- \)/ LEVEL pounds insoluble in water. The gas-recycle \ heating method would avoid this problem by maintaining lower retorting temperatures. The operation also depends on the ability of explosive rubbling techniques to produce broken shale that can be fed to conventional crushing equipment. Overall, the method is very interesting because of its potential for w \ simultaneously recovering fuel and minerals from deposits that may not be accessible with SOURCE B We(c hman Sa/~ne Zone O() Shd/e Deve/oprnent by fhe /nlegrd(ed In SJtu Process M u It I M I neral Corp H o uston Tex December 1979 any other approach. However, too little is D 15 known about the various steps to permit a nahcolite that is still associated with the thorough evaluation at this time. large blocks of shale. Crushing will liberate most of the associated nahcolite, and screening will separate it from the shale particles. Aboveground Retorting The shale will be backfilled to the top of the Hundreds of retorts have been invented in retort; the nahcolite is transported to the sur- the 600-year history of oil shale development. face for processing. The result would be a re- Most were never brought to the processing tort that is filled with uniformly sized oil shale stage but some were tested using laboratory- particles. With this configuration, Multi Min- scale equipment, and a few at pilot-plant and eral hopes to avoid the channeling and by- semiworks scales. None has been tested at a passing problems that may occur in TIS and scale suitable for modern commercial opera- MIS processing. tions. This section summarizes the technical In a commercial-scale facility, the retorts aspects of seven retorting systems that offer would be operated in sets of three, as shown the promise of being applicable in the near in figure 33, In retort 3, the oil shale is being future. One obsolete technology that is the pyrolyzed by injecting hot gases to produce basis for several of the modern systems is shale oil (which is removed to the surface), also discussed.

l–< ... -1 138 ● An Assessment of 01/ Shale Technologies

Figure 33.— A Set of Multi Mineral MIS Retorts

EXCESS GAS RETORT 1 RETORT 2 (RETORT 3 (HEAT RECOVERY) (CARBON RECOVERY) (PYROLYSIS) IIt COLD RECYCLE GAS I ‘;

TK======--====-=------=="*----=---*==------; I il ,1 II IIi

OIL I ‘1t 1, 1, 1, ;1 Ii 1, I ,1t

------a

SOURCE B Welchman, Sa//rre Zone” 0(/ Shale Deve/oprnerrf by the Irrtegrafed In SIfu Process, Multl Mineral Corp , Houston, Tex December 1979, p 11

Although aboveground retorts differ wide- They include the Nevada-Texas-Utah ly with respect to many technical details and (NTU) and Paraho direct processes de- operating characteristics, they can be scribed below, and also USBM’s gas grouped into four classes: combustion retort and the Union “A” retort. Class 2 retorts produce a spent Class 1: Heat is transferred by conduc- shale low in residual carbon and low-Btu tion through the retort wall. The Pump- retort gas. Their thermal efficiencies are herston retorts used in Scotland, Spain, high because energy is recovered from and Australia were of this class, as is the retorted shale. However, recovery the Fischer assay retort that was devel- efficiencies are relatively low—about 80 oped in the 1920’s. It is a laboratory to 90 percent of Fischer assay. device for estimating potential shale oil yields. Its oil yield is the standard to ● Class 3: Heat is transferred by gases which the retorting efficiencies of all that are heated outside of the retort ves- other retorts are compared. Because sel. Retorts in this class are also called conduction heating is very slow, no mod- indirectly heated. They include the Para- ern industrial retorts are in class 1. ho indirect, Petrosix, Union “B,” and Su- Class 2: Heat is transferred by flowing perior retorts discussed below, and also gases generated within the retort by the Union SGR and SGR-3, the obsolete combustion of carbonaceous retorted Royster design, the Soviet Kiviter, the shale and pyrolysis gases. Retorts in this Texaco catalytic hydrotort, and others. class are also called directly heated. These retorts produce a carbonaceous Ch. 5–Technology ● 139

spent shale and a high-Btu gas. Thermal oil. Three units that were operated in Austra- efficiencies are relatively low because lia during World War 11 produced nearly energy is not recovered from the residu- 500,000 bbl. As noted previously, USBM used al carbon, but oil recovery efficiencies two units to simulate in situ retorting. are high, from 90 to over 100 percent of The operating sequence for the NTU retort Fischer assay. is shown in figure 34. The unit is loaded with ● Class 4: Heat is transferred by mixing crushed oil shale and sealed. The gas burner hot solid particles with the oil shale. is lighted, and air is blown in. Once the top of They include the TOSCO II and Lurgi- the shale bed is burning (step A), the fuel gas Ruhrgas retorts described below, and is shut off but the air supply continues. As the also the Soviet Galoter retort. Class 4 re- air flows through the burning layer, it is torts achieve high oil yields (about 100 heated to approximately 1,500° F (815° C). percent of Fischer assay) and produce a This hot gas heats the shale in the lower lay- high-Btu gas. The spent shale may or ers and induces the pyrolysis of the kerogen. may not contain carbon, and thermal ef- The oil and gases produced are swept down ficiencies vary, depending on whether through the cooler portions of the bed to the the spent shale is used as the heat car- exhaust port (step B). The solid product from rier. The retorts are sometimes referred the conversion of the kerogen (residual car- to as indirectly heated, as in class 3, be- bon) remains on the spent shale and is con- cause they also lack internal combus- sumed as the combustion zone moves down tion, and produce a similar gas product. the retort, providing fuel for additional com- Several other conversion methods have been bustion and thereby heat for additional pyrol- developed that cannot easily be placed in ysis. When all the carbon is burned from the these classes. These include microwave heat- upper layers of the bed, the four zones shown ing, bacterial degradation, gasification, and in step C are formed. The top layer contains circulation of hot solids slurries. Although burned and decarbonized spent shale. The some of these processes have potentially val- second layer is burning, releasing heat for py- uable characteristics, they will not be dis- rolysis in the third layer. In the bottom layer, cussed in this section because they have not the shale is being heated but is not yet at py- yet been proposed for near-term commercial rolysis temperatures. application. As time passes, the top layer expands downward and the lower three zones move The Nevada-Texas-Utah Retort uniformly down the retort. When the leading edge of the combustion zone reaches the ex- The NTU retort is a modified downdraft haust port, oil production ceases, air injection gas producer similar to units used in the 19th stops, and the retort is emptied. The dumping century to produce low-Btu gas from coal. It of spent shale ash from the 40-ton NTU at is a vertical steel cylinder, lined with refrac- Laramie is shown in figure 35. The entire tory brick and equipped with an air supply cycle, from ignition to dumping, takes about pipe at the top and an exhaust pipe at the bot- 40 hours. tom. The top may be opened for charging a batch of shale; the bottom for discharging the NTU retorts are simple to operate, and re- spent shale after retorting. The unit was de- quire no external fuel except for small veloped and tested for oil shale processing by amounts of gas to start the retorting. They the NTU Co. in California in 1925, and was can process a wide variety of shales with oil also tested by USBM at Rifle, Colo., from 1925 recoveries ranging from 60 to 90 percent of to 1929. Two units with nominal capacities of Fischer assay. They are unsuitable for mod- 40 tons of raw shale were built and operated ern commercial applications because they by USBM at Rifle between 1946 and 1951. are batch units with high labor costs and They produced more than 12,000 bbl of shale small capacities. Over 600 150-ton retorts — .

140 ● An Assessment of 011 Shale Technologies

Figure 34.—The Operation of an NTU Retort

AIR SUPPLY — AIR SUPPLY AIR SUPPLY BLOWER BLOWER BLOWER

rGAS BURNER: ON GAS BURNER: OFF rGAS BURNER: OFF h- SHALE IGNITES: /%- ECOMBUSTION ZONE; SPENT SHALE ZONE: ED RESIDUAL CARBON BURNS } ALL RESIDUAL CARBON IN AIR STREAM BURNED PYROLYSIS ZONE: COMBUSION ZONE: KEROGEN CONVERSION RESIDUAL CARBON } WITHOUT FURTHER \ BURNING COMBUSTION \ N!!iN PYROLYSIS ZONE; KEROGEN CONVERSION N BURNER GAS AND 1 SHALE OFF-GAS ‘+ HEAT REMAINING PREHEAT ZONE: SHALE SHALE HEATED BY ) OFF-GAS TO BELOW l\ II PREHEAT ZONE; PYROLYSIS TEMPERATURE { ( ~1~1 \\ y

1- BURNER FLUE GAS LOW-BTU GAS AND OIL MIST Yt LOW-BTU GAS AND SMOKE, AND FUMES TO SEPARATION EQUIPMENT OIL MIST

STEP A STEP B STEP C

SOURCE T A Sladek, Recent Trends In 011 Shale– Part 2 Mining and Shale 011 Extract Ion Processes, M(nera/ /ndustr/a/ Elu//ef/n VOI 18 No 1 January 1975 p 5

would be needed to produce 50,000 bbl/d of to the gas combustion technology but it is crude shale oil. In contrast, plants using some more likely to be commercialized.-It was de- of the continuous technologies described be- veloped by Development Engineering, Inc., low would require only about six retorts for (DEI) in the late 1960’s, and was tested for the same production capacity. limestone calcining in three cement kilns in South Dakota and Texas. Each kiln had a ca- The Paraho Direct and Indirect Retorts pacity of 330 ton/d and was comparable to the largest gas combustion retort tested by An NTU retort becomes a Paraho direct re- the six oil companies. tort when it is turned upside down, made continuous, and mechanically modified. The Par- After verifying the solids-flow character- aho retorts are based on USBM’s gas combus- istics of the Paraho technology in the lime- tion retort which, in turn, evolved from the stone kilns, DEI leased the Anvil Points site NTU retorts tested at Anvil Points in the late from the Federal Government in May 1972, 1940’s. The gas combustion process was and began a 5-year program to develop the tested in 6-, 10-, and 25-ton/d units by USBM technology for oil shale processing. Funding between 1949 and 1955, and by a consortium was obtained from a consortium of 17 energy of six oil companies between 1964 and 1968. companies and engineering firms. In return The Paraho direct retort is similar in design for a contribution of $500,000, each company Ch 5– Technology ● 141

Figure 35.— Discharging Spent Shale Ash From a 40-Ton NTU Retort

I I , , " ". .. • -:. -. • ~ ~ ~I' I • ./ • '; fi i. ; ... I ....., II

\ ',' , .,. .. ~ .. _.1 ~. .

SOURCE U S Department of Energy 142 ● An Assessment of 0il Shale Technologies was guaranteed a favorable royalty arrange- Figure 36.— The Paraho Oil Shale Retorting System ment in any subsequent commercial application of DEI’s technology. The Paraho Develop- RAW SHALE ment Corp. was formed to manage the proj- 1 OIL MIST ect. * Two retorts, a pilot-scale unit 4.5 ft in SEPARATORS diameter and 60 ft high and a semiworks unit ---- -—- 10.5 ft in diameter and 70 ft high, were in- MIST FORMATION stalled and tested after August 1973. They AND PREHEATING were used to produce over 100,000 bbl of - — ---- crude shale oil, some of which was used for ltl- OIL RETORTING OIL refining and end-use experiments by DOE (?ZONE w PRODUCT ru and the Department of Defense. Maximum GAS ELECTROSTATIC throughput rates reached about 400 ton/d in I-- — - --- I t PRECIPITATOR F 1 the semiworks unit. Both direct and indirect COMBUSTION RECYCLE GAS ZONE BLOWER heating modes were tested. - i ----—- 4 RESIDUE The Paraho retort is shown in figure 36, COOLING and the Anvil Points semiworks unit in figure AND GAS 37. In its direct mode, the retort is very simi- PREHEATING AIR BLOWER \ --- —-- lar to the older gas combustion design. How- ● 4 t * A A ever, significant differences exist in the shale /v feeding mechanism, in the gas distributors, ~ SpEED CONTROLLER‘y and in the discharge grate. During operation, RESIDUE raw shale is fed to the retort through a rotat- A. Direct Heating Mode ing distributor at the top. It descends as a moving bed along the vertical axis of the re- RAW tort. As it moves, it is heated to pyrolysis tem- SHALE peratures by a rising stream of hot combus- OIL MiST tion gases. The oil and gas produced are SEPARATORS swept up through the bed to collecting tubes and out of the retort to product separation MIST FORMATION equipment. The retorted shale retains the re- AND sidual carbon. As the shale approaches the PREHEATING ——-—- — [ ~OIL burner bars, the carbon is ignited and gives RETORTING OIL ZONE off the heat required for pyrolyzing addition- L — STACK al raw shale. Passing beyond the burner bars, GAS ELECTROSTATIC --—- —- t < HEATER PRECIPITATOR the shale is cooled in a stream of recycle gas 0 HEATING T and exits the bottom of the retort through the i RECYCLE GAS — BLOWER discharge grate. It is then moistened and sent ------t to disposal. RESIDUE COOLING PRODUCT GAS The retort may also be operated as a class AND GAS 3 retort. The configuration would resemble ~REHEATIN$ AIR BLOWER —— —-- directly heated operations except that air c?- would not be injected and the offgas steam would be split into four parts after oil separa- ‘)1( tion. One part would be the net product gas. RESIDUE Another would be sent through a reheating B. Indirect Heating Mode furnace and then reinfected into the middle of SOURCE C C Shlh, et al Techno/ogma/ Ovefv)ew Reporfs for Eight Sha/e 0// Recovery Processes report prepared for the U S Environmental Pro- *“ Paraho” is from the Portuguese words “para homen”’— tection Agency by TRW under contract No EPA.600/7.79-075 March for mankind. 1979, pp 20 and 23 Ch 5– Technology ● 143

Figure 37.— The Paraho Semiworks Unit at Anvil Points, Colo.

. , ... ..~ -...;...t-'l..,. _ .-:- "

-. , """ '. '" . t

"I '" oft,. .'

• I - ~ '" .

SOURCE Paraho Development Corp 144 ● An Assessment of Oil Shale Technologies the retort. A third would not be reheated but tion plant near the city of Sao Mateus do Sul would be reinfected through the bottom of the in the State of Parana. In the second stage, retort to cool the shale before discharge. The the full commercial plant would be built on fourth would be used for fuel in the reheating the same site, to include 20 Petrosix units, furnace. All heat for kerogen pyrolysis would each about 33 ft in diameter. Brazil is not be provided by the reinfected gases, and no committed to either stage, but if financing is combustion would occur in the retort vessel obtained in 1980, the first stage could be com- itself. pleted by 1983 and the second by 1985. In addition to the shale oil, the plant would To date, the Paraho retorting technology also produce sulfur and liquefied petroleum has been tested at about one-twentieth of the gases. Preliminary plans are also being pre- size that would be used in commercial plants. pared for two additional commercial-scale Paraho would like to test a full-size module plants south of the present demonstration producing about 7,300 bbl/d at Anvil Points, plant in the State of Rio Grande do Sul. and has submitted a proposal to DOE for such a program. Both direct and indirect heating Except for mechanical differences, the modes would be tested. Permission has been Petrosix retort is very similar to the Paraho obtained from the Department of the Navy to indirect retort described above. This similari- use large quantities of shale from the Naval ty is not surprising in view of the shared engi- Oil Shale Reserves for the program. An envi- neering heritage of the two systems. One ronmental impact statement (EIS) is being operational difference is that the Petrosix prepared for the project. Paraho has re- spent shale is discharged into a water bath sponded to a DOE Program Opportunity No- and pumped in a slurry to a disposal pond. tice for a $15 million engineering design study Paraho shale is discharged dry, with only a of modular oil shale retorting, and would little water added prior to disposal. base the design of the Anvil Points module on results of the study. Outcome of the procure- Little information has been released about ment has not yet been announced. the demonstration program. Oil characteristics have been described, but these have little The Petrosix Indirectly Heated Retort relevance to the processing of Green River shale. It can be predicted that the retort The Petrosix process was developed for the should have high oil recovery efficiencies and Brazilian Government by Petrobras, the na- produce a retort gas with high heating value. tional oil company, with the assistance of The spent shale would be carbonaceous. In Cameron and Jones, Inc., a U.S. engineering the demonstration plant, recovery of energy firm, Russell Cameron, later president of from the spent shale was not possible be- Cameron Engineers, worked on the gas com- cause of the slurry disposal method. In any bustion program at Anvil Points, as did John commercial plant, it is possible that the shale Jones, later president of Paraho. The system would be burned in a separate unit to pro- is depicted in figure 38. Figure 39 is a photo- duce heat for pyrolysis. graph of the demonstration retort that has been built and tested in Brazil. The retort is The Union “B’ Indirectly Heated Retort 18 ft in diameter, and has a capacity of 2,200 ton/d of Irati oil shale. It was built in 1972, The Union “B” retort is a class 3 retort that and tested intermittently until quite recently. evolved from the Union “A,” a class 2 retort, In 1975, a U.S. patent was issued for the proc- by the Union Oil Co. of California. Two other ess, A 50,000-bbl/d plant is planned by the systems, the SGR and SGR-3, have also been Brazilian Government, to be developed in a proposed by Union, Union describes them all two-stage project. The first stage would in- as continuous, underfeed, countercurrent re- volve construction of a 25,000-bbl/d facility torts. The “B” has not been field tested, but about 5 miles from the site of the demonstra- the “A” was tested in Colorado in the 1950’s Ch. 5–Technology ● 145

Figure 38. —The Petrosix Oil Shale Retorting System

=ALGAS<”’LSHALEFEED HIGH BTU GAS FEED HOPPER PRODUCT FOR PURIFICATION

DISTRIBUTOR ELECTROSTATIC PRECIPITATOR CONDENSER ● CYCLONE I SEPARATOR COMPRESSOR HEAVY SHALE OIL HEAVY PYROLYSIS HOT VESSEL v 9 SHALE OIL \ 00000 d ‘As WASTE WATER DISCHARGE HEATER MECHANISM D \ COOL GAS

SEAL SYSTEM

WATER RETORTED SHALE SLURRY JftJ - TO DISPOSAL

SOURCE 0// Sha/e Refer//ng Technology, prepared for OTA by Cameron Engineers, Inc , 1978 at up to 1,200 ton/d. Figure 40 is a sketch of withdrawn from the top of the pool. The gases the Union “B” design. It incorporates most of are split into three streams. One is reheated the design features of the “A.” and reinfected to induce additional kerogen During operation, shale is fed through the pyrolysis; one is used as fuel in the reheating bottom of the inverted-cone vessel. The re- furnace; and one is the net product. The shale torting process thereafter resembles that of a is discharged from the top of the retort and continuous NTU retort. Hot gases enter the falls into a water bath in the retorted shale top of the retort and pass down through the cooler. From there it is conveyed to disposal. rising bed, causing kerogen pyrolysis. Shale The key to all of Union’s retorting systems oil and gas flow down through the bed. The oil is the solids pump that is used to move the oil accumulates in a pool at the bottom, which shale through the retort. In the “B” design, seals the retort and acts as a settling basin the solids pump is mounted on a movable car- for entrained shale fines. Oil and gas are riage and is immersed in the shale oil pool. 146 ● An Assessment of 0il Shale Technologies

Figure 39.— The Petrosix Demonstration Plant, Sao Mateus do Sul, Brazil

SOURCE Cameron Engineers, Inc Ch 5– Technology . 147

Figure 40.—The Union Oil “B” Retorting Process Ii?

‘. “’ P-4=.+.’.’ AA-+--d 1

= OIL LEVEL

RETORTED SHALE / DISCHARGE TO WATER SEAL

RETORT * GAS \\\\\l\ll j?{! .h\\\\\\lllt 7

T r —

- ROCK PUMP M r m * SHALE OIL k!% m rI

TiT\\ \ \~\\\ ‘\\ \\~. \ \’ \l\\ . ~. . .1 \\\\ \“.’\\\\\\\\\\\\~.\

A. The Retorting System

SHALE IN SHALE IN SHALE IN SHALE IN I

B. Hock Pump Detail

SOURCE 0/1 Strale Reforf/ng Technology, prepared for OTA by Cameron Engineers Inc .1978 .

148 . An Assessment of Oil Shale technologies

The pump consists of two hydraulic assem- A block diagram for the Superior approach blies that act in sequence. (See figure 40.) is shown in figure 41. In step 1, the mined While the cylinder of one assembly is filling oil shale is crushed to pieces smaller than 8 with oil shale, the other is charging a batch of inches and screened. About 85 to 90 percent shale into the bottom of the retort. When this of the nahcolite in the shale is in the form of operation is completed, the carriage moves distinct, highly friable nodular inclusions that horizontally on rails until the full cylinder is become a fine powder during the crushing under the retort entrance. A piston then operation. This is screened from the coarser moves the oil shale in this cylinder upwards shale in step 2. The shale is then further into the retort, while the other fills with fresh crushed to smaller than 3 inches and is fed in shale from the other feed chute. The carriage step 3 to a doughnut-shaped traveling-grate then returns to its original position and the retort, which includes sequential stages for process is repeated. heating, retorting, burning, cooling, and discharging the oil shale feed. The retort is The “B” achieves high oil yields, and the sketched in figure 42. In the heating section, retort gas has a high heating value, although oil is recovered by passing hot gases through much of it is consumed in the reheating fur- the moving bed. In the carbon recovery sec- nace. The mechanical nature of the rock tion, process heat is recovered by burning the pump is troublesome because its moving residual carbon. In the cooling section, inert parts would be subject to wear during opera- gases are blown through the bed of spent tion. However, the pump is immersed in the shale, cooling the shale and heating the gases shale oil pool, which should provide adequate for use in the heating section. After dis- lubrication. Union appears to be satisfied charge, the cooled spent shale is sent to other with its reliability. units in which alumina is recovered from cal- In 1976, Union announced plans to build a cined dawsonite and soda ash from calcined demonstration plant on its private land in Col- nahcolite. The alumina is shipped to offsite orado. The “B” retort was to be used to pro- aluminum refineries; the soda ash to glass duce 7,000 bbl/d of shale oil from 10,000 ton/d plants; and the nahcolite to refineries and of oil shale. Later, the announced capacity powerplants for use as a stack-gas scrubbing was increased to 9,000 bbl/d. The demonstra- agent. tion plant, called the Long Ridge project, Superior chose the traveling-grate retort would be the first step towards a 75,000-bbl/d because it allows close temperature control, commercial-scale plant. Air quality permits important to maintaining dawsonite’s solubil- have been obtained for the modular plant, ity during the burning stage. Similar, simpler which could be completed before 1985. Con- devices have been used to sinter iron ore for struction has not begun because Union is steelmaking and to roast lead and zinc sul- awaiting financial incentives from the Feder- fides. Superior’s process has been tested for al Government. oil shale in pilot plants in Denver and Cleve- land. A commercial-scale plant would con- The Superior Oil Indirectly Heated Retort sume 20,000 ton/d of oil shale to produce The Superior retort is unique among the 10,000 to 15,000 bbl/d of shale oil, 3,500 to aboveground retorts discussed in this section 5,000 ton/d of nahcolite, 500 to 800 ton/d of because it is designed for recovery of sodium- alumina, and 1,200 to 1,600 ton/d of soda ash. bearing minerals in addition to shale oil. As In the early 1970’s, Superior proposed to discussed in chapter 4, the minerals nahcolite build a commercial-size demonstration plant and dawsonite occur in substantial quantities on its 7,000-acre tract in the northern Pi- in portions of the Piceance basin. They are ceance Basin. The deposit was to be devel- potential sources of sodium bicarbonate, oped by deep room-and-pillar mining on sev- soda ash, and aluminum. eral levels. The single retort was to produce Ch 5–Technology 149

Figure 41 .— Block Diagram for the engineering design and cost estimate for a Superior Multi Mineral Concept commercial-scale plant that would contain six TOSCO II retorts, and convert 66,000 ton/d of oil shale into about 46,000 bbl/d of shale oil. In 1969, ARCO joined Colony, and a 14EH---TI I I second semiworks program began to test I SPENT SHALE SHALE scaleup procedures and to evaluate environmental controls. The program continued until

STEP 2 STEP 3 STEP 4 April 1972. Between 1965 and 1972 the semi- SHALE ASH ALUMINA & NAHCOLITE > OIL E works plant converted 220,000 tons of oil RECOVERY SODA ASH RECOVERY RECOVERY shale into 180,000 bbl of shale oil. In 1974, the 1968 cost estimate, which had been updated in 1971, was further revised to ● ● ● ● NAHCOLITE OIL SODA ASH ALUMINA incorporate operating data from the latter SOURCE 01/ Shale Retorting Technology, prepared for OTA by Cameron Engl part of the semiworks program and to ac- neers, Inc .1978 count for additional pollution controls. The 11,500 bbl/d of shale oil, plus the byproducts resulting cost estimate was about three times described above. Although the tract’s re- as large as the previous estimate. This cost sources are extensive, its L-shaped configu- escalation raised doubts about commercial ration does not favor large-scale develop- feasibility, and the project was postponed in- ment. Superior therefore proposed to ex- definitely. SOHIO and Cleveland Cliffs subse- change portions of the tract for adjacent land quently withdrew from the Colony group. controlled by the Bureau of Land Manage- Early in 1974, Tosco, ARCO, Ashland, and ment (BLM). Approval was delayed by BLM Shell purchased a lease for tract C-b from the review and by preparation of an EIS, a draft Federal Government. Initial development of which was recently released. In February plans for the tract involved a plant similar to 1980, BLM denied the exchange because the that proposed for Colony’s private tract. two tracts involved were not considered to These plans were also affected by the cost es- have equivalent value. The decision is open to calations, and in 1976 suspension of opera- review. tions on tract C-b was granted by the Govern- ment. In 1977 Tosco and ARCO withdrew The TOSCO H Indirectly Heated Retort from the tract. Shell withdrew in 1977. Ash- land, the remaining partner, teamed with The TOSCO II is a class 4 retort in which Oxy to develop the tract using MIS tech- hot ceramic balls carry heat to finely crushed niques. oil shale, It is a refinement of the Aspeco process developed by a Swedish inventor. Colony’s semiworks retort, which is about Patent rights were purchased by The Oil one-tenth of commercial scale, is shown in Shale Corp. (later Tosco) in 1952. Early devel- figure 43. The TOSCO II retorting system is opment work was performed by the Denver sketched in figure 44. Raw shale is crushed Research Institute, including testing of a 24- smaller than one-half inch and enters the sys- ton/d pilot plant. In 1964 Tosco, Standard Oil tem through pneumatic lift pipes in which the Co. of Ohio (SOHIO), and Cleveland Cliffs Iron shale is elevated by hot gas streams and pre- Co. formed Colony Development, a joint ven- heated to about 500” F (260° C). The shale ture company, to commercialize the TOSCO II then enters the retort, a heated ball mill, and technology. Between 1965 and 1967, the contacts a separate stream of hot ceramic group operated a 1,000-ton/d semiworks balls. As the shale and balls mix, the shale is 0 0 plant on its land near Grand Valley, Colo., heated to about 950 F (510 C), causing re- next to the site of Union’s semiworks opera- torting to take place. Oil vapors and gases are tions. In 1968, Colony prepared a preliminary withdrawn. The oil is condensed in a fraction- 150 . An Assessment of Oil Shale Technologies

Figure 42.—The Superior Oil Shale Retort

COOL RECYCLE GAS HOT S+LE HEATING RECYCLE + COOL RECYCLE ‘As -~ ~--- GAS / 1- -- 1

SHALE FEED

SOURCE. 0// Sha/e Retorturg Tec/rno/ogy, prepared for OTA by Cameron Eng!neers, Inc , 1978 (after Arthur G McKee & Co j ator. Some of the gases are burned in a heat- increasing energy recovery, and freeing the er to reheat the ceramic balls to about 1,2000 valuable retort gases for other uses. F (650° C). At the retort exit, the retorted shale and the cooled ceramic balls pass over The retort’s chief disadvantages are its a trommel, a perforated rotating separation mechanical complexity and large number of drum. The shale, which has been thoroughly moving parts. The ceramic balls are con- crushed during retorting, falls through holes sumed over time. The need for a fine feed size in the trommel. It is cooled and sent to dispos- results in crushing costs that are higher than al. The larger balls pass over the trommel those of systems that can handle coarser and are sent to the ball heater. feeds. On the other hand, all crushing operations produce some fine shale that could be Oil yields exceeding 100 percent of Fischer screened from the feed to coarse-shale re- assay have been reported for the TOSCO II torts and converted in auxiliary TOSCO II technology. However, overall thermal effi- units. Disposal of TOSCO II spent shale ciencies are low because energy is not recov- presents some problems because it is very ered from spent shale carbon, and much of finely divided and contains carbon. the product gas is consumed in the ball heater. Tosco has patented processes to burn the At present Tosco is participating in two retorted shale as fuel for the ball heater, thus projects that are committed to its proprietary Ch 5–Technology ● 151

Figure 43. — The Colony Semiworks Test Facility Near Grand Valley, Colo.

\, -.,.~ ' , I , I I _ --. * ~...... -- • • <4'" . 'I ..--- -.1 ~ . r:- ,*' " II =_ .. -~ ...; <,\~~

SOURCE Colony Development Corp 152 ● An Assessment of 011 Shale Technologies

Figure 44.—The TOSCO II Oil Shale Retorting System

FLUE GAS PREHEAT SYSTEM TO ATMOSPHERE STACK 4 —

WATER VENTURI BALLS WET SCRUBBER

RAW FOUL WATER To CRUSHED SEPARATOR z FOUL WATER SHALE -h ~ STRIPPER u CERAMIC a NAPHTHA BALL : F SLUDGE” HEATER v < - - HYDROCARBON ~ GAS OIL TO GAS 01 L VAPORS HYDROGENATION

n HOT BALLS BOTTOMS OIL TO : ACCUMULATOR DELAYED COKER Q ~ u. w ~

2 w t- 3 -1 BALL CIRCULATION E SYSTEM STACK

VENTURI WET SCRUBBER I HOT FLUE GAS FLUE GAS * MOISTURIZER SLUDGE PREHEAT SYSTEM HOT cnnu CTFAM+ I 4 SCRUBBER PROCESSED (INCLUDES INCINERATOR) WATER STACK SHALE VENTURI WET SCRUBBER

r+)t COOLER SLUDGE MOISTURIZER“’++ MOISTURIZED PROCESSED

COVERED PROCESSED SHALE CONVEYOR- ‘+$%spOsAL SOURCE 0// Shale Retorflng Technology prepared for OTA by Cameron Engineers, Inc , 1978.

retorting technology. The Colony project has The Lurgi-Ruhrgas Indirectly Heated Retort been mentioned previously. The other venture, the Sand Wash project, is being devel- The Lurgi-Ruhrgas retorting system uses a oped on 14,000 acres of land in the Uinta class 4 retort in which hot retorted shale car- Basin leased from the State of Utah. Unlike ries pyrolysis heat to oil shale. The process the Colony project, which has been sus- was developed jointly by Ruhrgas A. G. and pended pending resolution of economic uncer- Lurgi Gesellschaft fur Warmetechnik m. b. H., tainties, Sand Wash is proceeding towards two West German firms that have been in- commercialization in compliance with the due volved in synfuels production for decades. diligence requirements of the State leases. A The process was developed in the 1950's for plant similar to the proposed Colony facility is low-temperature coal carbonization. A 20- contemplated, but no schedule has been an- ton/d pilot plant was built in West Germany, nounced for its construction. At present, to test a variety of coals, oil shales, and work consists of monitoring the environment, petroleum oils. European shales were tested and preparing to sink a mine shaft. in the late 1960’s, and Colorado oil shale in Ch 5–Technology ● 153

1972. The plant has since been scrapped but Except for the mixer, the process is mechani- smaller retorts are available. cally simple and has few moving parts. It should be capable of processing most oil Coal processing plants using the Lurgi- shales, if they are crushed to a fine size. The Ruhrgas technique have been built in Japan, two major problems with the system appear West Germany, England, and Argentina. to be accumulation of dust in the transfer There are also two Yugoslavian plants, each lines and dust entrainment in the oil. Dusty built in 1963, with a capacity of 850 ton/d of crude oil is not a severe problem because the brown coal. The Japanese plant is also of dust is concentrated in the low-value residual commercial size, and uses the process to product when the oil is subsequently refined. crack petroleum oils to olefins. No large-scale As with the TOSCO II process, requirements oil shale plants have yet been built. for a fine feed material will result in high The retorting system is shown in figure 45. crushing costs. These costs would be partial- Finely crushed oil shale is mixed with hot rely offset by the ability to process the fine frac- torted oil shale in a mechanical mixer that re- tion from any crushing process, including sembles a conventional screw conveyor. Re- those used to prepare shale for coarse-shale torting takes place in the mixer, and gas and retorts. shale oil vapors are withdrawn. Dust is removed from these products in a cyclone sepa- In 1972, Lurgi proposed to develop its re- rator and oil is separated from the gas by con- torting technologies with Colorado oil shale. The program was not funded, but Lurgi’s in- densation. Retorted shale leaves the mixer terest in commercializing the technique has and is sent to a lift pipe where it is heated to continued. In recent years Lurgi has been about 1, 100° F (5950 C) in a burning mixture working with Dravo Corp. to interest U.S. of fuel gas and air. The hot retorted shale is firms in using the technology. At present, at then sent back to the mixer, and the process least one company—Rio Blanco—has ob- is repeated. tained a license to investigate the use of High oil yields have been reported for the Lurgi-Ruhrgas retorts. Present plans call for retort, and the product gas is of high quality. constructing a modular Lurgi-Ruhrgas retort that will be close to commercial size (2,200 ton/d). It will be used to retort the shale that Figure 45. —The Lurgi-Ruhrgas Oil Shale Retorting System will be mined during the preparation of MIS WASTE HEAT retorts on tract C-a.

-OLIDS1 ~-~ FLUE GAS wAsTE RECOVERY Advantages and Disadvantages of the Processing Options

OIL GASEOUS ANO The greatest advantage of TIS processing LIQUID PRODUCTS is that mining is not required, and spent shale CONDENSER DUST is not produced on the surface. The technical, economic, and environmental problems asso- MIXING SCREW TYPE RETORT SOLIDS ciated with above-ground waste disposal are SURGE BIN LIFT thereby avoided. MIS does involve mining and PIPE aboveground waste disposal, although to a TO WASTE lesser extent than with AGR. However, the MIS waste is either overburden or raw oil shale. Both materials are found naturally exposed on the surfaces of deeper canyons in ~ AIR - FUEL the oil shale basins. Although raw shale has (!! Reqwed) low concentrations of the soluble salts, it does SOURCE 0// .Shale Retorf/ng Technology, prepared for OTA by Cameron Engt neers Inc 1978 contain soluble organic materials that could 154 . An Assessment of 011 Shale Technologies

be leached from the disposal piles. It should retorts. It is expected that yields from MIS re- be noted that the presence of spent shale un- torts could be increased by injecting steam or derground has the potential to cause environ- hydrocarbon gases (as is done in Equity’s TIS mental problems because soluble salts could process), but it is doubtful that recoveries can be leached by ground water. Therefore, envi- reach those of carefully controlled above- ronmental controls will also be needed for -ground retorts. On the other hand, the pres- TIS and MIS methods. ent low efficiencies of MIS operations are partially compensated for by their ability to Surface Facilities convert very large sections of an oil shale deposit, by their ability to process shale of a TIS has another theoretical advantage in lower grade than would be practical for AGR, that the required surface facilities are min- and by their lower cost of preparing the shale imal, consisting only of wells, pumps, gas for retorting. cleaning and product recovery systems, oil storage, and a few other peripheral units. It is difficult to compare overall recoveries These facilities would probably resemble from MIS and AGR without making numerous those for processing of crude oil and natural assumptions about the operating characteris- gas. MIS requires more facilities to support tics of both systems. To make a rough com- the mine and the waste disposal program. parison, it could be assumed that AGR (with Aboveground processing, which uses the room-and-pillar mining) and MIS were to be largest number of facilities, causes the most applied to two 30()-f t-thick deposits with iden- surface disruption. tical physical characteristics. The net recoveries from several development options are summarized in table 18. The highest recovery Oil Recovery (100 percent) is for full-subsidence mining in The advantage of AGR is that the condi- conjunction with AGR processing. It should tions within the retorts can be controlled to be noted that full-subsidence mining, for achieve very high oil recoveries—approach- either MIS processing or AGR, would result ing or even in some cases exceeding the yields in extensive surface disturbance and could achieved with Fischer assay retorts. Retort- increase risks to the miners. Subsidence mining efficiencies are usually lower for MIS ing has never been tested in oil shale. Its po- processing and much lower for TIS because tential for surface disturbance could be re- of the difficulty in obtaining a uniform dis- duced by backfilling the mined-out areas with tribution of broken shale and void volume, spent shale from surface processing, The re- which in turn, makes it difficult to maintain torted shale in burned-out MIS retorts would uniform burn fronts and leads to channeling also reduce the severity of subsidence. and bypassing of the heat-carrier gases. The The three generic approaches to oil shale few estimates of the retorting efficiencies of processing also have various other advan- TIS operations that have been published have tages and disadvantages with respect to not been encouraging. (USBM achieved recov- water needs, environmental effects, financial eries of 2 to 4 percent in its field tests. ) MIS requirements, and social and economic im- retorting has not exceeded 60-percent recov- pacts. These aspects are discussed in the re- ery of the potential oil in the shale within the spective chapters of this report. Ch 5–Technology ● 155

Table 18.–Overall Shale Oil Recoveries for Several Processing Options

First-stage Overall shale Case retorting technology First-stage mining method Second-stage processing oil recoverya 1 AGR Conventional room-and-pillar mining on three levels 60-ft None 36% rooms, 60-ft barrier and siII pillars. 2 MIS Conventional MIS mining. 40% of shale left behind in barrier None 29% pillars 20% of the disturbed shale IS removed to the surface to provide void volume in the retorts 3 MIS As in case 2 AGR processing of the mined shale 41 %, 4 AGR As in case 1 Barrier and siII pillars collapsed and 74% retorted by MIS 5 MIS Full subsidence b None 48% 6 MIS Full subsidence b AGR processing of the mined shale 68% 7 AGR Full subsidence b None. 100%

aAssurnlng AGR reco~ers 100 ~ercenl of the potential 011 In the shale retorted MIS assumed to recover 60 percent of the potential 011 bEntlre deposit IS mned SOURCE Off Ice of Technology Assessment

Properties of Crude Shale Oil Crude shale oil (also called raw shale oil, One of the most important factors is the con- retort oil, or simply shale oil) is the liquid oil densing temperature within the retorting sys- product recovered directly from the offgas tem—the temperature at which the oil prod- stream of an oil shale retort. Synthetic crude uct is separated from the retort gases, The oil (syncrude) results when crude shale oil is lower this temperature, the higher the con- hydrogenated. In general, crude shale oil centration of low molecular weight com- resembles conventional petroleum in that it is pounds in the product oil, composed primarily of long-chain hydrocarbon molecules with boiling points that span The properties of crude shale oil from several aboveground and MIS retorting proc- roughly the same range as those of typical 24 petroleum crudes. The three principal differ- esses are listed in table 19. It is important to ences between crude shale oil and conven- note that the oils that are characterized were tional crude are a higher olefin content (be- produced in small-scale test runs under con- cause of the high temperatures used in oil ditions that may not be representative of shale pyrolysis), higher concentrations of oxy- those that will be encountered in other areas, gen and nitrogen (derived from oil shale kero- and with larger processing systems. The oils gen), and, in many cases, higher pour point from commercial-scale facilities in other and viscosity, parts of the oil shale region may have properties that are quite different, The physical and chemical properties of crude shale oil are affected by the conditions The properties of the oil produced by dif- under which the oil was produced. Some ferent AGR processes vary widely, but the retorting processes subject it to relatively differences between these oils and the in situ high temperatures, which may cause thermal oils are much more significant. In situ oils are cracking and thus produce an oil with a lower generally much lighter, as indicated by their average molecular weight. In other processes higher yields of material with relatively low (such as directly heated retorting) some of the boiling points, and would produce more low- lighter components of the oil are incinerated boiling product (such as gasoline) and less during retorting. The result is a heavier final high-boiling product (such as residual oil). In product. Others may produce lighter prod- general, the low yields of residuum make ucts because of refluxing (cyclic vaporization shale oils attractive as refinery feedstocks in and condensation] of the oil within the retort. comparison with many of the heavy conven- 156 . An Assessment of Oil Shale Technologies

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Shale Oil Refining Shale oil has been successfully refined in of the economic aspects of shale oil utiliza- oil shale operations in Sweden, Scotland, tion, and justified continued efforts aimed at Australia, West Germany, the U. S. S. R., and its recovery. In recent years, refining R&D other countries, although on a relatively has been revived because refiners now con- small scale and under unusual economic consider the availability of shale oil to be a dis- ditions. In the United States, the initial refin- tinct possibility. There is also a need to per- ing research was conducted by USBM at the form more precise and up-to-date economic Petroleum and Oil Shale Experiment Station analyses. at Laramie, Wyo. It was coordinated with the early development of the gas combustion re- To date, refining studies have been con- tort at Anvil Points, Colo. The results of this ducted on the upgrading of crude shale oil to work, plus the findings of other investigators, a transportable product, and on the total re- allowed a preliminary assessment to be made fining of shale oil into finished fuels. The dif- 158 . An Assessment of Oil Shale Technologies

ference between these operations lies in the stocks. These studies differ in their approach nature of the desired final product. As dis- to the analysis of refining requirements. cussed previously, some crude shale oils have Studies of existing refineries must consider pour points and viscosities that make trans- the equipment that is in place, and must allow porting them difficult and expensive. In some for the limited flexibility of this equipment for situations, economic considerations may dic- processing a feedstock that is different from tate that the crude shale oil be partially re- the one for which the refinery was designed. fined (upgraded) near the retorting site to im- Studies of specially built refineries, in con- prove its transportation characteristics. In trast, need not be biased in this manner, and other instances, a developer may desire to ob- can draw upon any processing technique that tain a complete array of finished fuels from is available within the refining industry. an integrated processing facility located near However, both types of studies must make the minesite. In this case, a total-refining assumptions about feedstock characteristics facility would be considered rather than a and desired product mixes. These will vary more simple upgrading plant. with the location of the refinery, the nature of the market it serves, and the type of retorting To date, upgrading experiments have been facility that supplies its feedstocks. The op- carried out largely at the bench scale, and in relatively small pilot plants. Theoretical timal refining conditions for one set of assumptions will probably not be applicable to studies and computer modeling have also another set. For example, a refining method been used to evaluate the expected perform- to maximize gasoline production from TOSCO ance of three types of upgrading processes: II shale oil would not maximize diesel fuel thermal, catalytic, and additive. Thermal processes include visbreaking (a relatively production from Oxy’s in situ oil. mild treatment) and coking (a severe treat- Numerous computer studies and bench- ment). Mild thermal treatment will reduce scale refining investigations have been con- pour point and viscosity, but the oil will retain ducted for a wide range of shale oil feed- its initial amounts of nitrogen and sulfur. In stocks and operating conditions. The results contrast, severe thermal treatment reduces of these studies can be extrapolated, with pour point, viscosity, and sulfur content and some degree of caution, to predict the also causes the nitrogen compounds to con- performance of commercial-scale refineries. centrate in the heavier products. The proper- However, refining tests both in pilot plants ties of the lighter products will thus be con- and in commercial-scale facilities, because of siderably improved. much higher costs, have focused on only a In catalytic processes, the shale oil is re- few feedstocks, and have been conducted for acted with hydrogen in the presence of a cat- particular sets of operating constraints. In alyst. Viscosity is reduced, and the nitrogen general, each large-scale study has dealt only and sulfur are converted to ammonia and hy- with oil from aboveground retorts or with oil drogen sulfide gases that can be recovered as from in situ operations, but usually not with byproducts. In additive processes, blending both types of feedstocks. The conclusions of agents are added that reduce the pour point all studies are highly dependent on the com- and allow the crude to be transported by bination of feedstock and refining conditions pipeline. Such pour point depressants have assumed. Caution must be used when apply- been added in several instances with success, ing the results to different conditions. but the technique is not yet highly developed. Total refining studies have focused either Shale Oil Upgrading Processes on the needs of existing refineries that would have to be modified for processing shale oil, The treatment techniques that can be used or on those of newly built facilities that could to improve the transportation properties of be designed specifically for shale oil feed- crude shale oil are briefly described below. Ch 5–Technology ● 159

Visbreaking Catalytic Hydrogenation This technique involves heating the crude In these processes, the crude shale oil is shale oil to approximately 900° to 980° F reacted with hydrogen in the presence of a (480° to 525° C) and holding it at this tem- catalyst. The sulfur in the oil is converted to perature range for from several seconds to hydrogen sulfide, the nitrogen to ammonia, several minutes. The product is then cooled, the oxygen to water, the olefin hydrocarbons and the gases evolved during the heating are to their paraffin equivalents, * and long-chain removed. There is little reduction in the con- molecules to smaller molecules. The hydro- tents of nitrogen, sulfur, and oxygen. There- genation reactions can take place in a fixed- fore, the principal improvements are reduc- bed reactor through which a mixture of oil tions in pour point and viscosity. This tech- vapors and hydrogen is passed, in a fluidized- nique is simple but energy-intensive. It could bed reactor, or in an ebulliating-bed reactor. reduce the pour point of crude shale oil from The latter technique is being promoted by Hy- 30 about 850 F to about 400 F (300 to 40 C). drocarbon Research, Inc., as the H-Oil process. Plants in several foreign nations have Coking successfully used it for heavy petroleum feedstocks and for residuum fractions from a va- This process involves heating the oil to riety of crudes. In this process, a mixture is about 900° to 980° F (480° to 525° C) and injected into the bottom of a reactor at a high then charging it into a vessel in which ther- enough velocity to cause catalyst ebulliation mal decomposition occurs. If the vessel is a (a boiling motion). This movement reduces the coke drum, the process is called delayed cok- possibility that the bed will become plugged ing. The coke—the solid product from ther- by coke and by the liquid tars that are formed mal decomposition—is allowed to accumulate during the coking process. It also allows spent until it fills about two-thirds of the drum’s vol- catalyst and coke to be removed, and fresh ume. The feed is then switched to another catalyst to be added, so as to keep the bed ac- drum while the coke is cleaned out of the first tively stocked. one. Catalytic hydrogenation produces up- In the fluid coking process, hot oil is graded products of the highest quality, but it charged into a vessel that contains a fluidized is relatively expensive. The use of fixed-bed bed of coke particles. The particles become reactors would probably be confined to the coated with oil, which then decomposes to treatment of streams from an initial frac- yield gases and another layer of coke. The tionation step; fluid-bed or ebulliating-bed gases are withdrawn from the vessel. The processes could be used for either frac- coke is also withdrawn continuously, at a tionator products or for the whole shale oil. rate sufficient to maintain an active stock of coke within the bed. The flexicoking process, developed by EXXON, combines conventional fluid coking with gasification of the product coke. The ad- ‘Olefins are unsaturated (lower ratio of hydrogen to carbon) hydrocarbon compounds having at least one double bond. They vantage is that energy is recovered from the are the source of synthetic polymers such as polyethylene and coke. The process is used in the refining in- polypropylene used in the manufacture of fibers and other ma- dustry, but tests would have to be performed terials. Paraffins are saturated hydrocarbons (equal ratio of hydrogen to carbon) having only single bonds. Methane, to determine if it would be suitable for the ethane, propane, and butane are some of the paraffin hydro- coking characteristics of crude shale oil. carbons. 160 ● An Assessment of 0il Shale Technologies

Additives that have occurred in the proposed configurations of shale oil refineries since the 1950’s: Chemicals may also be added to crude the earlier studies placed much more empha- shale oil to improve its transportation proper- sis on gasoline production. For example, early ties. Pour point depressants have been suc- designs by USBM called for the extensive use cessful in some instances, but this does not of middle-distillate cracking and reforming to mean that they would always work. A chemi- yield gasoline, The ratio of gasoline to distil- cal that is suitable for one type of oil may not late yields was nearly 3 to 1.31 Most of the work at all with oil from another retorting refinery configurations that have been pro- process. Furthermore, pour point depres- posed more recently indicate a gasoline-to- sants are disadvantageous because they only distillate ratio of about 1 to 4.” change the physical characteristics of the oil and not its chemical properties. Thus, their The third factor—equipment and operat- cost can be offset only if they save transpor- ing constraints—has become increasingly im- tation costs. portant in recent years. The modifications to convert a conventional refinery to shale oil Conventional petroleum crudes are other feedstocks might not be economically justifi- potential blending agents. Since shale oil (at able unless the refiner could be assured of an least in Colorado) will be produced in an area adequate supply of shale oil. The economic that also contains petroleum reserves, and desirability of building a refinery specifically even active crude oilfields, the possibility ex- for shale oil would be thoroughly scrutinized. ists that the light petroleum crudes could be Modular retorts, or even a few pioneer com- mixed with crude shale oil to form a trans- mercial plants, would not produce enough portable blend. The feasibility of this concept shale oil in the mid-term to justify a new refin- is unclear because, in general, the blend ery unless the refiner was assured that the would not be as valuable as a refinery feed- operations would continue until his invest- stock on a per-unit basis as would the petro- ment cost could be recovered. For this rea- leum alone. However, the decrease in unit son, the most recent studies have stressed value would be offset by the increased vol- modifying existing facilities to make them ume. In the case of a refinery that does not suitable for processing shale oil, rather than have a reliable supply of crude, this could be building new ones. In some cases, this entails a significant advantage. only minor changes to installed equipment, in others, the adaptation of an existing facility Total Refining Processes by adding new units. The three primary factors that affect the The basic unit operations in crude oil refin- design of a refining system are: ing are: . the characteristics of the crude shale oil ● coking, feedstock; hydrotreating, ● the desired mix of finished products; and distillation, ● the constraints imposed by the equip- hydrocracking, ment and operating practices of the pro- ● catalytic cracking, and posed refinery. ● reforming. The first factor probably will have the lowest The various refining schemes that have been effect because, except for the higher nitrogen proposed for shale oil cannot easily be gener- and arsenic contents, the characteristics of alized because, depending on both the de- crude shale oil are not widely different from sired product mix and the possible operating those of conventional petroleum. The second conditions, many configurations could be de- factor—the product mix—is much more sig- signed that would achieve the same results. nificant. This is evidenced by the changes The one selected will largely depend on the Ch 5– Technology 161 availability of equipment and the individual Figure 47. —Refining Scheme Employing Coking economics of the particular refinery. Before an Initial Fractionation, Used by Chevron U.S.A. in Refining Experiments One significant difference among the various configurations described in the literature is the relative arrangement of distillation and thermal or catalytic treatment. Two general approaches have been investigated: 1. distillation of the whole crude into its components, then catalytic or thermal treatment; or I T“ 2. catalytic or thermal treatment of the RpJY whole crude, then distillation.

In the first approach the properties of the SOURCE G L Baughman The Ref(nfng and Markeflrtg of Crude Sha/e 0{/ finished products are better controlled. In the second, the net load on successive processing Figure 48.— Refining Scheme Employing units is reduced, and, in general, the overall Initial H ydrotreating, Used by Chevron U.S.A. yield of high-value hydrocarbon products is in Refining Experiments increased. Most of the refining research to date has been focused on the second ap- c, proach. Three versions are shown schemati- c, G (iog,aaunal cally in figures 46 through 48. The scheme in $ c 3 1S04WT w REFORMER d w~ ~ v I K 6 b Figure 46.— Refining Scheme Used by the cc 0 HYDROTREATER P- > i Fti U.S. Bureau of Mines to Maximize Gasoline 1 $ } Production From Shale Oil !5

Gas z 660”F< > I lt-d3 Ga90hm w Gasohw REFORM ER ~ cc $ 0. cmdO Shale “ft- cm 7. SOURCE G L Baughman. The Reflrrlng and A4arkeflr?g of Crude Sha/e 0//

-T”’ue’Fu@l Od able into finished fuels. The disadvantage of t- coking is that there might not be a ready market for coke in the vicinity of the refinery, particularly if it were located in the oil shale re-

SOURCE G L Baughman, The Refining and Markefing of Crude Sha/e 0// gion. Another refining scheme that was investi- figure 46, which was used by USBM at Anvil gated by Chevron is shown in figure 47. It 33 Points in the late 1940'S, had a gasoline-to- uses a fixed-bed catalytic hydrotreater to up- distillate ratio of 3 to 1. Figure 47, a con- grade the shale oil before distillation. No coke figuration that was investigated by Chevron is produced because most of the heavier com- U.S.A. during pilot-plant runs on Paraho ponents of the crude shale oil are upgraded shale oil,34 had a gasoline-to-distillate ratio of into lighter and more valuable liquid fuels 1 to 4. Both of these systems used an initial during the hydrogenation process. This meth- coking step to upgrade the feedstock and to od may be more costly than the coking ap- supply a product stream more easily refin- proach, but that can only be determined by 162 ● An Assessment of Oil Shale Technologies operating experience and evaluating the eco- pumps and explosions in processing units. nomics. Ash, or particulate matter, must be removed to prevent its deposition in pipes, heat ex- Chevron also investigated the possibility of changers, and catalyst beds. Recent studies substituting a fluidized catalytic cracker for have shown that heating the crude oil to the hydrocracker in figure 48. A similar ap- about 165° F (75° C) then letting it stand for proach was used by SOHIO in processing 85,000 bbl of Paraho shale oil at its Toledo about 6 hours allows the water and solid mat- refinery. 35 The chief difference between the ter to separate from the oil. As noted, arsenic and other metals poison the hydrotreating SOHIO runs and the Chevron experiments is catalysts. A variety of processes have been that SOHIO used an acid/clay treatment to upgrade the distillation products into jet fuel developed for their removal; consequently, and marine diesel fuel for military applica- their presence no longer presents a technical tions. The residuum fraction from the column problem. ARCO has patented several catalytic techniques and methods for heat treat- was used for fuel in the refinery. ing the oil in the presence of hydrogen. Re- The approach in which the crude oil is cent studies by Chevron U.S.A. have shown fractionated before hydrogenation or other that an alumina guard bed preceding the hy- treatment is shown in figure 49. This scheme drotreater will effectively remove both arsenic and iron from shale oil. 39 Figure 49.— Refining Scheme Employing Initial Fractionation, Used by SOHIO in Prerefining Studies The quantity and quality of the fuels produced will be determined by both the configuration of the equipment and the operating conditions used in the refining step. The fuels produced by USBM at Anvil Points in the 1940’s were quite satisfactory.’” However, some of the fuels from the Gary Western refining run in 1975 failed to meet certain military specifications, principally those for stability. 41 This has been attributed to the application of refining techniques unsuitable for shale oil feedstocks, specifically inadequate hydrogenation. Subsequent refining tests at SOHIO’s Toledo refinery show that, with appropriate refining, fuels can be produced that are of superior quality and that can meet all applicable specifications. 42

SOURCE. G L Baughman, The Refining and Market/rig of Crude Shale 0// Cost of Upgrading and Refining was used by SOHIO during the prerefining The most recent estimates of the cost of up- studies carried out before 10,000 bbl of Para- grading crude shale oil to a transportable re- ho shale oil were refined at the Gary Western 36 finery feedstock have been prepared by Chev- refinery in Fruita, Colo. During the actual ron U.S.A.43 The retorting complex that was refinery run, a combination coker/fraction- considered had a capacity of 100,000 bbl/d. ator was used rather than the separate units Conventional hydrotreating was the upgrad- shown in the diagram. ing technique evaluated. Chevron considered The shale oil must also be treated to re- two possible locations for the upgrading facil- move excess amounts of water, ash, and ity: a newly built unit at the retorting site; and heavy metals such as arsenic. Water must be a unit to be added to an existing refinery at removed because it can cause cavitation in some distance from the retorts. In both cases, Ch 5–Technology 163 the estimated cost for upgrading 1 bbl of was estimated to range from $8.00 to $10.00/ crude shale oil was $6.50, in first-quarter bbl of crude shale oil. For a 50,000-bbl/d 1978 dollars. The product would be a high- refinery located in a remote area of the Rocky quality syncrude suitable as feedstock for Mountains (e.g., near the retorting facility), most refineries in the United States. the refining cost would be approximately It is more difficult to estimate the costs of $10.00 to $12.00/bbl.* These are somewhat higher than the costs for refining a high-qual- the total-refining option for converting crude ity conventional crude oil because of the addi- shale oil into finished fuels. This is because in tional amounts of hydrogen that would be addition to the properties of the crude oil con- needed to reduce the nitrogen content of the sideration must be given to the location of po- shale oil crude. tential refinery sites, the availability of refining equipment, the proximity and stability of Another study compared the cost of shale potential markets, the ease of product distri- oil refining with those of refining Wyoming bution, and other factors. Chevron consid- sour crude oil and Alaskan crude. It was as- ered some of these in its analysis of refining sumed that a refinery in the Rocky Mountain costs, although in a relatively generalized region was modified for these feedstocks. The manner. Three total-refining options and two increased costs to refine crude shale oil, refining capacities and refinery locations rather than the other crudes, was in the were considered. For a l00,000-bbl/d refin- range of $0.25 to $2.00/bbl.44 45 ery located in an urban area in the Rocky Mountains (e.g., Denver), the refining cost *Costs are in first-quarter 1978 dollars.

Markets for Shale Oil Crude shale oil has three major potential Shale Oil as a Boiler Fuel uses: as a boiler fuel, as a refinery feedstock, and as a feedstock for producing petrochemicals, The output from a mature oil shale in- Shale oil will most likely first be used as a dustry will probably be used for all three pur- boiler fuel because of the relatively small poses. However, the relative importance of capital investments and very short leadtimes the three markets will change with time as that would be required. Because of Govern- the industry develops. In the mid-1980’s, ment regulation, the current trend in the utili- when shale oil first becomes available in sig- ty industry is to replace oil- and gas-fired nificant amounts, its most likely use will be as boilers with coal-fired units, thus freeing the boiler fuel, with only a small quantity di- natural gas for domestic consumers. In some rected to nearby refineries that could be mod- areas, it will be a two-stage transition, with ified to accommodate the feedstock without the gas first replaced by oil, and the oil later large capital expenditures. As more shale oil by coal. During the transition, there maybe a becomes available, its use as a refinery feed- market for about 50,000 to 80,000 bbl/d of stock will increase as conventional petroleum crude shale oil near the oil shale region. In becomes scarcer. At a later date, when the addition, the refining industry has a small but market for boiler fuels declines, shale oil will significant demand for boiler fuel because re- begin to be used for petrochemical produc- fineries are also changing from natural gas to tion. oil. Therefore, refineries located near the oil —

164 ● An Assessment of 011 Shale Technologies shale region are likely to be near-term shale ies have dealt with four general types of oil customers. In the long run, the largest refining facilities: market for shale oil boiler fuel is likely to be 1. in the Great Lakes States. Transportation dis- a new refinery just for shale oil; tances will probably preclude its use in the 2. a new refinery for a mix of shale oil and other two major markets for boiler fuels—the conventional crude; east and west coasts. 3. an existing refinery modified for, and dedicated to, shale oil; and 4. an existing refinery processing a mix of Shale Oil as a Refinery Feedstock shale oil and conventional crude. There has been relatively little research on The first two approaches are precluded for the refining of crude shale oil because build- the foreseeable future because, as long as re- ing an oil shale plant takes about 5 to 7 years, fined products continue to be imported, the whereas a refinery operator can evaluate a United States will have excess refining ca- new potential feedstock in a few days, devel- pacity. At least through the 1980’s, shale oil op a feasible refining strategy within a mat- will most likely be refined in existing refin- ter of weeks, conduct the necessary pilot- eries, either by itself or as a blend with con- plant refining studies in a few months, and ventional petroleum, modify the refinery to accommodate the new The shale oil produced by demonstration feedstock in less than 3 years. Thus, neither facilities will probably be processed in local the developer nor the refiner has any induce- refineries* or in more distant refineries ment to study shale oil refining until they are owned and operated by the energy companies sure that the oil will, in fact, be forthcoming. that participate in the oil shale programs. Another reason is that until quite recently, The much larger output from a commercial- shale oil was not considered a highly desir- ize industry will be more widely distributed; able refinery feedstock. During the 1950’s thus it will have to compete with other feed- and 1960’s, the refining industry tended to stocks, at least regionally. Recent studies maximize gasoline yields at the expense of have indicated that the Midwest is the most middle and heavy distillates. Because shale likely market area for large quantities of oil is a good source of heavier distillates, not shale oil. This includes the States in the Petro- of gasoline, it was not highly regarded. How- leum Administration for Defense District 2 ever, most projections indicate that gasoline (PADD 2), as shown in figure 50. There will demand will peak in the early 1980’s and then be secondary effects in other districts, as a decline slightly, even though total demand for consequence of the supplies of shale-derived refined products will continue to grow.46 This fuels in PADD 2, because the conventional pe- will be the result of the increasing efficien- troleum that it displaces will become avail- cies of gasoline engines in automobiles and of able for use elsewhere. a greater use of diesel engines in automobiles The quantitative impact on the supply and light trucks. Also, because the current situation in PADD 2 can be determined by re- supplies of conventional petroleum are be- fering to table 20, which indicates how the coming more like shale oil with respect to district’s supplies of finished fuels were di- their distillate yields, the refining industry is vided among domestic and foreign sources in being forced to adopt techniques that would 1978. As shown, the district consumed about be equally suitable for shale oil. 518,000 bbl/d of medium and heavy distillates For these reasons, shale oil’s desirability is (jet fuels, diesel fuel, and distillate fuel oil) increasing, and its potential availability as a from foreign sources. According to Chevron’s premium feedstock has encouraged the refin- *’I’hese could include the Gary Western refinery in Fruita, ing studies that have been conducted by Colo., the Little America refinery in Rawlins, Wyo., the Chev- Chevron and other organizations. These stud- ron refinery in Salt Lake City, Utah, ond others. Ch 5–Technology ● 165

Figure 50.— The Petroleum Administration for Defense Districts

Includes Alaska and Hawaii

SOURCE Natmna/ At/as, Department of the Intenor

Table 20.–Supply of Finished Petroleum Products in PADDs 2, 3, and 4 in 1978 (thousand bbl/d)a

PADD 2 Midwest PADD 3 Texas and New Mexico — PADD 4. Rocky Mountains Foreign Domestic Foreign Domestic Foreign Domestic sources sources Total sources sources Total sources sources Total Gasoline. 976 1,540 2,516 422 604 1,026 33 219 252 Light ends 224 236 460 276 388 664 12 25 37 Jet fuel 81 131 212 50 71 121 7 29 36 Kerosine 17 27 44 19 27 46 0 2 2 Distillate fuel oil 420 672 1,092 194 279 473 13 113 126 Residual fuel 011 150 173 323 237 340 577 4 38 42 Petrochemical feedstocks. 18 26 44 211 298 509 0 1 1 Special naphthas and still gas 60 98 158 114 165 279 2 14 16 Others 138 232 370 102 146 248 4 31 35 Total 2,084 3,135 5,219 1,625 2,318 3.943 75 472 547 ap,ADO = pe/rOleum ,4dmlfllSlfa10fl tor Defense Dlstrlcl

SOURCE G L Baughman The Refmmg and Markef~ng of Crude Sha/e 01/ studies, refining will convert about 74 per- tricts. The same size industry would produce cent of a crude shale oil feedstock to similar about 170,000 bbl/d of gasoline, which would distillates.” A l-million-bbl/d industry would be equivalent to about 17 percent of the dis- yield about 740,000 bbl/d of medium and trict’s gasoline currently obtained from for- heavy distillates. If it were marketed in PADD eign sources. 2, this production would completely displace the foreign supplies and free an additional An alternative marketing strategy would 222,000 bbl/d of the fuels for use in other dis- be to sell the output from a major shale oil in- 166 ● An Assessment of 011 Shale Technologies dustry in PADD 4—the Rocky Mountain re- foreign crude. Recent marketing studies have gion—and to supply any surplus fuels to adja- identified several large refineries in this area cent districts such as PADD 2 or PADD 3 that, with only minor modifications would be (Texas and New Mexico). As shown in table able to handle crude shale oil. 48 Furthermore, 20, the Rocky Mountain district consumes rel- some of the refineries only have access to the atively little distillate fuel (about 20,000 heavier petroleum crudes at present, and bbl/d) from foreign sources. A l-million-bbl/d their production is being limited by their ca- shale oil industry could easily displace this pacity to process the large quantities of resid- entire supply. The surplus production (about uum from the distillation of these fuels. Shale 720,000 bbl/d) could displace about 95 per- oil, with its relatively small yield of bottoms cent of the supply of foreign-derived distil- fractions, would help alleviate this problem. lates in both PADD 2 and PADD 3. The gasoline derived from the shale oil could supply Shale Oil as a Petrochemical Feedstock about 67 percent of the total gasoline demand in the Rocky Mountain States. Three principal factors must be considered As indicated previously, the capabilities of in evaluating the suitability of shale oil sup- the refineries in the Midwest and the Rocky plies for producing petrochemicals: Mountain States will strongly affect the will- ● the yields of petrochemicals from shale ingness of the refiners to accept shale oil oil feedstocks; feedstocks. In some cases, shale oil could not the ability of existing and future petro- be accommodated without significant invest- chemical plants to process the shale oil; ments of capital. However, the receptivity of and refiners to shale oil will also be influenced by ● the logistics of supplying the shale oil to the reliability of other feedstocks such as for- the plants. eign petroleum. The area in which the supplies of crude are most uncertain is the north- Because shale oil is produced by pyrolysis, its ern tier of States, which includes Montana, olefin content is approximately 12 percent, North and South Dakota, Minnesota, and which is appreciably higher than convention- Wisconsin. These States have historically deal crudes. Together with its fairly high hydro- pended on refinery feedstocks from Canada, gen content, these characteristics make shale but, in recent years, a significant reduction in oil, and its hydrogenated derivatives, appro- these supplies has led the refiners in this priate feedstocks for petrochemical produc- area to look elsewhere. The result has been tion.” 50 Steam pyrolysis has been used to the present interest in building a pipeline to process crude shale oil, and the yields of transport crude from Alaska and from for- olefin products have been comparable with eign nations into the area. An alternative—a those from many conventional crudes. Shale pipeline from the oil shale region—could also oil syncrudes, with even higher olefin yields, be built as the oil shale industry developed. are considered to be premium petrochemical feedstocks. These conclusions are based on The area that covers Iowa, Missouri, Illi- laboratory studies under carefully controlled nois, Indiana, Michigan, and Ohio also does conditions. The feasibility of marketing shale not have an adequate indigenous supply of oil to the petrochemical industry depends on crude. However, unlike the northern tier, the ability to replicate these conditions in these States have good pipeline systems with commercial chemical plants. adequate access to both foreign and domestic crude supplies. The feasibility of marketing Historically, the primary feedstock for pet- shale oil in this area will largely be deter- rochemical plants has been natural gas liq- mined by the cost differential between it and uids from the gulf coast. Because crude shale other crude supplies and by the differences in oil is quite different from these liquids, it the reliability of its supply versus that of would be difficult to switch traditionally de- Ch 5–Technology ● 167 signed petrochemical plants to shale oil. How- United States, the petrochemical industry is ever, the production of domestic natural gas concentrated on the gulf coast. This concen- and its associated liquids is declining, and the tration will continue into the foreseeable fu- petrochemical industry is shifting to heavier ture. Therefore, it will be necessary to either feedstocks such as naphtha and gas oils. The move the shale oil to the coast, or to build supplies of these feedstocks are uncertain a new petrochemical complex in the Rocky and irregular. The availability of naphtha has Mountain region. In the latter case, the half- been affected by a growing demand for its finished products from the new plant would use as a gasoline blending agent in response still have to be transported to the coast for to the phasing out of tetraethyl lead. Gas oils final conversion to commercial chemicals. are also being used more frequently for home The former approach is more likely but is im- heating fuels, which causes seasonal varia- peded by the lack of a product pipeline sys- tions in their availability. Because of these tem between the oil shale region and the gulf supply uncertainties, new petrochemical coast, and by the high cost of alternative plants are being designed to be highly flexible modes of transportation. with respect to feedstocks. As using heavier feedstocks becomes more common in the in- In summary, tests have shown that crude dustry, shale oil may become a highly re- shale oil and its derivatives could be used to garded raw material. produce petrochemicals. However, these materials cannot be considered to be viable feed- The use of shale oil for petrochemical pro- stocks in the near future because existing duction is hampered by the distance between chemical plants are generally unable to proc- the oil shale region and the petrochemical ess them and there is ‘no economical transpor- plants. While refineries and oil-fired boilers tation link between the oil shale region and are distributed fairly uniformly across the the existing petrochemical plants.

Issues and Uncertainties The technological readiness of the major Germany.5z In these operations, the lignite is mining and processing alternatives is summa- covered by 900 ft of overburden, and strip- rized in table 21. Estimated degrees of read- ping operations will soon extend to 1,600 ft. iness are shown as judged by DOI in 1968,51 This is comparable to the oil shale deposits, and as they appear under present conditions. which are covered by a maximum of about There are significant differences between the 1,800 ft of overburden. two evaluations because much R&D work has been conducted in the interim, and because Nevertheless, uncertainties remain with two new processing methods—MIS retorting respect to the effects of shale stability and and concurrent recovery of associated min- strength on mine design, mine safety, and re- erals—have since entered the picture. As source recovery. The effects of large inflows shown, room-and-pillar, open pit, and MIS of ground water, such as have been encoun- mining methods are regarded as reasonably tered on tract C-a, could pose severe opera- well-understood. Open pit mining has not tional difficulties, especially with under- been tested with Green River shales, but it is ground mines. In all mines, the logistics asso- highly developed for other minerals such as ciated with moving many thousands of tons of copper and iron ores. It was evaluated on raw material and solid wastes could present paper for application to the shales on tract some formidable problems. Materials-han- C-a. Some highly relevent experience has dling systems exist that could be applied, but been obtained from the operation of large- they have yet to be tested in commercial oil scale lignite (a form of coal) mines in West shale operations. —. .

168 An Assessment of Oil Shale Technologies

Table 21 .–Technological Readiness of Oil Shale Mining, Retorting, and Refining Technologies

Technological readiness Unit operation In 1968 In 1979 Developments in the Interim Remaining areas of uncertainty Mining Room and pillar Medium Medium Mine design studies. Experience of Colony, Rock mechanics Ground water Deep shales Mobil, and the six-company program at Anvil Logistics. Points MIS Unknown Medium Oxy experience at Logan Wash Mine design Rock mechanics Ground water Deep shales studies. Logistics Open pit Low Medium Established procedure for other minerals Rock mechanics Logistics Reclamation Large-scale mines in West Germany. Mine design studies for tract C-a, Other Low Low Mine design studies No field experience All areas Retorting Aboveground Medium Medium Pilot studies for Lurgi-Ruhrgas Semiworks Effects of scaleup on stream factor and recov- programs by Colony and Paraho Detailed ery. Characteristics of emissions streams designs by Colony and Union. Reliability of peripheral equipment Materials handling. TIS Low Low Field work and lab tests by USBM. Field tests Stream factor and recovery. Characteristics of by Equity, Geoknetics, and Talley-Frac. emissions streams Rock mechanics Deep National lab support shales. MIS Unknown Medium Oxy experience, Design studies for tracts C-a Effects of scaleup on stream factor and recov- and C-b. DOE and USBM design studies ery Characteristics of emissions streams Modeling and lab support by national Reliability of peripheral equipment Use of laboratories. low-Btu gas Rich shales. Mixed shales, Fracturing Rock mechanics Deep shales, Multimineral Unknown Medium Pilot plant studies by Superior USBM lab Effects of scaleup on stream factor and recov- tests of product recovery methods. Nahcolite ery Characteristics of emissions streams scrubbing tests. Reliability of peripheral equipment, Materials handling Integration of recovery steps Underground waste disposal Marketability of byproduct minerals. Upgrading and refining...... High High Studies and refinery runs by SOHIO/Paraho, Effects of retorting conditions on crude Chevron, and others. Marketing analyses characteristics Cost effectiveness of alter- by Oxy and DOE. nate processes Use of pour point depressants Effects of metals

SOURCE Ofhce of Technology Assessment

AGR is regarded as having a medium level Although understanding has increased of readiness, as it was in 1968. The under- since 1968, TIS must still be regarded as standing of its technical aspects has been im- being in the conceptual stage. Many uncer- proved since then by field tests in the Pice- tainties remain, especially with respect to ance basin, but the largest tests conducted to economics and environmental effects. date have been at the semiworks scale— about one-tenth of commercial size. Their re- MIS retorting, a new concept since 1968, sults do not permit accurate cost projections has advanced to a medium level of technologi- for commercial-scale plants. Particular prob- cal readiness, approaching that of above- lems are noted with respect to the effect of -ground retorts. This progress is largely a re- scaling up the semiworks design to commer- sult of Oxy’s development efforts in Colorado, cial size. The on-stream factor—the fraction but additional understanding has been ob- of the time that the retorts could be expected tained through simulations by USBM, DOE, to operate at design capacity—is unknown. and the national laboratories, most notably The reliability of some associated systems the Lawrence Livermore and Los Alamos (emissions controls, product recovery de- Laboratories. The remaining uncertainties vices, materials-handling equipment) is also are similar to those for aboveground retorts, questionable. except the materials-handling problems may Ch 5–Technology ● 169 be less substantial with MIS methods. The conventional petroleum, and the fact that all major uncertainties relate to the use of the of the components of a facility must work as large quantities of low-Btu retort gas for pow- designed—not just the well-established ones. er generation and to the application of the With the present state of technological technique to very rich or very deep shales. knowledge, it is not clear that an oil shale The multimineral concept was also largely plant would perform as desired, nor that the unknown in 1968, although the presence of oil would be sufficiently cheap to compete sodium minerals was recognized. At present, with its currently designated competitor—im- the aboveground system of Superior Oil is reported petroleum. Even though the future of garded as having medium technological read- oil shale looks brighter, few companies are iness. Its uncertainties are much the same as willing to build large-scale plants immediate- for other AGR methods, with the addition of ly. They prefer to follow conventional engi- the potential difficulties with integrating the neering practice by proceeding to an inter- systems for recovering mineral byproducts mediate step—the so-called modular demon- with those for recovering oil and gas. The stration retort. marketability of the nahcolite, soda ash, and The modular retort is the smallest unit that alumina has also not been well-established. would be used in commercial practice, A com- The MIS concept proposed by Multi Mineral mercial-size oil shale facility would use sev- Corp. is not specifically evaluated in the eral of these retorts in parallel to obtain the table. It would share the same uncertainties desired production rate. The capacity of a as conventional MIS, with additional po- module varies with the developer. For Oxy, a tential problems introduced by the need to modular MIS retort might have a capacity of evacuate a large underground retort, and be- only a few hundred barrels per day of shale cause the oil shale resource is deeply buried. oil; a commercial facility would have several Upgrading and refining systems were given dozen of these retorts operating simultane- a high rating in 1968, which has been im- ously in modular clusters, each producing proved by additional study. No major prob- several thousand barrels per day. A modular lems are anticipated, although more needs to Lurgi-Ruhrgas retort would have a capacity be known about the feasibility of using pour of about 2,200 bbl/d. One or two such units point depressants, the effects of retorting might suffice for the mined shale from an MIS conditions on the characteristics of the crude operation; a facility that used only AGR might oil, and the effects of metals (such as arsenic) need a dozen comparable units. A commer- on refining catalysts. The major uncertainty cial-sized plant that used Paraho retorting in the distribution area—the existence of an might have seven or eight individual retorts, adequate pipeline system to the most likely each producing 7,300 bbl/d. A comparable markets—is not directly related to the nature plant might use seven Union “B” retorts, each of the refining technology and is therefore not producing about 9,000 bbl/d. Colony prefers indicated. to bypass the modular demonstration phase and to proceed directly to a commercial-size It should be noted that mining and retorting facility, claiming that the TOSCO 11 technol- (the major subprocesses having only medium ogy is ready to be scaled up to such a capacity levels of technological advancement) require for demonstration purposes. only about 35 percent of the capital investment that is needed to establish an AGR com- Regardless of these differences, the sev- plex. The remaining 65 percent is distributed eral “next steps” that are proposed by the among upgrading units, byproduct recovery developer’s have two points in common: the systems, utilities, sidewalks, and other well- production units must be large enough to sim- established items. Yet developers hesitate to ulate actual commercial practice, and the commit themselves to oil shale plants. The equipment must be operated long enough to reasons given are an uncertain regulatory obtain reliable data on its performance under climate, an uncertain future for the price of a complete spectrum of operating conditions. 170 . An Assessment of Oil Shale Technologies

R&D Needs and Present Programs R&D Needs TIS Retorting Mining TIS is the most primitive of the processing methods. It has some potentially valuable fea- Room-and-pillar mining and mining in sup- tures but these cannot be evaluated because port of MIS operations have been tested with of a lack of information. The potential im- oil shale, and an extensive body of informa- pacts on surface characteristics and ground tion has been assembled. To date, however, water quality are especially unclear. The all of the field tests have been conducted in R&D needs include: one area—the southern fringe of the Pice- ● ance basin. In each case, the deposit was development of less expensive drilling techniques; reached through an outcrop along a stream ● course. The limited area in which mining development of efficient and cost-effective fracturing and rubbling techniques; tests have been conducted is unfortunate be- ● cause the characteristics of deposits in other development of methods for determin- areas are quite different. They may be more ing the success of a rubbling program or less favorable to mine development. For through, for example, surveys of the per- example, there is little ground water in the meability increase that has been achieved; southern fringe. In contrast, the deposits on ● tracts C-a and C-b, nearer the basin’s center, development of ignition methods and of lie within ground water aquifers, and the in- methods for maintaining a uniform burn front; flow of water into the mine shafts has been a ● problem on tract C-a. Similar problems were study of the effects of heat-carrier com- encountered at the USBM shaft in the north- position, rate of injection, and temperature on product recovery; ern part of the basin. Work on this site was ● also impeded by the presence of highly frac- study of the effects of creep* on retort stability and product recovery; tured zones, which are not common on the ● southern fringe. determination of the effects of ground water infiltration on retorting; and Similar surprises could be avoided in fu- ● evaluation of the long-term potential for ture projects if the suitability of the candi- surface subsidence. date mining techniques for developing deposits throughout the oil shale region were better Valuable information is being obtained in the understood, especially in these areas where Equity and Geokinetics projects, but these re- near-term development is likely. This infor- sults are applicable only to specific types of mation could be obtained through coring and oil shale deposits—the Equity process to rock mechanics studies, mathematical simu- shale in the Leached Zone; the Geokinetics lation, and experimental mining. Field testing method to thin, shallow beds. Additional field of mining methods would be expensive, work in other types of deposits would aid in although overall costs could be minimized evaluating the potential of TIS methods for through developing a single site that could be large-scale production. To minimize the cost used to test many mining alternatives. A and duration of these tests, they could be supplemented with initial theoretical studies and single shaft or adit, for example, could be laboratory programs. used to test room and pillar, longwall, block caving, and other methods. It should be noted that open pit mining, because of the necessity for costly and large-scale operations, would probably not be amenable to testing in a lim- *Creep is the gradual change in the shape of a solid object in- ited field program. duced by prolonged exposure to stress or high temperatures. Ch 5–Technology ● 171

MIS Retorting Some of these needs could be addressed by further laboratory-scale and semiworks test- MIS is more highly developed, but more ing. Others could be estimated by theoretical testing is needed before its potential applica- calculations and modeling. All of them and es- tion to other areas of the Green River forma- pecially the need for reliability studies, will tion can be determined. The R&D needs are eventually have to be addressed in full-scale similar to those for TIS. They are: retorting modules, either alone or as part of a ● the development of better rubbling tech- commercial-size complex. niques; ● the development of improved remote Upgrading, Refining, and Distribution sensing procedures for permeability, fluid flow, and temperature; Because crude shale oil is sufficiently ● the development of methods for creating similar to conventional petroleum crude, no and maintaining a better burn front; substantial problems are anticipated in the ● evaluation of the effects of heat-carrier refining area. R&D on the effects of heavy characteristics; metals on refining catalysts and of retorting ● evaluation of the effects of creep and conditions on oil properties could be con- subsidence; and ducted in the laboratory, provided that re- ● examination of the effects of ground torts were operating that could supply a prod- water infiltration, retort geometry, and uct resembling the crude oil that will be pro- particle-size distribution. duced in commercial operations, Many of these needs will be addressed in the In the upgrading area, the major need is re- MIS programs on tracts C-a and C-b and the lated to the feasibility of using chemical addi- USBM shaft. tives to depress the pour point of crude shale oil. The necessary R&D could be conducted in Aboveground Retorting the laboratory or in a pilot refinery, again assuming the availability of a representative Several candidate retorting processes crude shale oil. have been tested in Colorado, but only for relatively short periods, and in small-scale R&D is also needed to determine the opti- facilities, More R&D is needed, and particu- mum distribution pattern for the finished lar emphasis should be given to: fuels, which will vary with the size of the industry, the location of the facilities, the need evaluating the effects of scaleup on the for various fuels and feedstocks, and the flow patterns of solids and fluids within availability of a transportation system. R&D the retort vessel; is needed to determine optimal plans for like- determining the reliability and effec- ly combinations of these factors. Work has tiveness of peripheral equipment such begun in this area, and more work could be as solids-handling systems, pollution conducted at relatively low cost, since it is controls, and product separators; theoretical rather than experimental in examining the effects of heat-carrier nature. However, it will not be possible to characteristics on product recovery and define an optimum pattern for the actual equipment reliability; and future industry until the sites of the produc- determining the reliability of mechanical tion facilities are designated. components such as Union’s rock pump; Tosco’s retort vessel, separation trom- The System mel, and ball elevator; the Lurgi-Ruhrgas screw conveyor; and the raw shale dis- All manufacturing and processing plants tributors and spent shale discharge potentially suffer from a lack of systems reli- grates of all retorts that use gas as a ability. Because of the scale of operations and heat carrier. the need for the coordinated performance of .—. .—.—— .

172 An Assessment of Oil Shale Technologies

many components, it is certainly possible that nologies in the various types of oil shale oil shale plants will have significant prob- deposits. lems. On the other hand, they may not be more severe than in other, more conventional In situ processing has been given the major industries. R&D programs, such as mathe- emphasis throughout the program, and much matical simulations and industrial engineer- of the technical R&D will be conducted in the ing studies, would help to eliminate some of “Moon Shot” project that will address the the uncertainties regarding the expected per- second goal. Initial support of AGR will focus formance and reliability of oil shale systems. on designing the retort module and on surface Basic data on the lifetimes of equipment, and underground mines to support single operating characteristics, and other factors plants and an industry of 1 million to 3 million could be obtained from those minerals proc- bbl/d. The decision to proceed with construc- essing and refining plants that oil shale facil- tion of AGR modules will be determined by ities will resemble. However, because of the the economic outlook for shale oil in unique character of oil shale operations, pre- mid-1980. DOE will consider a cost-shared dictions from these studies will be tentative. program if industry has not announced firm It will only be possible to define performance plans to proceed without Federal participa- characteristics after large-scale oil shale tion. The program will also include resource plants are operated at their maximum pro- characterization studies that will help to duction capacities. delineate the portions of the oil shale basins where the different types of development Present Programs technologies would be most applicable. Other studies will include assessments of air, Some of the current R&D programs for water, land, and socioeconomic impacts; of individual retorting technologies were de- occupational safety and health; and of meth- scribed previously. An effort that has not ods for increasing the efficiency of water use. been discussed in detail is DOE’s integrated research, development, and demonstration These efforts should substantially advance program for oil shale.53 Its major objective is the understanding of the technological as- to provide the private sector with the techni- pects of oil shale development. The budget of cal, economic, and environmental informa- over $387 million for fiscal years 1980 tion needed to proceed with the construction through 1984 should be adequate to address of pioneer commercial plants. Its specific most of the R&D needs identified in the previ- goals are: ous section. This budget includes about $126 million for developing and operating a com- ● by mid-1981: to provide technical de- mercial-scale MIS retort, and half of the esti- signs, cost data, and environmental in- mated $200 million cost of an AGR module. 54 formation for construction and operation of at least one AGR module; The demonstration facilities are especially ● by 1982: to design at least one commer- important to the acquisition of firm engineer- cial-size MIS retort that could be used on ing and economic data. Unfortunately, only the Federal lease tracts or in other loca- one in situ technology and one aboveground tions; and retort will be tested, and it will be difficult to ● by 1985 to 1990: to remove the remaining evaluate fully the effects of resource charac- technical uncertainties that impede com- teristics on the feasibility of alternate mining mercial-scale use of the alternate tech- methods. Ch 5–Technology ● 173

Policy Options R&D The two general approaches to funding such demonstration programs are discussed Some of the remaining technical uncertain- below. Selecting an option will depend on the ties could be alleviated with additional small- desired balance between information genera- scale R&D programs. These could be con- tion and dissemination, Federal involvement, ducted by Government agencies or by the pri- timing of development, and cost. vate sector, with or without Federal participation. If full or partial Federal control is de- Private Funding sired, the programs could be implemented through the congressional budgetary process If left alone, the industry would develop in by adjusting the appropriations for DOE and response to normal market pressures and op- other executive branch agencies, by provid- portunities, and the Government’s expense ing additional appropriations earmarked for and involvement would be minimized. How- oil shale R&D, or by passing new legislation ever, the Government would not be assured of specifically for R&D on oil shale technologies. access to the technical, economic, and environmental information that it needs to formu- Demonstration late future policies and programs, although some of this information could be obtained Full-scale demonstrations will be needed to through third-party reviewers or through li- accurately determine the performance, reli- censing arrangements. Another disadvantage ability, and costs of development systems un- is that industry may not risk even the relative- der commercial operating conditions. In gen- ly modest investment of a modular program eral, potential developers would prefer to fol- until economic and regulatory conditions low conventional engineering practice and clearly favor development. For example, approach commercialization through a se- Union and Colony have announced that they quence of increasingly larger production will not proceed until Federal incentives are units. Union, Colony, and Paraho have pro- provided and regulatory impediments re- gressed through this sequence to the semi- moved. Industry may eventually proceed, but works scale of operation—about one-tenth of perhaps not in time for the resource to con- commercial size. tribute substantially to the Nation’s fuel supplies within the next decade. If this conservative approach were continued, the next step would be a modular Government Support demonstration facility. Although such a plant would cost several hundred million dollars, it The alternatives are full Government fund- would provide the experience and the techni- ing of demonstration facilities, indirect fund- cal and economic data needed to decide on ing through incentives to industry, and a the commitment of much larger sums to com- sharing of the costs with industry. The op- mercial-scale operation. Union has expressed tions are discussed in detail in chapter 6 and its preference for this path; Rio Blanco and summarized in chapter 3. In brief, Federal Cathedral Bluffs are following it. Colony re- ownership would provide the Government gards a pioneer commercial plant as the best with the maximum amount of experience and facility for proving the TOSCO II technology. information. It would also maximize Govern- 174 ● An Assessment of Oil Shale Technologies

ment intervention and the commitment of A single module on a single site.—This op- public funds, and it might discourage private tion would provide comprehensive informa- developers from proceeding with independ- tion about one process on one site. Either ent demonstrations. Also, industry and Gov- underground or surface mining experiments ernment would design, finance, and operate a could be performed, but probably not both. demonstration project in very dissimilar The costs would be small overall but large on ways. The Federal experience with a Govern- a per-barrel basis, because there would be no ment-owned facility may have little relevance economies of scale. Some of the shale mined to the problems that would be encountered by could be wasted because the single retort a private developer with the same production might not be able to process all of it economi- goal, The Government’s experience would cally. If the site could subsequently be devel- therefore provide little guidance for evaluat- oped for commercial production (e. g., a pri- ing oil shale as a private investment oppor- vate tract, a potential lease tract, or a can- tunity. didate for land exchange), the facility would Incentives programs could involve tax have substantial resale value. Otherwise, it credits, purchase agreements, price sup- would be valuable only as scrap. ports, or other types of support, either singly Several modules on a single site.—This or in combination. They could be structured program might consist of an MIS operation, to encourage the participation of specific coupled with a Union retort for the coarse types of firms and could be combined with portion of the mined oil shale and a TOSCO II regulatory changes, and possibly land ex- for the fines. As with the single-module op- changes or additional leasing, to control both tion, either surface or underground mining the growth and the nature of the ultimate could be tested, depending on the site, or commercial industry. They would cost less possibly both if the plant had a sufficiently than Government ownership. They would also large production capacity. The total costs tend to provide the Government with less in- would be larger than for the single-module formation and with no operating experience. program, but unit costs would be lower. For However, disclosure requirements could be example, a three-module demonstration plant inserted into the leases or the incentives legis- would cost about 2. I times as much as a lation as a prerequisite for project eligibility y. single-module facility; a six-module plant The cost sharing of demonstration facilities about 3.7 times as much. Different technol- would entail intermediate expenditures of ogies could be combined to maximize republic funds and intermediate levels of infor- source utilization, and detailed information mation. The receptivity of industry to such could be obtained for each. However, all of proposals would depend on how much the the information would be applicable to only Government would intervene in designing and one site. If many modules were tested, the operating the projects. If industry responded, demonstration project would be equivalent to the Federal investment that would be needed a pioneer commercial plant, except that a for a single Government-owned plant could be true pioneer operation would probably not spread over several projects, thereby in- use such a wide variety of technologies. creasing the total amount of information generated. Single modules on several sites.—Several technologies might be demonstrated, each at Program Alternatives a separate location. For example, an underground mine could be combined with a Demonstration will require designing, TOSCO II retort on one site; a surface mine building, and operating full-size production with a Paraho retort at another. Total costs units, either as separate modules or incorpo- could be large, as would unit costs, which rated in pioneer plants. would be comparable with those of the single- Ch. 5–Technology 175 module/single-site option. The principal ad- methods would be selected that would be vantage would be that different site charac- most appropriate for the characteristics of teristics, processing technologies, and mining the site and the nature of its oil shale de- methods could be studied in one comprehen- posits. The maximum amount of information sive program. would thus be acquired, in exchange for the maximum amount of investment. Each project would resemble the several-module/single- Several modules on several sites.—For site option; the collection would constitute a each site, a mix of mining and processing pioneer commercial-scale industry.

Chapter 5 References

‘T. Ertl, “Mining Colorado Oil Shale, ” Quarter- ‘2P. W. Marshall, “Colony Development Opera- ly of the Colorado School of Mines, vol. 69, No. 3, tion Room-and-Pillar Oil Shale Mining, ” Quarterly July 1965, pp. 83-92. of the Colorado School of Mines, vol. 69, No. 2, ZRio Blanco oil Shale Project, ~etailed ~eVe~oP- April 1974, pp. 171-184, ment Plan: Tract C-a, Gulf Oil Corp. and Standard “C-b Shale Oil Project, Detailed Development Oil Co. (Indiana), March 1976, pp. 7-2-1 to 7-2-20. Plan and Relatea’ Materials, Ashland Oil, Inc., and ‘J. B. Miller, President of Rio Blanco Oil Shale Shell Oil Co,, February 1979, p. IV-2. Co., letter to G. Martin, Assistant Secretary for “Oil Shale R, D, & D—Program Management Land and Water Resources, Department of the In- Plan, Department of Energy, Washington, D. C., terior, Oct. 26, 1979. June 25, 1979, p. C-3. ‘U.S. Energy Outlook—An I~terim Report, The 151bid. National Petroleum Council, Washington, D, C., ‘bIbid., p. C-2. 1972. “Ibid. ‘H. E. Carver, “Oil Shale Mining: A New Possi- 18R. D. Ridley, “Progress in Occidental’s Shale bility for Mechanization, ” Quarterly of the Col- Oil Activities,” Eleventh Oil Shale Symposium Pro- orado School of Mines, vol. 60, No. 3, July 1965. ceedings, Colorado School of Mines Press, Golden, “J. J. Reed, “Rock Mechanics Applied to Oil Colo., November 1978, pp. 169-175. Shale Mining,’” Quarterly of the Colorado School “D. R. Williamson, “Oil Shales: Part 5—Oil of Mines, vol. 61, No. 3, July 1966. Shale Retorts, ” Mineral Industries Bulletin, vol. 8, ‘R. O. Bredthauer and T. N, Williamson, No. 2, March 1965. “Mechanization Potential in Oil Shale Mining, ” ‘(’J. L, Ash, et al., Technical and Economic Study Quarterly of the Colorado School oj Mines, vol. 61, of the Modified In Situ Process for Oil Shale, re- INO. 3., July 1966. port prepared for the U.S. Bureau of Mines by Fe- 8P. T. Allsman, “A Simultaneous Caving and nix and Scission, Inc., under contract No. Surface Restoration System for Oil Shale Min- SO241O73, November 1976. ing, ” Quarterly of the Colorado School of Mines, “J. H, Campbell, et al., “Dynamics of Oil Gen- vol. 63, No. 4, October 1968. eration and Degradation During Retorting of Oil ‘W. N. Hoskins, et al., “A Technical and Eco- Shale Blocks and Powders, ” Tenth Oil Shale Sym- nomic Study of Candidate Underground Mining posium Proceedings, Colorado School of Mines Systems for Deep, Thick Oil Shale Deposits, ” Press, Golden, Colo., July 1977, pp. 148-165, Quarterly of the Colorado School of Mines, vol. 71, 22R. L. Braun and R. C. Y. Chin, “Computer Mod- No. 4, October 1976, pp. 199-234. el for In-Situ Oil Shale Retorting: Effects of Gas In- ‘“C. E. Banks and B. C. Franciscotti, “Resource troduced Into the Retort, ” Tenth Oil Shale Sym- Appraisal and Preliminary Planning for Surface posium Proceedings, Colorado School of Mines Mining of Oil Shale, Piceance Creek Basin, Col- Press, Golden, Colo., July 1977, pp. 166-179. orado,” Quarterly of the Colorado School of 2tJ. H. Raley, et al., “Results From Simulated, Mines, vol. 71, No. 4, October 1976, pp. 257-286. Modified In Situ Retorting in Pilot Retorts, ” IIJ. H. East and E, D. Gardner, “Oil Shale Min- Eleventh Oil Shale Symposium Proceedings, Col- ing, Rifle, Colorado, 1944 -1956,” Bulletin 611, U.S. orado School of Mines Press, Golden, Colo., No- Bureau of Mines, 1964. vember 1978, pp. 331-342. —

176 ● An Assessment of Od Shale Technologies

“G. L. Baughman, Synthetic Fuels Data I-Iand- ings, The Colorado School of Mines Press, Golden, book, 2nd Edition, Cameron Engineers, Inc., Den- Colo,, November 1978, pp. 120-134. ver, Colo., 1976, ‘%upra No. 28, 25R. D, Ridley, “A Marketing Perspective for ‘%upra No. 29, Shale Oil,” paper presented at the meeting of the ‘OH. C, Carpenter, et al., “A Method for Refining Commercial Development Association, Marcos Shale Oil,’* Industrial and Engineering Chemistry, Island, Fla,, 1979. vol. 48, pp. 1139-1145. zbR. F, Sullivan, et al., “Refining Shale Oil, ” “Applied Systems Corp., Compilation of Test Re- paper presented at the 43rd Midyear Meeting of sults, report prepared for the Office of Naval Re- the Refining Department of the American Petro- search under contract No. NOO014-76-C-0427, leum Institute, Toronto, Ontario, May 10, 1978. 1976, ‘71bid. ‘2 Supra No. 35, 2W.S. patent Nos. 3,804,750: 3,876,533; and ‘]H, A. Frumkin, et al., “Cost Comparisons—Al- 4,029,571. ternative Refining Routes for Paraho Shale Oil, ” 2YR. F. Sullivan, et al., Refining and Upgrading of paper presented at the 86th National Meeting of Syn~uels From Coal and Oil Shale by Advanced the American Institute of Chemical Engineers, Catalytic Processes, report prepared for the De- Houston, Tex., Apr. 1-5, 1979. partment of Energy by Chevron U.S.A. under con- %upra No. 25. tract No. EF-76-C-01-2315, 1978. “’Pace Company Consultants and Engineers, 1{)W. L. Nelson, “Visbreaking as Pour Point Re- Inc., Shale Oil Refining Analysis, report prepared ducer,” The Oil and Gas journal, Nov. 10, 1969, p. by the Pace Co. for the Department of Energy and 229. Occidental Oil Shale, Inc., 1978, “J. D, Lankford and C. F. Ellis, “Shale Oil Refin- %upra No. 25. 7 ing, ” Industrial and Engineering Chemistry, vol. ‘ Supra No, 43. 43, No. 1, January 1951, pp. 27-32. ‘“Purvin and Gertz, Inc., Markets for Crude %upra No. 29. Shale Oil in Central U. S., report prepared for Oc- ‘] Supra No. 31. cidental Oil Shale, Inc., 1977. ‘%upra No. 29. “yIbid, “E. T. Robinson, “Refining of Paraho Shale Oil 5’]C. F. Griswold, et al., “Light Olefins From Hy- Into Military Specification Fuels, ” Twelfth Oil drogenated Shale Oil,” Chemical Engineering Shale Symposium Proceedings, The Colorado Progress, September 1979, pp. 78-80, School of Mines Press, Golden, Colo., August “Prospects for Oil Shale Development—Colora- 1979, pp. 195-212. do, Utah, and Wyoming, Department of the Interi- ‘“H. Bartick, et al., The Production and Refining or, Washington, D, C., May 1968, p, 47. of Crude Shale Oil Into Military Fuels, report pre- 52M. A. Weiss, et al., ShaJe Oil: Potential Econo- pared for the Office of Naval Research by Applied mies of Large Scale Production, Workshop Phase, Systems Corp. under contract No. NOOO14-75- The Massachusetts Institute of Technology, Ener- C-0055, 1975. gy Laboratory report No. MIT-EL-79-031-WP, July “R. F, Sullivan and B. E. Strangeland, “Convert- 1979, pp. 6-7. ing Green River Shale Oil to Transportable ‘] Supra No. 14, at pp. 1-6. Fuels, ” Eleventh Oil Shale Symposium Proceed- 5%upra No. 14, at pp. viii-ix. CHAPTER 6 Economic and Financial Considerations

Page Page Introduction . ., . . . ., . . . . ., . 0 . .,,,,,.., 179 Loan Guarantee ...... 212 The Nature of the Investigations...... 180 Government Participation ...... 213 Government Ownership Versus Incentives Summary of Major Findings...... 180 for Private Development ...... 215 Development, Commercialization, and Deployment ...... 181 Which Incentives Are Most Efficient and Effective? ● . . ● . ● . . . ,. . , ● ● ● ● , . . , ● ● . ● ● . 215 The Rationales for Federal Intervention. .. ..182 Are Financial Incentives Needed?...... 216 Impediments to the Commercialization of Economic and Budgetary Impact...... 217 Oil Shale . ,,..,,...,,.,....,.,,.,., 183 Industry Costs...... 217 Risks, Uncertainties, and Impediments Cost to the Government...... 218 Associated With Oil Shale Development. .. 185 Capital Market Impacts and Financial Plant Capital Cost Estimates ...... 186 Feasibility...... , .. ..221 Increases in the General Rate of Inflation. .. .187 Concerns...... 222 Uncertain Future Prices of World Crude. .. ..189 Scenario Framework ...... 222 Choosing Goals for Oil Shale Development. .. 191 Peak Financing Requirement ...... 222 Information Base Goal ...... 191 Foreign Oil Displacement Goal...... 192 Aggregate Financial Feasibility...... 224 A Caveat ...... 224 A Comparison of Alternative Financial Finance Mix ...... ,...... 225

Incentives ● .., ,.O, .0. .,...... 193 Smaller Companies and NewEquity ...... 225 Production Tax Credit ...... , ...... 197 Construction Grant...... , , ...... 200 Secondary Financial Impacts and Benefits. ..226 Low-Interest Loan...... 203 Balance of Payments and Strength of Purchase Agreement ...... , .. ...204 U.S. Dollar ...... 226 Price Support ...... 206 Taxes ...... 226 Investment Tax Credit ...... 207 Capital Costs Secondary Effects ...... 227 Accelerated Depreciation ., ...... 208 Financial Aspects of Policy Alternatives. . . . .227 Increased Depletion Allowance...... 210 Impact on Peak Financing ...... 227

Page Page Impact on Private Sector Share of Peak Incentives (15-percent rate of return Financing...... 227 on invested capital) ...... 198 General Impact of Subsidies...... 227 27. Peak Financing in Billions for Each Summary...... ,...... 228 Scenario ...... 224 28. Finance Mix ...... 225 Effect on Inflation and Employment ...... 228 29. The Current DolIarImprovement in the Construction Industry and Equipment Annual U.S. Balance-of-Payments Capacity *.***..* ...... **..*..* . . 229 Position Associated With Alternative Development Rate Scenarios...... 226 Chapter 6 References...... 231 30. Summary of Estimates of the Improvement in Federal Tax Revenue List of Tables Attributable to Shale Oil Production Table No. Page From the Taxes Paid byShale Oil 22. Cost Estimates for Oil Shale Processing Companies, Their Employees, Their Plants ...... 186 Suppliers, and Their Suppliers’ 23. Evaluationof Potential Financial Employees ...... 227 Incentives for Oil Shale Development .,, 196 24. Summary of Companies’ Ordinal List of Figures Preferences for Incentives...... 197 25. Subsidy Effect and Net Cost to the Figure No. Page Government of Possible Oil Shale 51. Increases in Capital Cost Estimates . . . . 188 Incentives (12-percentrate of return 52. A Summary of Variations in Each on invested capital) ...... 197 Scenario. .o. o ...... 222 26. Subsidy Effect and Net Cost to the 53. Year-by-Year Financing in Billions for Government of Possible Oil Shale Various Scenarios ...... 223 CHAPTER 6 Economic and Financial Considerations

Introduction The loss of oil imports from Iran coupled for achieving various production levels with large OPEC price increases during 1979 and minimizing private and Government once more emphasized the vulnerability of risk; and the United States to its continued dependence ● the major commercial and institutional on imported oil. Rapidly escalating world oil risks and obstacles that currently ham- prices combined with uncertain supplies and per commercial development, which of dwindling domestic reserves have seriously these can be predicted, and in which affected the balance of payments, the rate of cases is information insufficient to ade- inflation, and the general health of the econ- quately evaluate policy options. omy. While expert opinions may differ about prices in the immediate future, they agree Considering the amount of capital that would that supplies will remain uncertain and need to be invested and profitably returned prices will continue to rise. The recently re- over long periods of time, a rational and in- newed interest in shale oil (and other synthet- formed choice about the commercial produc- ic fuels) as contributors to the domestic fuel tion of shale oil (or any synthetic fuel) re- supply has arisen in response to these uncer- quires making reasonably confident esti- tainties. mates of the following factors and relation- The present debate over the proper eco- ships: nomic policy to pursue with respect to oil ● the required capital and operating costs shale development centers around the follow- for various levels of shale oil production, ing: and a comparison of these costs with ● the potential it may have for alleviating those for alternative strategies for ob- the Nation’s energy-supply problems; taining equivalent benefits; ● the financial, environmental, and socio- ● the future effect of OPEC pricing pol- economic costs and risks that could be icies; encountered in developing an oil shale ● industry; the corporate perceptions of specific ● risks and deterrents that currently in- a comparison of its benefits and costs hibit private commercialization; with those of other energy strategies such as conservation, solar, increased ● the subsidies and incentives that would direct use of coal, other synthetic fuels, most effectively, and at least cost, suffi- expanded domestic exploration and pro- ciently reduce uncertainty to promote duction, or continued reliance on foreign development; and oil: ● the temporary or permanent subsidies ● the implications of both alternative pro- that would be required to maintain an in- duction goals and the rate at which the dustry. industry is established for maximizing the benefits and minimizing the costs These are all complex issues open to a variety and risks of commercialization; of interpretations. Several of these questions ● the relative advantages and disadvan- may be unanswerable at this time with the in- tages of different financial mechanisms formation available.

179 180 ● An Assessment of Oil Shale Technologies

The Nature of the Investigations

- This chapter reports the results of the fol- ducted mathematical simulations of in- lowing analyses: dustry economics, as well as on extensive discussions with private consult- The capital and operating costs have ants, Government financial administra- been estimated for commercial-size fa- tors, and industry representatives. cilities in third-quarter 1979 dollars. The relative advantages and the merits This has been done for both surface re- of several different strategies, develop- torting and modified in situ (MIS) tech- ment schedules, and production targets nologies. The total costs of various pro- have been examined with respect to duction levels have been calculated for their comparative costs, risks, and bene- industries based on both generic tech- fits. nologies. The accuracy of current cost ● A detailed study has been carried out of estimates has been evaluated in the light the impact on capital availability and of the prior unreliability of such projec- pricing of oil shale development at sever- tions, and an attempt has been made to al levels of production. The investigation disaggregate the factors responsible for indicates the probable impacts that al- the escalating cost estimates for these ternative levels of oil shale production facilities. will have on the cost and availability of . The effect of uncertain prices for OPEC capital, both for the U.S. energy sector crude on shale oil commercialization has and the economy as a whole, given a va- been examined, a variety of projections riety of different growth and demand for these prices evaluated, and a proba- characteristics for investment capital, ble rate of increase for future real This examination also considers the rel- prices described. ative impact that different Federal in- ● OTA has undertaken extensive qualita- centives will have on capital markets. tive and quantitative examinations of ● The effect of various levels and paces of the relative effectiveness and outcomes oil shale development on the level of em- of various possible financial incentives ployment, the balance of payments, the for stimulating commercial development. rate of inflation, and Federal tax genera- These were based on independently con- tion,

Summary of Major Findings

The major conclusions of OTA’s economic analysis ● It is likely, given current market conditions, re- of the oil shale industry are as follows: source availability, and the regulatory climate that without additional Federal action a shale oil pro- ● The commercialization of oil shale has been gen- duction capacity of 100,000 bbl/d will be online erally impeded in the past by several uncertain- by 1990-92. It is probable, given similar condi- ties. Among the most important are large and un- tions, that the production of 200,000 bbl/d by reliable plant capital cost estimates, the insuffi- that date will require financial incentives, direct cient number of high-grade private oil shale tracts Government participation, or major changes in the plus limited access to Federal oil shale lands, un- regulatory environment of the industry. The same certainty about present and future environmental would be even more the case for a 400,000 -bbl/d regulations, and uncertainty over future prices for industry. Furthermore, the deployment of this size oil. industry by 1990 could require additional land ex- Ch 6–Economic and Financial Considerations ● 181

changes or Federal leases. The deployment of a 1- ● The deployment of a 400,000-bbl/d industry by million-bbl/d industry by the same date would re- 1990 would begin to markedly strain the capacity quire aggressive action in all of these areas. of U.S. manufacturers to supply heavy equipment to developers. To deploy a 1-million-bbl/d indus- ● Given recent increases in the price of oil, the po- try by that time would use between 15 and 30 per- tential marketability of shale oil improved substan- cent of current U.S. annual production of this tially during late 1979 and early 1980. In narrow equipment. There would be a similar strain on the economic terms, the production of shale oil may be capacity of large integrated architectural/engi- price competitive with foreign crude at this time. neering firms capable of undertaking major proc- However, this conclusion is subject to several crit- ess plant construction. ical limitations, It assumes that current capital and operating cost estimates are within 20 percent of ● Existing capital markets and lending institutions actual costs, that the price for oil will continue to are able to supply sufficient capital for even the rise throughout the rest of this century by at least rapid development of a large industry (1-million- a real 3 percent per year, and that developers re- bbl/d by 1990) without significant perturbations, quire a real discount rate of no more than 12 percent. (The economics of shale oil and its potential ● Oil shale development would provide a number of selling price are extremely sensitive to the dis- economic benefits such as contributions to the na- count rate assumed by the developers. ) tional fuel supply and direct substitution for for- ● If financial incentives to private industry are to be eign oil imports. A production of 500,000 bbl/d employed, production tax credits, purchase agree- would reduce the balance-of-payments deficit by ments, and price supports have the most econom- about $5 billion current dollars if the price of for- ic merit based on a variety of criteria. However, it eign crude were $31/bbl. should be noted that the subsidy effect of purchase agreements and price supports are depend- ● Oil shale development, even at high rates of de- ent on the contract price that is set. Consequently, ployment, would have an insignificant impact on the success of these two incentives will depend on national prices and rates of employment. How- how they are constructed and administered. Small ever, the production of even 200,000 bbl/d by and moderate firms will require some kind of front- 1990 would noticeably increase local rents, land end subsidy if they are to significantly participate prices, and labor costs. Even moderate devel- in oil shale development. If such participation is an opmental rates would favorably affect local em- important goal of Government policy, debt guaran- ployment levels and this effect would extend to the tees or debt insurance are probably the most effi- region with the deployment of a 400,000-bbl/d in- cient vehicles. dustry by 1990.

Development, Commercialization, and Deployment’ In this assessment, the term commerciali- oil shale, it will be necessary for their atten- uation is used to designate the process by tion to be focused on the period between the which private industry adopts a technology time when the major technical problems have for commercial use after most of the tech- been solved and the time when the technology nical uncertainties affecting its economic fea- is commercially self-sufficient—the initial sibility have been resolved. In the United phase. Once a decision about the advisability States, commercialization of new technol- of intervention has been made, the question ogies is primarily undertaken by private firms then is how the commercialization of the ini- without direct Federal intervention. Never- tial phase can best be accomplished. theless, during the past decade the amount of direct Government involvement has risen Government sponsored development pro- sharply. If Congress and the administration grams consist primarily of research and de- decide to stimulate the commercialization of velopment (R&D) to solve the technical prob- ———— . ——— —— —

182 ● An Assessment of Oil Shale Technologies lems of a process. Thus far, such programs industry during World War II is a well-known for oil shale have been directed to developing example of such a program. In this case the specific techniques for mining, retorting, rub- industry subsequently became profitable bling (in MIS processing), removing of impuri- without subsidy, but this was not the main ob- ties, and hydrotreating the shale oil. jective of the program. Commercialization, in which a technology is adopted and made economically viable by Both deployment programs and commer- private industry, involves the resolution of cialization support for synthetic fuel plants the institutional and economic deterrents that have been proposed. Although they have simi- affect profitability. Efforts by the Govern- lar goals, these strategies imply very dissimi- ment to promote commercialization assume lar relationships between Government and in- that the adoption by private industry of a dustry. Deployment programs are govern- process, which is temporarily not commer- mentally controlled. The function of private cially viable, will be expedited. The rationale firms is restricted to advising, constructing, is that such assistance will enable an indus- and, in some instances, operating the facil- try to become self-sufficient and profitable ities. Private corporations provide services without further subsidy. A Government-spon- for a fee to the Government, which buys the sored deployment program differs from one products and services and retains ultimate to promote commercialization in that it does authority over the planning and the pacing. not assume that an industry will ultimately be Commercialization, on the other hand, implies self-sufficient or that incentives are tempo- that the private sector makes the final deci- rary. The deployment of the synthetic rubber sions about adopting a technology.

The Rationales for Federal Intervention

From an economic point of view, Govern- erating effect on oil price increases, although ment involvement in commercialization may it is not clear what level of production would be justifiable when private industry declines be needed for this to happen. to undertake an enterprise that meets major social needs or benefits society. The penalty Private industry declines to invest in an en- for governmental inaction may take the form terprise when it lacks confidence in the pros- of a forgone social benefit, such as a de- pects for profitability. Higher expected prof- crease in national security because of insuffi- its are required of very risky projects than of cient domestic suppies of oil, or of increased more certain ones. Three types of risk for oil costs to society, such as environmental dam- shale are discussed in this chapter: age because of inadequate regulation. Socie- 1. the possibility that capital and operating ty would also have to pay if, as a consequence cost estimates may seriously underesti- of the Government’s failure to intervene, the mate a project’s cost and thus jeopardize price of a resource increased at a later time. its profitability or that the technology The deliberate stimulation of a significant will not perform as planned, level of oil shale production could be ex- 2. the possibility that world oil prices may pected to have a number of social benefits. It fluctuate in such a way that product would help reduce dependence on foreign oil. marketability will be interrupted at It would position the United States several some point in the time period required to years closer to the deployment of a major recoup the initial investment, and shale oil industry should this be made neces- 3. the possibility that regulatory delays or sary by future political or economic events. a change in environmental standards

Stimulated production might also have a mod- may adverselv affect proiect economics.— J J *, Ch. 6–Economic and Financial Considerations 183

If the Government is already intervening in shale economics by the Government will in- such a way as to penalize a new technology, hibit the use of the most efficient energy the private sector may be discouraged from sources, encourage less efficient manage- pursuing it, despite its usefulness. For exam- ment of the industry itself, increase the cost ple, the regulation of the prices of domestic of energy, and foster continued dependence petroleum and natural gas that is now being on fossil fuels. However, those who would phased out undoubtedly penalized oil shale allow the market to decide whether shale oil development. should be produced, also tend to argue that taxes on developers, restrictions on resource It is widely believed in oil shale industry acquisition, and regulatory constraints circles that the overall impact of Government should also be radically reduced. policy (e.g., regulations, permitting processes, preferential treatment of conventional petro- It does not necessarily follow from the fail- leum, and limitation of access to shale re- ure of market mechanisms to promote com- sources on Federal land) has been one of the mercialization that the Government will or most important impediments to oil shale de- can do it better. Government intervention is velopment, justified only if its benefits (appropriately A variety of groups and individuals oppose computed) are greater than its actual real Government stimulation of the oil shale indus- costs. Since the choice is not between effi- try (or other industries) because they believe cient markets and inefficient Government or that the free play of market forces will make efficient Government and inefficient markets, much more efficient and productive market but rather between inefficient markets and decisions than will any federally inspired inefficient Government, the question is which stimulation program. Those sharing this per- will be more effective in a particular situa- spective argue that favorable alteration of oil tion.

Impediments to the Commercialization of Oil Shale*

The successful commercialization of a new This usually involves solving technical prob- technology ultimately depends on its profit- lems that could adversely affect operation ability. Commercialization will not take place, and thus increase the risk of financial loss, despite Government encouragement, if devel- e.g., a component may be required to perform opers are unable to obtain a return on their beyond the capacity of available equipment, investment commensurate with returns avail- or existing mining techniques may be inade- able to them from other investments. Conse- quate for the scale of commercial-size opera- quently, in determining the proper course to tions. With MIS technologies, the need to pursue with respect to oil shale development, properly rubble shale in order to achieve nec- the Government needs to give careful consid- essary burn characteristics (and thus a high eration to the prospects for profitable oper- rate of shale oil recovery) is such a technical ation. An industry that requires permanent problem. With surface retorting, an example subsidies is a different economic proposition would be scale-up of 10 to 20 times of com- from one that needs them only for the first plex reaction systems handling massive quan- commercial-size facilities. There are three tities of solids. types of factors that influence self-sufficient profitable operation: technical, economic, Economic uncertainties are different for and institutional. those technologies that produce a substitute for an older product than they are for those Technical uncertainties primarily refer to that produce primarily new products. The the difficulties associated with scaling up a economic risks associated with shale oil new process from pilot to commercial size. center around whether it can be produced 184 ● An Assessment of Oil Shale Technologies

and sold with sufficient profitability to com- Although not as severe as the polarization pete with conventional crude. Uncertainty that has been taking place over nuclear pow- about capital and operating costs has con- er, the debate over the development of oil tinually beset corporate decisionmaking with shale and other synthetic fuels is significant. respect to oil shale commercialization. In ad- Proponents of solar power and conservation dition, developers are unable to accurately continue to oppose fossil-based synthetic predict shale oil’s marketing potential be- fuels because their development supposedly cause of uncertainty over future prices for diverts funds from the pursuit of “soft” OPEC crude. The recovery cost of most world energy strategies and discourages conserva- oil is unquestionably far lower than that of tion. Environmental groups oppose develop- shale oil, and will remain so over the life of a ment because of the possible deleterious ef- first-generation shale oil facility. Oil price in- fects on air, water, and land. Fiscal conserva- creases have begun to make shale oil very at- tives oppose Federal intervention on the tractive. However, since these prices are, in grounds that Government money should not part, set by a cartel and bear little relation to be used to subsidize private development. the cost of production, there is no certainty Although it has been argued that the popu- that they will continue to rise in real terms. * lace of the oil shale region is generally in Commercial shale oil facilities producing favor of development, local communities are 50,000 bbl/d require investments of around concerned about the impact that these facilities might have on their quality of life and the $1.5 billion (third quarter 1979 dollars). In order to recoup this investment, they will local environment. have to function profitably for 10 to 15 years. Developers believe, virtually without ex- Given the 4 or 5 years such plants take to be- ception, that delays and costs associated with come operational, it is clear that even the the permitting process are a major disincen- largest private developers would want to be tive to oil shale investment. They argue fur- confident about the trend of international ther that the possibility of new or more strict prices over the next 15 years in order to un- regulations in the future is a severe impedi- dertake commercial operations. ment to development. The imposition of new Institutional uncertainties occur because regulatory rules or standards after a plant is all technologies and economic activities take in construction or operation could require ex- place within an institutional context that can tensive and costly modification of the facili- act to facilitate or impede their commercial- ty’s design or operation. These expenses ization. The extent to which this happens de- could seriously harm a project’s economics, pends on the extent to which the technology and in extreme cases force the suspension of and its costs create conflicts over basic val- operations. The need to compensate for sig- ues or the use of scarce resources. At issue is nificant regulatory risks and disincentives is whether the aggregate impact of Government one of the primary arguments used to justify policies such as leasing arrangements, taxes, Federal subsidies. incentives, and environmental regulations would be applied more or less favorably to oil To understand the prospects for successful shale development than they would be to commercialization, it should be recognized other forms of energy. Clearly, Government that many of the technical, economic, and in- policy does not treat all energy sources stitutional impediments are interdependent. “neutrally.” In general, the potential for successful commercialization is limited by the margins avail- *Many analysts believe that the OPEC cartel has lost much able to accommodate a technology to these of its power to set prices and thal OPEC price decisions are impediments without encountering barriers. now follow ing rather than preceding market trends. Recent evi- Thus, if the relative economic advantage of a dence of market prices rising above OPEC-established prices supports this belief. So does the outcome of the December 1979 process is very large, then extensive adjust- OPEC meetings, ments to environmental standards can be Ch 6–Economic and Financial Considerations ● 185 made without reaching an economic barrier. seen, at least in part, from the point of view of When a process has relatively low technical present and potential developers. The suc- performance requirements, it may be possi- cess of any Government program to stimulate ble to reduce economic or institutional bar- the commercialization of a new technology riers by upgrading technical performance. depends, to a large degree, on the extent to However, if technical performance goals are which the policy incorporates the developers high, production costs are close to or exceed own perceptions of the risks, benefits, and the selling price for competitive products, uncertainties associated with production. and institutional barriers are restrictive, then the technology will encounter serious difficulties. Under these conditions, the usual Surface oil shale technologies are compar- response of industry would be to postpone atively well-understood with only a few re- commercial commitment while waiting for maining technical uncertainties. They are, in technical improvements, reduced institution- fact, very much the same today as they were al barriers, or improved market prices for the 20 years ago, and present little room in which product. to maneuver with respect to changing their scale of operations or improving their per- Technical problems can be reduced formance. For example, there is apparently through further R&D. Economic uncertainty no alternative to large-scale mining and the can be averted through some form of subsidy. disposal of sizable quantities of spent shale. Institutional barriers can be minimized In real terms, these technologies are unlikely through altering administrative or regulatory to become significantly less costly than they rules and timetables. are now. Thus, the possibility of technical Although other considerations are ex- tradeoffs from the technology itself is re- tremely important (e.g., overall cost to the duced, and the improvement of overall com- Government, financial exposure, and admin- mercial prospects must come through the re- istrative burden), the risks presented in com- duction of economic and institutional bar- mercializing a particular industry must be riers.

Risks, Uncertainties, and Impediments Associated With Oil Shale Development The commercialization of oil shale faces There are three additional uncertainties three primary economic risks and uncertain- related to the carrying capacity and response ties: of the institutional systems within which the the uncertainty over the costs of building oil shale industry operates that could serious- and operating commercial facilities; ly affect the economics of the industry. They the risk of unfavorable recovery-cost dif- are: ferentials relative to conventional crude ● the possibility (under conditions of rapid (except possibly those from such frontier large-scale deployment) of bottlenecks areas as Outer Continental Shelf devel- and shortages of equipment, architec- opment); and tural and engineering construction ca- the uncertain future selling prices of pacity, and trained manpower for con- world oil. structing and operating facilities; These are compounded by the partial con- ● the possible scarcity of available and nection between the costs of oil shale facil- reasonably priced investment capital ities and the rising price of energy, during the period of construction; and 186 An Assessment of Oil Shale Technologies

the potentially unfavorable effects of tive engineering designs. Also, as with similar present or future Federal and State reg- projects, oil shale development is highly vul- ulatory policies on commercial develop- nerable to changes in the cost of capital and ment. labor. These costs have increased more rapidly in recent years than the composite rate of Plant Capital Cost Estimates inflation. In addition, oil shale development will be particularly subject to regulatory re- 50,000-bbl/d oil shale facility would requirements, permitting procedures, and pos- quire a capital investment of around $1.5 bil- sible environmental litigation that could delay lion in 1979 dollars. Operating costs are esti- or arrest construction and substantially add mated by industry at $8 to $13/bbl of crude to costs. shale oil processed, exclusive of capital recovery. Such an investment would be under- A number of hypotheses have been offered taken cautiously even if the estimates of capi- to explain these cost estimate increases. tal and operating costs for oil shale plants Some argue that since the historically most were known to be accurate. However, during accurate method of estimating the price of the past 10 years, capital cost estimates have shale oil is simply to add $5 to the price of im- increased much more rapidly than has the ported oil, oil shale companies are exaggerat- general rate of inflation, and still do not ap- ing their costs in order either to prepare the pear to be totally reliable. The experience of market for high selling prices or to get large Colony Development is illustrative but not ex- governmental subsidies. This charge has its ceptional. Its direct capital cost estimates for basis in the observation that the rise in shale a 43,000-bbl/d facility increased from $225 oil cost estimates has paralleled foreign oil million in 1972 to $1.3 billion in early 1979, prices, and seems to increase each time the and were $1.7 billion in February 1980. (See Government gives serious consideration to in- table 22.) dustry subsidies, Neither this nor any other investigation has produced evidence that cost Cost escalations of this magnitude are not increases are contrived, Most of the vari- unusual for large, capital-intensive facilities ations in cost increases and estimated prices involving complex novel technologies. As for oil shale can be explained by examining demonstrated by experience with light water four significant variables: reactors, many coal gasification plants, Ca- nadian tar sands, and various weapons sys- . increases in the general rate of inflation, tems, cost estimates are likely to rise rapidly ● escalations in the real costs of plant con- as a process advances from initial to defini- struction.

Table 22.–Cost Estimates for Oil Shale Processing Plantsa — — Estimated cost Time of estimate $ million Data source Scope and detail of estimate 1968 $ 138 Department of the Interior Initial 1968 144 The 011 Shale Corp Initial 1970 ., 250 National Petroleum Council Initial 1973 280 Department of the Interior Initial 1973 : : 250-300 Colony Development Operation Initial Early 1974. . 400-500 Colony Development Operation Detailed (early version) Late 1974, 850-900 Colony Development Operation Detailed 1976 960 The Oil Shale Corp. Update 1977 1,050 The Oil Shale Corp. Update 1979 : : 1,350 OTA Update 1980 1,700 The 011 Shale Corp. Update

aplanl~ “se underground rnlolog and above-ground retorting to produce approximately 50000 bbl Id Of shale 011 syncrude SOURCE Office of Technology Assessment Ch 6–Economic and Financial Considerations 187

more stringent environmental standards important because of the way it affects the for oil shale operations, and perceptions of developers. The factors that increases in estimates as a consequence influence relative price changes are, how- of more complete and detailed knowl- ever, considerably more significant. edge of a facility’s actual design, Escalations of Plant Costs Increases in the General Rate of Inflation Large plants are vulnerable during periods Many developers believe that chronic infla- of extreme inflation when the demand for tion during the last 10 years has been the pri- necessary equipment and services rises mary cause of the exceptional cost escala- sharply relative to their supply. Such a period tions. Although inflation rates were very high existed in 1974. From mid-1973 to 1975 the between 1972 and 1976, this view is appar- general price index increased in excess of 20 ently incorrect. For oil shale developers fac- percent, but chemical industry equipment in- ing nominal rather than adjusted real prices, creased by approximately 70 percent, and the overall impact of dollar inflation would certain key items such as compressors and appear quite large. The rate of general price heat exchangers increased by almost 100 inflation also tends to drive up the interest percent. It was during this period that the rates on construction loans. However, as cost estimate for the Colony oil shale plant ap- shown in figure 51, during the period from proximately doubled. 1972 to 1977, not more than 12 percent or ap- The effects of severe sectoral inflation on proximately $100 million of the cost estimate increases were due to changes in the general project costs are even greater than those sug- price index. The rate of general inflation is gested by the above numbers, which are based on list prices that are often discounted. Discounts are eliminated as industry inflation accelerates. Figure 51 .—Increases in Capital Cost Estimates In a crash program for synthetic fuels, there will almost certainly be real cost escalations and overruns. The first few plants Surface shale plant estimates committed could contract for a significant . part of the available U.S. manufacturing capacity for key items such as valves, pumps, compressors, and pressure vessels. As additional plants reach the procurement stage, . equipment suppliers would be forced to quote longer and longer delivery times. These entail lncreases from Max environmental higher price contingencies for contractors to costs [ Min cover unknown increases in supplier costs, and can have a devastating impact on large . capital projects. Almost half the total per- barrel cost of synthetic fuels is estimated to be solely the carrying cost of the capital investment. project owners will, therefore, be 1971 1972 1973 1974 1975 1976 1977 willing to bid up the prices for essential Year equipment in order to save time. A single week’s delay could increase costs by millions “ Dupont Index This Index gives the gradient of change for Industrial process plant costs Although not entirely appropriate for 011 shale plants, it IS the best of dollars. available Index However It probably somewhat understates plant cost escala tions

SOURCE Edward W Merrow Cons frafnts on the Cornmercia/lzatlon of 0// Because of the potential for extreme sec- Sha/e 2293 DOE September 1978 toral inflation, costs could increase dramati- .—.—.—

188 . An Assessment of Oil Shale Technologies

cally in a crash program. Building 20 plants ● less efficient facility operation, and could cost considerably more than twice the ● costs of potential litigation. cost of building 10 plants. Any savings in Each of the above can have enormous im- design costs by building duplicate plants would be wiped out by cost increases. Plant pacts on plant economics; delays occurring construction costs during an all-out crash late in the construction stage are particularly program are likely to increase in real terms costly. A 6-month delay in the middle of con- by 50 percent or more.3 struction could add more than $100 million to costs. Additional environmental equipment can substantially reduce reliability and the Increases Due to Environmental Regulations on-stream factor, * if operations must cease The environmental legislation passed dur- when environmental equipment fails. A re- ing the late 1960’s and early 1970’s, along duction in the on-stream factor of 5 percent with the provision of substantial enforcement will increase the required selling price of the power to the Environmental Protection Agen- product by 7 percent. A construction delay cy, altered the context in which large-scale such as might be caused by environmental industrial development may now take place. litigation can be extremely costly after Without question, this legislation, which has ground has been broken. The costly delays been paralleled by similar State laws, has and disruptions described here will probably been and will continue to be very costly to in- characterize only a fraction of the projects dustry. It is not possible, however, to accu- undertaken. Nevertheless, they constitute a rately ascertain what the actual costs of significant risk that must be included by de- meeting these standards are, because the velopers in their contingency plans. costs are both direct and indirect. Most esti- Environmental regulations add to devel- mates usually include only the former cost opers’ estimates of uncertainty and risk. The category. Cost estimates for meeting some of uncertainty is over how present regulations the standards are discussed in detail in chap- will be interpreted, administered, and enter 8. forced; and the risk derives from the possibili- In 1978, the RAND Corp. estimated that the ty of future regulations. Rather than making direct costs of pollution control technologies an attempt to predict with some degree of ac- for oil shale developers ranged between 6.5 curacy what might be the indirect effects of and 15 percent of total capital costs. These environmental standards on plant economics, were primarily for eliminating hydrocarbons, developers have increased the size of their particulate, and hydrogen sulfide from the estimates as a hedge against uncertainty, retorting process, and for dust control and based on their informal sense of general risk. spent shale disposal. By assuming a zero val- Although environmental regulations have sig- ue for environmental costs in 1971, RAND nificantly augmented industry’s capital cost goes on to estimate that between 8 and 20 estimates, they nonetheless are responsible percent of the increases in estimated capital for less than than 20 percent of the overall costs or $65 million to $165 million between cost estimate escalations since 1971. 1971 and 1978 were caused by environmental factors. The Learning Curve for New Plant Design These estimates do not include the possible The escalations due to improved knowl- indirect environmental costs that might occur edge about costs, as a consequence of more because of: complete engineering designs, appear to be responsible for the largest increases in capi- ● necessary siting changes, ● alterations of mining plans, *The on-stream factor is the proportion of operating days ● disruption of construction schedules, per year. Ch 6–Economic and Financial Considerations ● 189 tal cost estimates. Between 40 and 50 percent creases have characterized the development of the estimated increases between 1971 and of coal gasification, coal liquefaction, Cana- 1977 were of this kind. dian tar sands, light water nuclear reactors, and a variety of new weapons systems. How- Forecasting the costs of constructing a ever, several characteristics of oil shale commercial facility for a new technology is plants present particular design and estima- normally based on a series of engineering de- tion problems. First, such plants are highly sign estimates, each of which is presumably more detailed and accurate than the previous site specific. The costs of transporting, mining, handling, and disposing of shale all de- one. There are four types of such estimates. They start with initial estimates, which are pend on the nature of a site’s topography, ge- “back of the envelope” predictions that give ology, and surrounding terrain. Second, the estimation of oil shale plant costs requires an only a rough indication of eventual costs; proceed through the preliminary design estimate array of engineering, architectural, economic, and technical skills possessed by only a in which the plant’s subsystem flows are de- few architectural and engineering firms. fined, but component subprocesses are not defined; continue with the detailed design in The reliability, or on-stream factor, for the which estimates are prepared for specific plant after it is constructed, figures signifi- materials and components; and end with the cantly in the eventual cost of production. Cost final design estimate in which precise costs estimates compute the cost of building the for all materials, components, and labor are plant, and then assume that it will be on- pulled together. The final design estimate stream about 90 percent of the time. There is should accurately locate the cost of immedi- a high probability, however, that pioneer ate construction to between plus or minus plants will not operate as planned for some [usually plus) 15 percent of the eventual cost. time, or until such time as additional in- The cost of preparing a final engineering vestments are made to correct their prob- design estimate for a commercial-size oil lems. For this reason, companies tend to build shale facility is between $12 million and $20 only those designs that are known to work, million. To date, only detailed design esti- even though new but untried approaches may mates have actually been carried out. The in- promise appreciable savings. tention of this iterative estimation process is to provide continually better design forecasts As technical data improve and developers based on continually more precise technical complete more detailed design estimates, the gradient for real cost escalations will level data derived from increasingly larger devel- off. It is probable, but not certain, that cur- opmental tests, As the designs become more complete and the technical data improve, the rent cost estimates are fairly realistic and costs become clearer. that there will be no further substantial increases, other than normal inflation. How- The cost estimate escalations that took ever, no commercial-sized facilities have place between 1973 and 1976 occurred, in been built, and cost estimates are unlikely to part, because prior to the middle of 1974, no become stabilized without industry experi- final or detailed engineering design estimates ence in constructing and operating such facil- had ever been prepared. Colony Oil Shale De- ities. velopment Corp. ’s detailed design estimate represented an 80-percent increase over the preliminary design estimate made 10 months Uncertain Future Prices of World Crude earlier. The subsequent experience of other The market price of premium grades of developers with their more detailed designs conventional crude oil is a major determinant was similar, of the highest possible profitable selling Cost estimation increases are by no means prices for syncrude from shale. Therefore, limited to oil shale facilities. Similar in- present and future prices for conventional 190 ● An Assessment of 011 Shale Technologies crude are among the basic factors that will Second, most analysts expect international condition the economic viability of the oil oil prices to increase by 3 or 4 percent per shale industry. A developer who commits year, over and above inflation. This will mean $1.4 billion to $1. i’ billion to a shale oil plant that the price of oil will double, in real terms, with a very long payback period must be rea- by 2000. However, because international oil sonably confident that the market value of the prices are still set, in part, by a cartel, the product will exceed its production costs. future of the market cannot be predicted with Uncertain future prices of international oil any certainty. Increasing or continued high prevent firms from accurately predicting demand, decreasing world reserves, and market values for shale oil. Since the Arab oil OPEC or producer-state governmental poli- embargo of 1973-74, the actions of the OPEC cies directed at conserving their reserves cartel and high international demand have through price rationing could result in sus- pushed the price of world oil far above recov- tained price inflation for imported oil. On the ery costs. other hand, prolonged recession in the industrial West or reduced international demand Between September of 1979 and February could limit oil price increases in the future. of 1980 the prices of world oil increased by Recent events strongly indicate that OPEC’s over 30 percent. In March of 1980, the posted capacity to set international oil prices has prices of the premium grades of conventional been substantially weakened. Nevertheless, crude (the counterpart of upgraded shale oil) the play of market forces is still likely to main- stood between $34 and $38/bbl. Their spot- tain upward pressure on prices. In any event, market prices (e.g., for Wyoming Sweet and future incremental price increases are not the best grades of Nigerian and North Afri- likely to be regular. Instead, temporary peri- can oil) are currently between $40 and $52/ ods of oversupply and soft markets are likely bbl. Sweet crude oils were recently sold from to alternate with shortfalls and high demand. the Elk Hills and Teapot Dome Petroleum Re- Therefore, short periods of stable prices will serves for $43 and $50/bbl respectively. probably alternate with rapid price in- These increases, along with the probability of creases. further escalations in the future, have substantially improved shale oil’s economic at- Finally, the question of whether present tractiveness. The future viability of shale oil and future oil prices will allow profitable sell- is predicated on the assumption that in- ing prices for shale oil without subsidy decreases in its production costs will lag behind pends on the discount rate that firms are as- the rising price of world market crude. On the sumed to require in order to undertake devel- basis of the best current capital and operat- opment. The average real aftertax returns on ing cost estimates (compiled between Novem- investment of U.S. industrial firms is gener- ber of 1979 and February of 1980), it appears ally between 6 and 10 percent. Given the that shale oil may have reached parity with risks associated with a pioneering industry, conventional oil without subsidy. However, oil shale developers will require a larger this conclusion is subject to several critical profit than that obtained from less risky proj- limitations. ects. Industry sources generally maintain that this would mean a real aftertax expected First, this finding assumes that current profit of between 12 and 15 percent. Break- capital and operating cost estimates are, in even selling prices for shale oil are extremely real dollar terms, within 20 percent of being sensitive to the discount rate, which at 12 accurate. Given that such projects have percent would make shale oil competitive never been previously undertaken, still lack with conventional petroleum according to final engineering design estimates, and are OTA’s analysis. However, if developers re- prone to possibly severe inflation because of quire a is-percent rate of return to under- associated heavy equipment costs, this may take investment, then subsidies will probably be a very risky assumption. still be necessary. Ch 6–Economic and Financial Considerations ● 191 .-

Choosing Goals for Oil Shale Development

The Federal Government has a variety of swer most of the remaining technical, eco- options available to stimulate oil shale devel- nomic, and environmental questions. It would opment. In order of increasing Government also facilitate the selection of the most feasi- involvement, these include: ble oil shale and synthetic fuel technologies available today; provide information for ra- continuing present policies and provid- tional decisions regarding oil shale commer- ing no additional incentives; cialization; and put the United States several modular encouraging precommercial years closer to full-scale production capacity. plants; building and operating a number of Gov- A modest program for stimulating the con- ernment-owned modules; struction of a limited number of commercial encouraging a few commercial-sized or modular facilities would be less likely to plants; and fail, Such a strategy reserves judgment con- deploying a major industry. cerning the ultimate extent of development Each option differs with respect to the cost until the processes have been tested. This has to the Treasury, the level of shale oil produc- the advantage of allowing policymakers to tion, the risks of cost overruns and inefficien- evaluate commercial results and consider cy, and the impacts on the physical and social alternatives for further reduction of oil im- environments. They also vary with respect to ports prior to contracting for additional the extent and types of financial incentives facilities, and should improve the chances of that would be most effective. ultimately establishing a self-sufficient oil shale industry. It should be noted, however, There are two major policy goals to be met that the information base strategy tends to ig- by an oil shale industry. One is to deploy nore the fact that technology is not static but enough production capacity to answer the re- is continually changing, By gathering data on maining uncertainties related to economic “today’s” processes, this approach may ig- and technological feasibility and environmen- nore possible (probable) future process devel- tal impacts, The other is to quickly displace opments. It is possible that complete informa- foreign oil imports. tion could be obtained on several processes in the next 10 years only to discover that a new Information Base Goal process may be more productive. Should policy be to repeat the cycle and obtain more in- Because no oil shale process has as yet formation, or to build the obsolete plant? been commercialized, the economics, techni- From an economic standpoint the choice is cal operability, and environmental impacts of not a simple one. each of the processes are still not fully known. If the most promising processes were In the absence of time limitations, the over- operated at either the precommercial modu- demand for scarce capacity in construction lar scale or at commercial capacity many companies, in skilled labor, in plant materi- questions could be answered and compari- als, and in architectural engineering firms sons among the various processes would be would be reduced or even avoided. When possible, Operating experience could be ac- these are placed in short supply, costs esca- quired by providing incentives to industry, by late, the quality of design is lowered, and operation of Government-controlled modular fewer plants may be constructed. test facilities, or through some combination of both. A1though some questions could be an- ICF in a recent study for the Budget Com- swered by research, a moderate development mittee of the U.S. Senate4 summarized the and production program would reliably an- benefits of proceeding with development in a 192 . An Assessment of 011 Shale Technologies two-phased strategy by maintaining that such how cost-effective shale oil development is an approach would: compared with other energy strategies in achieving import reductions; 2) whether the ● be an effective symbolic action showing costs and risks of a crash program to develop the seriousness with which the United a large industry outweigh its potential States intends to reduce energy imports; benefits and whether such a program would ● provide the opportunity through follow- achieve its production goals; and 3) if a rapid on stages of development to reduce ener- development strategy would have unaccept- gy imports directly through shale oil pro- able environmental costs. duction, while maintaining the option to consider more cost-effective ways of im- Establishing a large industry to replace port reduction; and foreign oil would have both positive and nega- ● provide the flexibility that has been tive effects. On the positive side, the economy found to be critical in advancing new and national security would benefit from a re- technologies to a commercially viable duction in oil imports; and in the oil shale re- stage. gion, employment would rise and an in- An information base strategy initially fol- creased tax base would provide revenues for lowed by review and possible subsequent ad- community development. On the negative ditions, as discussed in this chapter, has also side, such a program would be extremely been suggested by the RAND Corp., ICF, Cam- costly. It would necessitate investing in nu- eron Engineers, Booz-Allen, and the Congres- merous plants, each with a capital cost of sional Budget Office. It assumes that the prin- around $1.5 billion. Technologically inferior cipal goals are to create a viable industry, processes might be used because of insuffi- minimize the cost to the taxpayer, and max- cient time for supporting technical R&D, and imize the efficient use of capital. the accelerated construction schedule could lead to cost overruns and managerial ineffi- If, however, the primary goal is to reduce ciency. (The use of a “technologically inferi- dependence on foreign oil by 1990, then the or” process could, however, be compensated extensive development of a large oil shale in- by the inflation savings; a better process built dustry might be more advisable. Economic 10 years later would probably cost much analysts have examined whether producing more in real terms because of inflation of additional oil shale (or other synthetic fuels) plant costs.) Capital availability for other eco- is more cost-effective than alternative ap- nomic sectors could be restricted. It is also proaches such as conservation. Their anal- questionable that mining and processing yses depend on the assumption that the desir- equipment could be supplied within the con- ability of synthetic fuels is chiefly a matter of struction time frame. Furthermore, it is possi- price rather than availability. Another OPEC ble that the lack of supporting environmental oil embargo could change this assumption. R&D could lead to a conflict with environmental standards. On balance, the socioeconomic Foreign Oil Displacement Goal effects could well be more negative than positive. If present trends continue, the United States could import around 12 million bbl/d of There is general agreement among the en- oil by 1990. It is beyond the scope of this gineering and construction firms contacted report to examine whether this import de- by OTA that a program to establish a large oil pendence could be reduced to the President’s shale industry (over 500,000 bbl/d by 1990) target of 8.5 million bbl/d through conserva- would entail sizable cost overruns because of tion, synfuel production, and conversion from high inflation in critical supply industries. It oil to coal. To estimate the desirability of the would also impose severe time constraints on contribution that shale oil could make to re- a developer’s operations. Contractual agree- ducing import reliance requires examining: 1) ments for these facilities would have to begin Ch 6–Economic and Financial Considerations ● 193 immediately and continue under conditions of A major Government effort to establish an tight scheduling for the next 8 to 12 years. industry based on a new technology under Various studies of the consequences of Feder- time constraints does not allow sufficient al funding to stimulate the commercial adop- time to review progress, make cost-benefit tion of new technologies, including the 1976 tradeoffs, and modify plans in response to study by the RAND Corp.,5 report that subjec- new knowledge, When a pressing national tion to severe time constraints has rarely re- emergency requires a crash program, the resulted in the establishment of a viable indus- sultant inefficiencies entailed by these re- try. Furthermore, a rapid development effort strictions may be justified. However, when would probably require the commercial oper- the primary purpose is to establish a self-suf- ation of facilities before the technologies and ficient industry, crash programs should be their economics were fully understood. avoided.

A Comparison of Alternative Financial Incentives Before oil from domestic shale can signifi- Price support. With this incentive, the cantly supplant imported supplies, any devel- Government guarantees the developer a opment program must take into account the certain price for shale oil; the analysis major technological, environmental/regulato- assumed $55/bbl of hydrogen-upgraded ry, and economic uncertainties that discour- syncrude (hydrotreated shale oil). If the age private firms from undertaking such in- market price for the product falls below vestments. To overcome these uncertainties, the guaranteed price, the Government Congress is contemplating implementing an would make up the difference. incentive program that would share in the Purchase agreement. The developer con- risks or subsidize the economics of oil shale tracts with the Government to sell shale development. In evaluating alternative incen- oil at a price higher than the prevailing tives and their probable effects on oil shale market price; the analysis assumed a development, the reactions and preferences price of $55/bbl of upgraded product. of developers must be taken into considera- Increased depletion allowance. The de- tion. veloper is allowed to claim a 27-percent In conducting this analysis, 10 alternative depletion allowance (at present it is 15 incentive structures were examined: percent). Increased investment tax credit. The de- ● Construction grant. The Government veloper can claim an additional invest- provides a direct grant to cover a pre- ment tax credit of 10 percent, specified percentage of total construc- Accelerated depreciation. The firm is al- tion costs, both a 50- and 33-percent lowed to depreciate its investment over 5 construction grant were analyzed. years. ● Production tax credit. The developer re- Loan guarantee. The Government would ceives a tax credit for each barrel of agree to pay off a loan in the event that shale oil produced, a $3/bbl credit com- the firm defaults on its loan: the firm puted on shale oil prior to upgrading was would typically receive a lower interest analyzed. rate than that prevailing in capital mar- ● Low-interest loan. The Government kets. lends the developer a prespecified per- Government participation. The Govern- centage of capital costs at an interest ment would become an equity partici- rate below the prevailing market rate; pant in an oil shale project. the analysis assumed 70-percent Gov- ernment financing at 3 percentage To evaluate how effectively the different points below the market rate. incentives will promote the development of a —

194 ● An Assessment of 011 Shale Technologies viable oil shale industry, each was analyzed pay the same prices for resources (i.e., in relation to three fundamental objectives of land, labor, capital, and materials) that the congressional incentive program. * These are paid by firms engaged in other pro- objectives are: duction activities in the general economy (i.e., the prices paid should equal the val- ● Subsidizing the economics of shale oil ue of these resources in alternative production. The mechanism by which uses). Similarly, the price received for each incentive affects the perceived eco- the shale oil by producers should equal nomics of oil shale development and how its value to the economy. This will be the well it functions as a subsidy was ana- marginal price of crude oil, because up- lyzed. graded shale oil and crude oil are almost ● Sharing in project risks. The extent to equally substitutable. Therefore, OTA which each incentive allows the Govern- analyzed the extent, if any, to which ment to share in the risks of oil shale de- each incentive would interfere with development, and the extent to which it re- velopers’ perceptions of the market duces the variance of the present value prices of the productive resources con- of the aftertax income from a project sumed in shale oil production or the mar- was analyzed. To conduct this analysis, ket price for the final product. a project risk was assigned for four spe- ● Minimal administrative burden. The cost cific categories: the risk of unsuccessful of administering an incentive program project completion, which stems largely represents a loss to the economy that from technological and regulatory un- falls on the public and private sectors certainties; the risk associated with un- alike. In addition, the administrative certain investment costs; the risk associ- burden affects the time required to im- ated with uncertain operating costs; and plement a program as well as its overall the risk associated with uncertain future effectiveness. Therefore, OTA analyzed prices for oil from shale. the administrative requirements for ● Facilitating access to capital. The extent each of the incentives. to which each incentive would sufficiently induce capital markets to lend the Finally, the analysis was structured to large sums of money that will be re- assist Congress in developing an incentive quired to develop an oil shale industry program to meet a third policy guideline: to was examined. This consideration is promote a healthy state of competition in the particularly important for understand- industry, Because of the potential multiplicity ing which types of firms would benefit of objectives for an incentive program, and from specific incentives (i.e., whether an the variety of types of firms involved, it is incentive will benefit less well-capital- probably necessary that the incentive pro- ized firms or those with limited ability to gram consist of a package of incentives. This incur debt). should allow firms in differing financial, technical, and tax circumstances all to benefit. Once it was determined how well each incentive met each of the program’s objectives, To clarify the competitive implications of a it was examined in the context of two impor- program consisting of a combination of incen- tant policy guidelines: tives, the kinds of firms that would most benefit from each incentive were identified ● Efficient use of the Nation economic re- based on the analyses of the incentives, a sources. To make efficient investment review of industry statements, and discus- decisions,** oil shale developers should sions with industry representatives. Specific examples of firm preferences for the differ- *Congress, before designing an incentive program, should ent incentives have been documented. The ef- specify the relative emphasis to be placed on each objective. **This definition of efficiency is in the somewhat narrower fects of the various incentives on the program sense of its use in economics. objectives and the policy guidelines are sum- Ch 6–Economic and Financial Considerations . 195 marized in table 23. The rank-order prefer- less increased tax payments to the Gov- ences of different shale oil developers for the ernment. * An incentive increases tax re- various financial incentives are summarized ceipts if the present value of the tax pay- in table 24. In order to make a comparison of ments is larger with the incentive than if the incentives and evaluate their contribu- an equal investment was made without tions to the objectives of the total program the incentive. OTA estimated both the and the policy guidelines, a computerized actual cost to the Government and the simulation model developed by Professors ratio of the change in expected profit to Wallace Tyner (Purdue University) and Rob- cost. ert Kalter (Cornell University]” was used to test and measure each of them against the With these computations, the way in which case in which no incentive is offered. The a firm’s marginal tax rate** (and, for a low- present calculations with the Kalter-Tyner interest loan, its cost of borrowed funds) influenced expected profits was assessed, and model were prepared for OTA by Resource Planning Associates, Washington, D.C. A the sensitivity of expected profits to different complete description of the simulation model, discount rates (defined as the minimum rate its capabilities, limitations, and how it was of return necessary to induce private development) was determined, employed can be found in appendix B. Using the model, it was possible to estimate the fol- The numerical results of this analysis, lowing four variables (for all but the produc- which are summarized in tables 25 and 26, tion tax credit and loan incentives): were calculated using the best available data . Expected profit. Expected economic for the cost of commercial oil shale facilities. profit is defined as expected return in They thus provide a reasonable approxima- excess of a company’s minimum re- tion of the magnitude of the probable effects quired aftertax return on its oil shale in- of each of the incentives. While these out- vestment. * OTA calculated both ex- comes would not be expected for the opera- pected profit and the change in expected tion of an actual facility, they would be for profit relative to the no-incentive case. the average operations of a number of facil- Risk. The risk of the investment refers ities. Because of the uncertainties inherent in both to the probability of the investment the estimation, the most useful application of resulting in an economic loss (i. e., earn- these quantitative results is for establishing ing less than the minimum required rate comparisons among the incentives. of return), and to the degree of variation Congress is currently considering 10 major in possible profit outcomes, OTA meas- kinds of incentives to be included in a domes- ured this variation in absolute terms tic oil shale development program. The anal- (i.e., the ratio of change in expected ysis of the specific effects of each of these on profit to standard deviation of expected the three program objectives and the three profits). policy guidelines is summarized below. The ● Breakeven price. The breakeven price is discussion also includes a quantitative evacu- the constant price for hydrotreated** ation of the impact on expected profits, on shale oil at which it would just earn its minimum required rate of return. *Government cost was calculated in present value terms as ● Cost to the Government. The expected was private profit. Net cost for each year (i. e., subsidv less in- cost to the Government of providing the creased tax revenues) was discounted at the Government’s dis- incentive is the gross subsidy to the firm count rate (assumed to be 10 percent in real terms). The resulting present value calculations were summed for all years. *Profi I was measured as the sum of each yea r’s cash flows, **The marginal tax rate is the rate at which income from an dis(:ounted using the company’s minimum required aftertax additional investment (e. g., an oil shale facility) is taxed by the rate of return as a discount rate (see app, B). Government. For most firms, this is 46 percent. However, a * *In hydr~ treatment the physical properties of raw shale oil firm wiih excess tax deductions or credits from other opera- are improved by adding hydrogen and removing nitrogen and tions would apply the excess to the oil shale investment, there- sulfur. The product is often referred to as syncrude. by reducing its marginal tax rate. Table 23.–Evaluation of Potential Financial Incentives for Oil Shale Development

Effect of incentive on program objectives Extent to which incentive meets policy guidelines Promotion of Minimization of Promotion of competition Incentive —-. Subsidy effect Risk-sharmg effect Financing effect economic efficiency administrative burden Effect on firms Firm preferences 1 Production tax Strong, subsidizes Moderate, shares risk Slight, improves Slight adverse effect, Minimal administrative Benefits firms with Supported by relatively credit ($3/bbl) product price associated with price un- project economics distorts product price burden large tax Iiability and large firms certainty (If tax credit varies strong financial with product price) capability 2 Investment tax Strong, subsidizes Moderate: shares risk Slight, Improves Moderate adverse effect; Minimal administrative Benefits firms with Supported very strong- credit (additional investment cost associated with Investment project economics distorts input costs, burden large tax Iiability and ly by most firms; lo%) % cost uncertainty favors capital-intensive strong financial however, firms that technologies capability would not be able to use the investment tax credit do not favor its enactment 3. Price supper Strong, subsidizes Moderate; shares risk Moderate; improves Slight adverse effect, Moderate Benefits all firms Moderately supported product price (If con associated with price borrowing capa- distorts product price administrative burden except those with by a wide range tract price IS higher uncertainty bility very weak financial of firms than market price) capability 4 Loan guarantee Slight, subsidizes Moderate, shares risk of Strong; improves Slight adverse effect; Moderate admin - Benefits firms with Supported by firms Investment cost project failure borrowing capa- distorts input costs: istrative burden weak financial with limited debt bility favors capital-lntenswe capability capacity technologies 5 Subsidized Interest Slight; subsidizes Moderate: shares risk of Strong, Government Slight adverse effect; Moderate admin- Benefits firms with Supported by firms loan (70% debt at Investment cost project failure provides capital distorts input costs, istrative burden weak financial with Iimited debt 3% below market favors capital-intensive capability capacity rate) technologies 6. Purchase Strong, but less than Strong: shares risk of price Moderate; improves Slight adverse effect, Moderate (normally Benefits all btrms but Moderate, but less agreements price supports uncertainty financial capability distorts product price more than price sup- those with very weak than for price supports) ports) financial capability supports 7. Block grant (33 & Strong, neutral None Strong; Government No adverse effect Moderate admi- Benefits all firms Supported by firms in 50% of plant cost) subsidy provides capital nistrative burden widely varying financial circumstances 8. Government Slight Strong, shares all project Moderate, reduces No adverse effect on firm Major adminstrative Benefits firms that are Little support participation risks firm’s capital require- decisions; however, burden very averse to risk ment active Government (e. g., smaller, less Involvement may lead well-financed firms) to inefficiency 9 Accelerated de- Moderate, subsidizes Moderate, shares risk Slight, improves Moderate adverse effect, Minimal administrative Benefits firms with Supported by large, predation (5 years) Investment cost, associated with Investment project economics distorts input costs, burden large tax Iiabilities integrated oil maximum subsidy ef - cost uncertainty favors capital-lntenswe and strong financial companies feet IS Iimited by Fed- technologies capability eral corporate income tax rate and interaction with the depletion allowance 10 Percentage deple- Moderate, subsidizes None, Increases risk Slight, improves Moderate adverse effect, Minimal administrative Benefits firms with Not supported tion allowance product price, value associated with price un- project economics distorts product price in burden large tax Iiabilities (27%) of subsidy Increases certainty a variable and undesir- and strong financial as the need for the able manner capability subsidy decreases

SOURCE Resource Planmng Assoclales Inc Ch 6–Economic and Financial Considerations ● 197

Table 24. –Summary of Companies Ordinal Preferences for Incentives

Liberalizing Price Ieasing Produc - invest - guarantee/ and land Company tion tax ment tax purchase Loan Low- Block Accelerated Government management Percentage credit credit agreement guarantee Interest loan grant depredation. participation terms depletion Union 0il 2 1 3 4 4 — — . Colony project Tosco 2 3 4 1 1 3 . — ARCO 1 2 3 4 — — — — — Superior 2 1 3 1 1 — — 1 — Occidental 2 4 3 1 1 — — — — RIO Blanco project Gulf 1 2 3 — — 3 2 — Standard (Indiana) 4 2 5 5 3 1 — — SOHIO Natural Resources 4 5 3 2 2 1 — 1 — — EXXON — — — — — — — — 1 — Standard (California) 3 1 4 — — — 2 — — Conoco 3 1 4 — — 2 — — —

NOTE Vo compan~ malcated any preference for the Percentage dei)letlon lncentlve Rank orcered by preference 1 = most preferred elc SOURCE Resource Planmng Assoclales Inc

Table 25.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (12-percent rate of return on invested capitalb)

Ratio of change Total Ratio of change in expected expected in expected Total expected Change in Standard profit to cost to profit to profitc expected profit deviationd standard Probability Breakeven Government Government Incentive ($ million) ($ million) ($ million) deviation of loss price ($) ($ million) cost Construction grant (50%) $707 $487 $205 2,4 0.00 $34.00 $494 98 Construction grant (33%) 542 321 210 15 0.00 38,70 327 98 Low-interest loan (700/0) 497 277 219 13 000 43.40 453 61 Production tax credit ($3) 414 194 219 0,9 001 42.60 252 77 Price support ($55) 363 42 171 0.8 001 NA 172 .83 Increased depletion allowance (27%) 360 40 247 05 0,05 45.70 197 71 Increased Investment tax credit (20% ) 299 79 216 0.4 0.05 45.80 87 90 Accelerated depredation (5 years) 296 76 215 04 0,05 46.00 79 96 Purchase agreement ($55) 231 11 126 01 0,03 NA o NA None 220 o 219 0.0 0.09 48.20 0 NA aAll monetary values are In constanf 1 ’379 dollars bw,!h 12 percent annual ,nfla~lon a 12 percent real d{scoun[ rate IS approximately a 24-percent nominal aflerfax rate of return The calculahons assume a $35~bbl Price for conventional Premium crude that escala[es at a real rate of 3 percent per year Thus [he predlcled $48/bbl breakeven price for the 12-percent discount rate WIII be reached In 11 years or {n the fifth year of producf(on Therefore In narrow econom(c terms 011 shale planls starllng construcflon now which assume a 12-percent dlscounf rate WIII be profitable over the hfe of Ihe project without subsidy ( See discussion for caveats concerning this conclusion I The calculal!ons are for a 50 000-bbl d plant cosllng $1 7 b[fl(on cExpecled profl! IS the relurn in excess of a 12 percent discounted cash flow rate of return on !nveslment dslan~ard devla[lon IS a measure of the dispersion of possible proflf ou~comes around expected Profl~ SOURCE Resource Planmng Assoclales Inc firm risk reduction, on breakeven prices, and receive a $3/bbl credit on Federal income on the cost to the Government. taxes. Projects operating after April 20, 1977, and in production between 1979 and Production Tax Credit 2000, would be eligible. The $3/bbl credit would be defined in real terms; that is, the In the 96th Congress (1979), the Senate Fi- credit would increase with inflation. This nance Committee approved a production tax proposed credit will be phased out on a slid- credit for alternative forms of energy. Under ing scale as the price of imported oil in- this proposal, producers of shale oil would creases. 198 ● An Assessment of 011 Shale Technologies

Table 26.–Subsidy Effect and Net Cost to the Government of Possible Oil Shale Incentives’ (l S-percent rate of return on invested capitalb)

Ratio of change Total Ratio of change in expected expected in expected Total expected Change in Standard profit to cost to profit to profitc expected profit deviation standard Probability Breakeven Government Government Incentive ($ million) ($ million) ($ million) deviation of loss price ($) ($ million) cost Construction grant (50%) . $281 $477 $135 35 0.00 $40.60 $494 96 Construction grant (33%) 119 315 140 2,2 019 47.70 327 96 Low-interest loan (70%) 81 277 153 1.8 023 54.70 453 61 Production tax credit ($3) -61 135 153 0,9 063 58.30 252 .54 Price support ($55). ., ... -88 108 122 09 0.77 NA 172 63 Increased depletion allowance (27%) . -110 86 170 0.5 0,75 57.20 197 44 Increased Investment tax credit (20%), -131 65 150 0,4 0.77 58.80 87 75 Accelerated deprecation (5years) . -127 69 149 0.5 076 58.90 79 87 Purchase agreement ($55). -150 46 102 0,4 092 NA 0 NA None. . . ., -196 0 153 0.0 0.93 61.70 0 NA

aAll monetary values are In constant 1979 dollars bwllh 12.0ercent annual Ifltlatlon a 15-oercent real dlscounl rate IS acmroxlmatelv a 27-oercent nominal afteflax rate ot return cExPec(ed P(ofll IS the return In excess Of a 15.percenl discounted cas’h tlOW rale’of return on Inveslmenl dstandard devla[lon IS a measure Df (he dispersion of possible profll OUtCOmeS around expected Profll SOURCE Resource Planmng Associates Inc

This tax credit will strongly subsidize the ing costs and the resultant project profitabil- production of shale oil. By reducing a firm’s ity, it may provide a sufficient asset base tax liability, it effectively increases the unit against which firms may borrow for project product price by an amount equal to the tax financing. However, it will not assist project credit per unit of production (i.e., per barrel) financing as strongly as a purchase guaran- divided by 1 minus the firm’s Federal corpo- tee or a debt guarantee. rate income tax rate. For example, if a com- The production tax credit also can enhance pany’s tax rate is 46 percent, a $3/bbl credit economic efficiency, because it does not dis- becomes an effective price boost of $5.60. At tort a firm’s perception of the market prices current imported oil price averages of $35/ for the economy’s productive resources (i.e., bbl, the effective price with the credit would land, labor, capital, and materials), that are be $42.60. This price boost could substan- consumed in development and production. tially improve a project’s economics by creat- Moreover, if subsidizing oil shale developing a higher aftertax cash flow throughout its ment meets national objectives, this tax cred- producing life, and a higher return on invest- it with a sliding-scale phaseout can be used ment. by firms as a baseline for making their deci- Although the production tax credit does sions. To promote efficient investment and not share in the risks of project noncomple- production decisions, the price subsidy af- tion or price and cost uncertainties, it would forded by the tax credit should reflect the decrease the risk of incurring a loss by im- premium society is willing to pay to encour- proving project economics. Therefore, it may age the development of oil shale resources. slightly improve the ability of firms to acquire capital financing. However, this tax credit Because it works through the existing tax alone would not encourage financial institu- framework, implementing a production tax tions to lend to a financially less secure oil credit should be relatively straightforward, necessitating little or no administrative over- shale developer. head. The chief administrative policies would A production tax credit has a function sim- be to define a reference price for determining ilar to a price guarantee. Depending on lend- the value of the credit, to set an inflation ad- er expectations about investment and operat- justment formula, and to develop a mecha- Ch. 6–Economic and Financial Considerations 199 nism for ensuring that firms accurately re- tively than obtaining a grant, it might be pre- port the amount of shale oil produced. (How- ferred by some firms. ever, reliance on tax-based incentives would tend to reduce the Government’s control over production levels.) Expected Profit Large, integrated oil companies will most In comparison with no incentive, the $3/bbl readily benefit from this incentive (i.e., those tax credit would increase the expected profit firms having both a sufficient Federal income of the 50,000-bbl/d facility by $194 million. tax liability to use the credit and a strong This increase was the fourth highest of the inability to raise debt). Moreover, in trying to centives tested. With the tax credit, the ex- secure a competitive advantage in the oil pected profit of such a facility would be $392 shale development industry, those firms that million, more than enough to induce its devel- have already undertaken investment in oil opment. Moreover, this tax credit would re- shale, and that can accept exposure to the tain its high ranking irrespective of a firm’s risks of project noncompletion and invest- marginal tax rate, unless it has excess tax ment and production cost uncertainties, may credits (i. e., the tax credit expires before the favor production tax credits over all other in- firm has earned enough income to offset it). centives, Although some firms might hold excess tax credits at the outset of production, few, if The production tax credit is supported by any, would hold them over the entire lifetime most of the larger firms involved in oil shale of a project, given the eventual large annual activities. The Atlantic Richfield Co. (ARCO), income that can be expected, Therefore, an Gulf, Union, and Occidental, all companies excess credit situation would be likely to exist with current oil shale investments, rank it for no more than a few years of the tax cred- either first or second in their incentives pref- it’s duration which could be short or long de- erence lists. However, Standard of Indiana, pending on the phase-out provisions. which is Gulf’s partner in Rio Blanco, ranks it last, preferring incentives that deal with the The production tax credit is highly sensi- front-end investment uncertainties. Chevron, tive to the discount rate, however, because which is just starting its oil shale develop- the subsidy is spread over a project’s entire ment activities, directly opposes it in favor of lifetime, In fact, over the range of rates an investment tax credit that addresses the tested, this incentive is one of the most sen- investment cost risks, which Chevron feels sitive to the discount rate: averaged over the are considerable, (See table 24. ) discount rates, each percentage point drop in In calculating the quantitative effect of this the discount rate resulted in a $20 million in- incentive, the unit value of the subsidy (estab- crease in expected profit. lished as $3/bbl of unrefined shale oil) was multiplied by the entire annual output; that product was then subtracted from the income Risk tax obligation for each year of production. * Because the production tax credit does not The results indicate that the $3/bbl tax credit reduce the variation in possible future prices ranks fourth, behind the 50- and 33-percent and costs, it does not reduce the overall vari- construction grants and the low-interest loan, ation in possible profit outcomes. However, it in its tendency to increase profitability and significantly reduces financial risk because it reduce the risk of loss. In addition, because boosts the expected profit. For this reason, obtaining the tax credit is simpler administra- the production tax credit ranks fourth behind both construction grants and the low-interest loan in reducing the probability of loss in the *In OTA’S analysis, the tax credit was calculated on shale oil output prior 10 hvrirotrea t ing. Because of processing losses, variation in profit relative to the change in the output of hydrotreatd oil is 12 to 15 percent lower. expected profit. 200 ● An Assessment of 0il Shale Technologies

Breakeven Price required to operate a project capable of producing a specified quantity of shale oil). In In the absence of an incentive, the break- this case, with sufficient competition, firms even price was $48.20/bbl of hydrotreated would bid on an amount equivalent to the neg- product, with the production credit it was ative expected present value of their pro- $5.60 less, or $42.60/bbl. This price ranks jected aftertax income. Instead of bidding a third behind the breakeven prices for 50- and bonus to be paid to the Government, they 33-percent construction grants and the low- would bid a bonus to be received from the interest loans; nonetheless, it is still within Government. Those bidding the lowest bo- the commercially feasible range, given the nuses, up to some aggregate bonus payout average discounted price of oil—$53.00/bbl from the Government, would receive the —over the production period. awards. Cost to the Government A construction grant would make it possible for otherwise uneconomic projects to The cost to the Government is commensu- have a profitable, positive expected present rate with the credit’s strong effect on profit- value of aftertax income. The immediate ef- ability. Overall, it is the fourth most costly in- fect of a grant will be to facilitate capital ac- centive, ranking below the 33- and 50-percent quisition because less funds probably will be construction grants and the low-interest loan. needed from external sources. * In addition, Moreover, the production tax credit is one of over the life of the project, there will presum- the least cost-effective (as measured by the ably be lower debt repayment requirements. ratio of change in expected profit to Govern- A construction grant reduces the uncertainty ment cost). It ranks below most of the other over investment costs but not over operating incentives, including construction grants. costs or product prices. Thus, depending on However, it offers two advantages over con- its size, a construction grant may signifi- struction grants. First, the cost to the Govern- cantly reduce the risk of project failure. ment would be spread more evenly over time; Moreover, it may reduce the amount of exter- the production tax credit would require nal financing needed, and because it im- about $49 million per year over a 20-year pro- proves project economics, it enables the firm duction lifetime, compared with $170 million to borrow. However, it does not create an per year over a 5-year construction period for asset on the firm’s balance sheet, and will the 50-percent grant. Second, it would be thus provide no assurance to lenders of a much easier to administer for both oil shale firm’s ability to meet its debt repayment developers and the Government. Developers obligations. * * would simply file for the credit on their tax return, thus making the Government audit of The construction grant is not economically production records straightforward. efficient since it affects a firm’s perception of its investment costs, creating a bias in favor of more capital-intensive projects. Moreover, Construction Grant once the plant is constructed, output decisions will be based on the market price of oil Under a construction grant program, the rather than the strategic value of domestical- Government transfers a sum of money to a ly produced synthetic fuel. Finally, the confirm undertaking an oil shale development struction grant will be costly to administer project. In return, the firm must only fulfill its obligation to undertake the project within some period of time. The size of the grant *A construction grant program should not be confused with would be some prespecified fraction of the in- a loan program or a program to facilitate financing. To assist financing, the Government should consider a direct-loan or vestment costs. Alternatively, the Govern- loan-guarantee program. ment could hold the inverse of a bonus-bid *‘Unless a grant is to be paid at a future date and a firm bor- lease auction (i.e., firms could bid the amount rows against it in the short term. Ch 6–Economic and Financial Considerations ● 201 and may result in project delays if not proc- Construction grants are supported by firms essed expeditiously. of widely varying size and financial condition. In addition to those with more limited debt ca- There will be problems in deciding the size pacity, two financially strong companies, of grants without an auction. A firm can re- Gulf and Standard of Indiana, also support fuse the project if the grant is too small, If the this incentive. Gulf supports only limited grant is too large, on the other hand, the firm grants; its partner in the Rio Blanco develop- would receive excess economic rent* from ment, Standard of Indiana, supports front- the project at society’s expense. To minimize end cash construction grants for up to 25 per- the cost to the Government, the grant should cent of project investment to help offset the equal the absolute value of the negative ex- heavy initial capital requirements of early pected economic rent on the project (plus, for projects. (See table 24.) a risk-averse firm, any risk premium).** The effects of grants of 50 and 33 percent Second, even if the Government uses an of plant cost (estimated to average $1.7 bil- auction to distribute grants, firms will prob- lion including upgrading) were analyzed, as- ably collect excess rents at the expense of suming that the cost would be incurred over a society. The grant program shares none of period of 6 years and that the Government the risks of oil shale development. If these would pay its percentage of each year’s cost risks are as substantial as currently ex- at the end of the year in which the cost was pected, firms may require large risk premi- incurred. ums in their bonuses to ensure against economic loss. Although necessary and efficient On purely economic grounds, construction from a firm’s perspective, the risk premium grants would be ranked highly by oil shale represents an excessive transfer of income firms. Compared with the other incentives, from the public to the private sector. Also, the 50-percent grant would offer the greatest unless competition is high and firms have increase in expected profit, the greatest de- equal access to technical information, bids cline in risk of loss, and the lowest breakeven will not be driven down to the level of the neg- price. The 33-percent grant also compares ative expected economic rent. In this case, well, ranking second in its effect on profit- firms may strategically bid more than this ability, ability to lessen the probability of loss, figure in an attempt to receive higher than and breakeven price. For the Government, the risk-free required rate of return for however, construction grants would be undertaking the project. among the most costly incentives. The administrative requirements associated with this incentive could delay imple- Expected Profit mentation of an efficient program for several years. The construction grant is a neutral In the simulations, (see table 25) the 50-per- subsidy; all firms should be able to use it. cent construction grant yielded an expected profit of $707 million. When compared with They may, however, dislike the grant on ideological grounds. Those that are more risk- an expected profit of $220 million when no incentive was employed this represents a gain averse will be at a competitive disadvantage of $487 million, the largest of any incentive in acquiring grants in an auction (i. e., their tested. The 33-percent grant, although rank- requirement for higher risk premiums will ing second behind the 50-percent grant, re- reduce the probability of winning a grant). sulted in $321 million in expected profit. Both grant levels would therefore be more than adequate to induce private development of *Excess economic rent here indicates a situation where the developer has recovered more subsidy than would have been the 50,000-bbl/d oil shale facility. required to under ttike the project. **A risk premium is the additional margin of profit required In assessing the effect of a construction by a firm in order to undertake development. grant on profitability, an analysis was made

f, 3-83 B - 80 - :4 202 ● An Assessment of Oi/ Shale Technologies of its sensitivity to a firm’s marginal tax rate when no incentive was offered. The 33-per- and discount rate. An individual firm’s mar- cent grant results in the second lowest break- ginal tax rate was found to strongly influence even price, $38.70/bbl. Either price would the grant’s effectiveness: the higher the rate, place the shale oil facility in the commercially the lower the value of the incentive to the viable range. Given an initial oil price of firm. Because the grant reduces the amount $35/bbl, and the expectation that the price of investment that is depreciated against cor- will rise over time (at 3 percent per year in porate income tax, the developer has a higher real terms), the price of oil at the start of pro- taxable income as a result of this subsidy. In duction in 1986 would be $42/bbl. It is more analyzing this incentive, the highest marginal meaningful, however, to compare the break- tax rate (46 percent) was used in the calcula- even price with a composite price of oil over tions; the value of the grants for firms with the production lifetime—$53.00/bbl.* Be- lower marginal tax rates would therefore be cause the breakeven prices with both the 50- greater than that stated in this report. and 33-percent grants are less than this It was found that the effect of construction amount, the project would be viable. grants on profitability, however, would depend only slightly on the level of the discount Cost to the Government rate. The results were calculated using a 12- Construction grants of 50 and 33 percent percent discount rate, * but the expected in- would be among the most costly to the Gov- crease in profit stemming from construction ernment. In the simulations, the gross cost to grants changes very little with discount rates the Government for the 50-percent grant was of 10 and 15 percent. This is because the sub- $170 million per year for each of the 5 years sidy is concentrated in the construction of construction. The net cost, however, de- phase, thus is discounted over relatively few pends on the marginal tax rate of the recipi- years. ent. Because the grant would reduce the amount of investment subject to depreciation, Risk the Government would recover about one- Because the Government shares so large a third of the gross subsidy paid to firms with a portion of cost, construction grants have a 46-percent marginal tax rate, through in- very pronounced effect on risk reduction. For creased income tax payments. With this tax the representative facility, the probability of rate, the net cost to the Government for the loss dropped from 9 percent with no incentive 50-percent grant was higher than any other incentive—$494 million** and third highest to O percent with both the 50- and 33-percent grants. Thus, these grants rank highest in re- for the 33-percent grant. However, the con- ducing the risk of loss. In addition, the construction grants are the most cost-effective, struction grants result in the greatest reduc- as measured by the ratio of change in ex- tion in the variation of profit outcomes (as pected profit to Government cost. The net measured by standard deviation) relative to cost figures, however, do not include adminis- change in expected profit. trative costs, which could be significant. To guard against cost overloading, the Gov- Breakeven Price ernment would have to establish precise accounting guidelines and be prepared to audit The 50-percent construction grant also has all grant recipients. Furthermore, the grant the lowest breakeven price, $34,00/bbl of premium syncrude, compared with $48.20/bbl *The composite price is a constant price, which when substituted for the escalating market price, does not change the prof- *On the basis of studies showing that the real, aftertax re- it calculations (see app. A). turn for U.S. business averages from 5 to 10 percent, the 12- **All Government costs are calculated in present value percent rate was selected as representative. It reflects the risk terms using a lo-percent real discount rate. This is the rate involved in oil shale investment compared with that of the aver- adopted by the Office of Management and Budget (OMB) for age investment. evaluating Government programs. (See OMB’S Circular A-95.) Ch. 6–Economic and Financial Considerations ● 203 application procedure would tend to be time- sharing in the risk of investment cost uncer- consuming for both the Government (complex tainty and none in the risks of operating cost auditing procedures would be required) and and product price uncertainty. Because the the applicant, (a well-documented application Government lends directly to the firms, a sub- would be required). Alternatively, the Gov- sidized interest loan facilitates direct access ernment could simply offer to award $400 to capital for financially weaker firms. million ($80 million per year for 5 years) to The effects on economic efficiency parallel any company that is willing to build a 50,000- those of a loan guarantee. The reduced inter- bbl/d plant, the only stipulations being that est rate serves as a capital subsidy, thus, it the plant must be completed and operated. may favor relatively capital-intensive technologies. The primary effect on efficiency is Low-Interest Loan to encourage participation of a greater number of firms in oil shale development projects. The effects of a low-interest loan are sim- If increased competition leads to the testing ilar to those of a debt guarantee. Its primary and development of a wider variety of tech- purpose is to assist firms in financing the nologies, future production costs for shale oil large capital outlays required for oil shale may be lowered. projects. Those that otherwise would be unable to raise sufficient capital would benefit Because the low-interest loan incentive re- most from this incentive. quires discretionary review and approval of loan applications, it will be time-consuming With a low-interest loan incentive, the Gov- and laborious to administer. Delays in imple- ernment lends money directly to firms at a menting an effective program may be encoun- lower interest rate than would be provided by tered. private lenders. The money may be obtained from general funds, designated taxes (e.g., The firms that will most benefit from a low- the extra-profits tax currently being consid- interest loan program will be relatively weak ered in Congress), or through a Government- financially with limited access to capital mar- financing authority (similar to the Federal kets. If the Government were to make debt National Mortgage Assistance Program). available to all firms at less than market rates (i.e., rather than at the AAA rate), all, A low-interest loan and a loan guarantee independent of financial condition, could pre- would have similar effects on project eco- sumably benefit from the incentive. Like loan- nomics. Both would reduce the interest cost guarantee incentives, low-interest loan incen- of debt; as a result, the firm would have a tives are preferred by companies with limited lower payout obligation and higher cash flow debt capacity because they need subsidized over the life of the project. A low-interest loan interest loans to raise project capital. program could have a significant effect on project economics. It provides access to capi- This type of loan could be structured in a tal for firms that otherwise could not borrow variety of ways. A loan for 70 percent of con- in capital markets or that must borrow at struction costs was analyzed. It was assumed very high rates. that loan funds would be made available during the years the construction costs would be Its risk-sharing features are identical to incurred (e.g., if construction takes 5 years, those of the loan-guarantee program. As the funds would be dispersed over the 5-year direct lender, the Government shares the period at the rate of 70 percent of each year’s risks of project failure and default on debt cost per year. It was further assumed that the repayment. The equity owners of the develop- developer would begin repayment at the end ment firm remain exposed to the risks of proj- of the first year of production, that the loan ect failure and loss of capital. With the low- would be issued at an interest rate of 3 per- interest loan program there is only minor centage points below the prevailing market 204 An Assessment of 01/ Shale Technologies rate (e.g., 9-percent nominal interest on the 12-percent return was 0.00, but it was 0.09 loan when the market rate is 12 percent), and when no incentive was offered. Moreover, the that amortization would occur over a 20-year loan is effective in reducing the degree of period. variation in profit relative to expected profit, but to a lesser degree than the construction A low-interest Government loan would be a grants and production tax credit. very effective incentive, ranking close behind the 33-percent construction grant and production tax credit in its effect on profitability. Breakeven Price It would act to significantly reduce the risk of The low-interest loan resulted in a break- incurring a loss. However, it might be the even price for premium grade synthetic crude most costly to the Government; as such, it from shale oil ($43.40/bbl) that is only slightly could be less cost-effective than other high- higher than the price resulting from the pro- ranking incentives. duction tax credit ($42.60/bbl). However, it is well below the price prevailing when there is Expected Profit no incentive ($48.20/bbl), and lower than the The subsidized interest loan resulted in an average expected market price over the pro- expected profit of $497 million compared duction period ($53.00/bbl). with $220 million with no incentive. This $277 million increase is less than the increases in- Cost to the Government duced by the 50- and 33-percent construction The low-interest loan costs the Government grants but more than the $3/bbl production more than any other incentive except the 50- tax credit. The size of the increase, however, percent grant. It also results in the lowest depends on both the marginal tax rate for in- change in profit per dollar cost. The gross dividual firms and the access those firms outlay for the 70-percent loan is actually have to capital markets. For a firm with a 46- larger than that for the 50-percent construc- percent marginal tax rate, the 3-percent be- tion grant because both are computed on the fore-tax difference between the Govern- same construction costs. Loan repayments ment’s interest rate and a firm’s borrowing after the completion of the construction rate becomes a 1.5-percent aftertax differ- phase would also be higher than the in- ence, because interest payments are deducti- creased tax receipts under the 50-percent ble. The aftertax spread would be 2 percent grant program. However, because the subse- for a firm with a 3-percent marginal tax rate. quent receipts are discounted more heavily Hence, the lower the marginal tax rate, the than the initial outlay, the net cost to the Gov- more the loan is worth. In addition, the higher ernment in present value terms would be al- the rate of interest on alternative sources of most as great for the 70-percent loan as for debt financing, the more the loan is worth. the 50-percent grant. Moreover, it actually Because different firms may have different could be higher than has been calculated, be- borrowing rates, they might value the Gov- cause some firms might default on the loan. * ernment loan higher or lower than the value OTA has computed. Purchase Agreement Risk In a purchase agreement, the Government The low-interest loan does not affect the signs a long-term contract with a prospective degree of variation in possible profit out- *These conclusions are extremely sensitive to the choice of comes, because it does not reduce the vari- Government discount rate. If Government cash flows were discounted at a rate of less than 10 percent, the loan would cost ation in future costs or prices. However, it less. For example, at a 5-percent real discount rate, the cost to does significantly reduce the risk of loss; with the Government is $2OI million compared with $453 million the loan the probability of earning less than when the discount rate is 10 percent. Ch 6–Economic and Financial Considerations 205 oil shale developer to purchase some quantity production. Finally, when combined with a of shale oil or hydrotreated syncrude at a competitive bid mechanism, the purchase contract price (either in nominal or real agreement also subsidizes only the most effi- terms). The Government may set the contract cient firms. price directly, negotiate it with firms, or in- vite contract price bids. If the contract price Despite its advantage for economic effi- is negotiated or set by competition, the Gov- ciency, this incentive imposes significant ernment can selectively apply the incentive to burdens on administrative efficiency. The the most efficient firms by granting the pur- Government must determine the amount of chase agreement to firms bidding the lowest shale oil to be subsidized and the contract contract prices. The Government can always price, and it must manage a system for allo- control the number of firms using the subsidy cating the price contracts. If competitive bid- by limiting the number of projects and the ding is used to allocate contracts and set con- quantity of shale oil production covered in tract prices, managing the auction is another guaranteed price contracts. major administrative requirement. Moreover, because the mechanisms are less familiar to The purchase agreement incentive and the industry than for such other incentives as the production tax credit subsidize shale oil pro- tax credit, they will impose higher costs on duction by providing (presumably) a higher firms attempting to use and benefit from price to developers than they would receive them. Although purchase agreements entail a in the open market. Higher prices will benefit considerable amount of administrative bur- a firm over the life of the project, or until the den, its type and extent are strongly depend- specified quantity of shale oil has been pur- ent on the particular mechanisms employed. chased. According to this analysis, all firms except The purchase agreement reduces project those with very weak financial ability should risk stemming from the uncertainty over fu- be able to benefit from purchase agreements. ture oil prices. Because the product price is Unlike the tax credit, a firm’s ability to use essentially fixed, the Government bears all this incentive is not limited by the size of its the risk of price variations. However, this in- Federal tax liabilities. To some degree, those centive does not share in the risks of project that have not yet invested in oil shale develop- noncompletion or investment and operating ment and are strongly averse to the risk of in- cost uncertainties, vestment cost uncertainty may find this in- It does offer some security to lenders, and centive less attractive than the investment may provide a sufficient asset base for firms tax credit and the loan guarantee. to borrow against. As a result, the prospects for project financing are improved for firms Expected Profit with limited ability to raise debt. Like the production tax credit, the purchase agreement In the simulations, a purchase agreement also has distinct economic efficiency advan- of $55/bbl resulted in an expected profit of tages. It does not distort the prices of re- $231 million compared with $220 million with source inputs and thus encourages firms to no incentive. The $11 million gain in profit- utilize efficiently the Nation’s economic re- ability ranks behind gains achieved with all sources. In addition, it does not arbitrarily fa- the other incentives tested. The effect on vor any development technologies based on profitability is less than that of the $55/bbl differences in capital intensity or required price support, because with the price support construction time. Because it works through a firm benefits when the price exceeds $55/ the product price mechanism, the extent of bbl (this occurs in the ninth year of produc- the subsidy for shale oil is readily apparent, tion, assuming a 3-percent annual price in- and, in theory, should be set at a level that re- crease). The subsidy effect of purchase flects the social benefit of domestic shale oil agreements (and also price supports) is tied to 206 . An Assessment of Oil Shale Technologies the contract price. At such price, the pur- that the Government does not take title to the chase would cost the Government nothing. shale oil; it simply pays the difference be- However, its subsidy effect is also low. The tween the support price and the prevailing use of a higher contract price would have free-market price. If the free-market price ex- substantially increased its incentive impact. ceeds the contract price, the Government pays nothing. The price support, like the pur- Risk chase agreement and the production tax credit, subsidizes shale oil production since it Because it eliminates all variations in is presumed to have a probability of being possible future prices, the purchase agree- higher than the market price of imported oil. ment results in a large reduction (25 percent) in variations in possible profits. However, it The effects on project risk and efficiency of does not reduce the probability of loss as the price support are similar to those of the much as the price support, because a compa- purchase agreement: it reduces the risk of oil ny cannot benefit from upward variations in price uncertainty, it improves access to debt price above the purchase agreement price. capital, and it improves project economics. Like the purchase agreement, the price sup- Breakeven Price port entails significant administrative costs. However, in general, those associated with Because this incentive establishes a mini- price supports are lower than those for pur- mum price above the breakeven price when chase agreements. no incentive exists, there is no meaningful breakeven price under the price support or Expected Profit the purchase agreement. In the simulations (see table 25), a $55/bbl Cost to the Government price support resulted in an expected profit of $363 million, which is more than enough to At no direct cost, the purchase agreement induce a profit-maximizing firm to undertake was the least costly incentive for the Govern- an investment in oil shale. The level of profit ment. Government costs are incurred from presents a gain of $142 million over the case the first year of production until the market in which no incentive is offered, placing the price equals or exceeds the fixed purchase price support midway in the ranking. agreement price, If the market price increases over time, the cost to the Government As with most of the other incentives, the declines, and if the market price exceeds the expected profit for individual firms using the fixed price, the Government will regain part price support will depend on their marginal of its subsidy through low-cost purchases of tax rates. The price support will be worth shale oil. It can also recapture part of the less to firms with high marginal tax rates subsidy through the increased taxes that re- than to those with low marginal tax rates, sult from a developer’s larger taxable in- because the subsidized price increases tax- come. In analyzing this incentive, a high mar- able income. ginal tax rate for the company was assumed; Expected profit is also very sensitive to a the cost to the Government would be higher firm’s discount rate, because the price sup- than calculated here if the company had a port begins only after the start of production lower marginal rate. and continues for a number of years. The expected profit gain under this incentive varies Price Support more with changes in the discount rate than it does with a construction grant. On the other A price support is currently being consid- hand, the price support represents a relative- ered in several proposals before Congress. It ly larger sum in the early years of production is similar to a purchase agreement, except (assuming increasing oil prices) compared Ch. 6–Economic and Financial Considerations ● 207 with the constant tax credit. Thus, the $55/ that an additional 10- or 15-percent invest- bbl price support is somewhat less sensitive ment tax credit would be particularly attrac- to changes in the discount rate than is the tive. (See table 24.) $3/bbl production tax credit. Like the production tax credit, an investment tax credit strongly subsidizes the pro- Risk duction of oil shale. Under current tax ac- The price support is effective in reducing counting procedures, it effectively reduces risk because it eliminates the possibility of a the cost of an investment by the percentage of price for oil below the floor price. By reduc- the tax credit. That is, firms can deduct a ing the variation in possible future oil prices, specified percentage of their capital costs it reduces the total variation in possible profit from their income tax liabilities during the outcomes. In the simulations, the variation in first year in which the project operates. profit with the price support was reduced by When construction is scheduled over several over 20 percent compared with no incentive. years, a firm’s actual benefit is reduced by Given this reduction and the increased ex- discounting because the tax credit is not pected profits, the probability of incurring a taken until the project begins operation. The loss drops from 0.09 with no incentive to 0.01 investment tax credit increases net cash flow with the $55/bbl price support. This reduc- early in the life of the project when compa- tion in risk is only slightly below that for con- nies often need such a boost. However, destruction grants, the low-interest loan, and pending on the dollar value of the investment the production tax credit. (See table 25.) tax credit relative to a firm’s tax liabilities, it may take several years to fully utilize the tax Breakeven Price benefit if other revenues are not available on which to use the tax writeoffs. Because this incentive establishes a minimum price above the breakeven price when By reducing investment costs by a specified no incentive exists, there is no meaningful percentage formula, the investment tax cred- breakeven price under the price support or it reduces the variance in investment cost, the purchase agreement. and allows the Government to share in the risk of capital-cost uncertainties. In the early Cost to the Government stages of oil shale commercialization, capital- cost uncertainty will be a major source of The price support, which ranks fifth in its risk, net cost to the Government, would be spread over most of the production life of the facility, As investment costs increase, the share with a larger share in the early period if the paid by the Government increases in propor- price of oil continues to rise. In the analysis, tion to the percentage rate of the tax credit. the net cost figure of $172 million, which ac- Conversely, as investment costs decrease, the counts for the partial recovery of the gross Government’s share decreases. The invest- subsidy through increased income taxes, was ment tax credit does not share in the risks of calculated using a 46-percent tax rate. The project noncompletion and price and operat- cost of this incentive to the Government ing cost uncertainties. would be higher in the event of lower margin- Although an investment tax credit will en- al tax rates. hance a project’s profitability and return on investment, it cannot overcome the financing Investment Tax Credit problems of firms with limited debt capability. Unlike the production credit, it does not in- Several oil shale developers view the induce lenders to provide the substantial vestment tax credit as one of the most desir- amounts of capital required for oil shale de- able incentives. These firms have indicated velopment. 208 . An Assessment of Oil Shale Technologies

The effect of the investment tax credit on period rather than a long production period. economic efficiency is less desirable than the Therefore, its value is relatively more sen- production tax credit, for several reasons. sitive to a firm’s overall tax credit situation. First, it interferes with a firm’s perception of This credit is, however, relatively insensitive the market prices for the resources used in oil to a firm’s discount rate because all the tax shale development. This incentive subsidizes credit would be claimed early in the life of the investment costs only, and so favors the more project and would thus be discounted over capital-intensive development technologies. relatively few years. In addition, because the value of the tax benefit decreases as the length of the construction Risk period increases, an investment tax credit incentive favors development technologies with The investment tax credit was found to relatively short construction leadtimes. have a slight effect on the risk of loss but virtually no effect on the variability of profit out- Because the investment tax credit has been comes. With this incentive, the probability of part of the tax structure for several years, it a loss dropped to 0.05, the same level as the is particularly easy to implement. Analysis increased depletion allowance and acceler- has indicated that large, integrated oil com- ated depreciation. panies (i.e., firms with large tax liabilities and strong financial capabilities) will prefer Breakeven Price and benefit most. By inference, firms that prefer an investment tax credit to a produc- At $45.80/bbl, the breakeven price of the tion tax credit are more averse to the risk investment tax credit was slightly higher than associated with investment cost uncertainty that of the increased depletion allowance than to the risk associated with product price ($45.70/bbl), and not significantly less ($2.20) uncertainty. than the breakeven price with no incentive.

Expected Profit Cost to the Government In simulating the impact of a simple IO-per- For this incentive, the cost to the Govern- centage point increase* in the investment tax ment ($87 million) was among the lowest, credit, it appeared unlikely that it would in- ranking just above accelerated depreciation. crease the profitability of oil shale ventures Compared with the depletion allowance, how- enough to induce their development. In the ever, the cost of the tax credit would be in- quantitative analysis, the hypothetical facili- curred over a shorter period of time. ty had expected profits of $299 million compared with $220 million without an incentive. Accelerated Depreciation On the basis of the effect of profitability, the increased investment tax credit ranked near Accelerated depreciation for tax account- the bottom, above accelerated depreciation ing has been discussed by several firms as a and the purchase agreement. possible incentive for encouraging develop- The investment tax credit’s effect on prof- ment projects. For example, they have sug- itability (like the production tax credit) is not gested that oil shale investments be deducted sensitive to the marginal tax rate unless a from income over a period of 5 years instead firm has excess credits at the time the in- of 10 to 15 years, as is now expected. Some creased tax credit expires. However, unlike firms have even suggested the possibility that the production tax credit, the investment the entire oil shale investment could be writ- credit is claimed over a short construction ten off in the first year of project operation. *The existing investment tax credit has an additional IO-per- Accelerated depreciation functions simi- cent tax credit for energy investment, However, this credit was ignored in the calculations because it was due to expire in larly to an investment tax credit. It provides a 1982. modest subsidy for development. However, in Ch. 6–Economic and Financial Considerations ● 209 comparison with an investment tax credit, ac- the uncertainty of investment cost. In effect, celerated depreciation will have a weaker, it pays a percentage share of the investment only moderate subsidy effect, which is limited costs of a project, thus reducing their varia- by the firm’s marginal income tax rate and tion. It has no effect on the risks stemming the interaction of depreciation with depletion from the possibility of project failure and the in tax computation procedures. uncertainty of production cost and price, Shortening the period over which invest- Accelerated depreciation will improve ment costs may be deducted from pretax in- project economics but, by itself, is not suffi- come increases the present value of the tax cient to facilitate a firm’s access to debt deductions and, thus, will lead to a higher markets. It does not provide an asset against return on investment for a project. In addi- which firms may borrow. tion, accelerated depreciation would improve Accelerated depreciation has a negative cash flow in the early years of a project’s effect on economic efficiency. * It interferes operation when firms are often short of cash. with the perceived prices of the resource con- In effect, the Government pays an increased sumed in oil shale development. Because it share of the investment cost through reduc- functions as a capital subsidy, it will favor tions in income tax liability. The share paid is the more capital-intensive technologies. It the present value of depreciation deductions will not affect the production signal provided multiplied by the firm’s Federal income tax by product price. Moreover, like the invest- rate, which thereby sets a ceiling on the subsidy effect of this incentive. The maximum ment tax credit, accelerated depreciation does not function through an easily observ- benefit would be obtained with an instantane- able mechanism (e. g., product price). There- ous writeoff; in this case, the share paid by fore, it will be relatively difficult for society the Government would be equal to 0.46 multi- to ascertain the magnitude of the premium it plied by the cost of the investment (assuming is paying to develop domestic oil shale re- 46 percent of the firm’s corporate income tax sources. rate). Depreciation, which is familiar in tax ac- However, the subsidy effect of accelerated counting, would probably entail a minimal ad- depreciation could be limited by the interac- ministrative burden to implement. tion of depreciation and percentage depletion in computing Federal income tax liability. Large, integrated firms with strong finan- Percentage depletion is a deduction from tax- cial positions will benefit most from this in- able income that is determined as a percent- centive. Their pretax income and tax liabil- age of gross production revenue in any year. ities from other business activities are suffi- However, the maximum deduction for per- ciently high that the accelerated depreciation centage depletion allowed in any year is 50 writeoffs can be taken as they become avail- percent of net income after subtracting all able. In addition, unless the accelerated de- other deductibles allowed by the Internal preciation is made retroactive, firms that Revenue Code. Such deductibles include de- have not yet invested in oil shale development preciation. Thus, increasing the depreciation will have a somewhat stronger preference for allowance in any year would reduce the in- this incentive than firms that have made income ceiling on the depletion allowance and vestments with a longer depreciation sched- could reduce the deduction allowed for per- ule. centage depletion. In this case, the benefit to a firm from accelerated depreciation would be somewhat offset by the reduction in the ‘This assumes that the existing depreciation period is effi- tax benefits of percentage depletion, cient. In actuality, depreciation probably inefficiently biases against capital-intensive projects. Shortening the ciepreciat ion Through accelerated depreciation, the period reduces some of this bias and hence promotes efficien- Government shares in the risk stemming from cy. 210 ● An Assessment of 0il Shale Technologies

Expected Profits breakeven price was the smallest of any incentive tested. In the simulations, the accelerated depreciation schedule induced an increase in ex- Cost to the Government pected profit of $76 million, which was the second lowest figure for any incentive tested. Of the incentives tested, accelerated de- The effect of accelerated depreciation on preciation is one of the least costly to the profitability depends greatly on the tax situa- Government and one of the most cost-effec- tion of a firm: it will benefit firms with higher tive. In the simulations, the net cost to the marginal tax rates more than it will benefit Government was $79 million, and the ratio of those with lower rates. This difference arises change in expected profit to the Government for two reasons. First, the amount of tax sav- was 0.96. Moreover, because the incentive is ings for a given amount of depreciation is granted through the existing tax system, the directly proportional to a firm’s tax rate. Sec- cost of its administration would be negligible. ond, a firm with a high marginal tax rate and (See table 25.) with other income-producing investments will be able to write off the depreciation against Increased Depletion Allowance other income, whereas a firm with a low tax rate will be likely to have excess deductions. An increased percentage depletion allow- In the latter case, the increased depreciation ance has been discussed as a possible incen- deductions must be carried forward and are tive for encouraging oil shale development. thus worth less, through discounting, than Firms have suggested that the percentage de- they would be if they could immediately offset pletion allowance be increased to 25 or 27 taxable income. percent. The value of this incentive is also affected The primary effect of an increased per- by the discount rate. The effect is slight, centage depletion allowance would be to sub- however, because both the tax writeoff and sidize the economics of oil shale development. its timing are small. A 3-percentage point in- Specifically, increasing the depletion allow- crease in the discount rate produced only a ance will increase the share of production lo-percent reduction in the change in ex- revenues that are shielded from the Federal pected profits. corporate income tax. The depletion allowance, like a product-price increase, will im- Risk prove a firm’s cash flow throughout the producing life of a project. As a result, a firm’s Accelerated depreciation was found to return on investment for a project is im- have little effect on the risk of oil shale in- proved. vestments. In the simulations, the probability The depletion allowance might be assumed of incurring a loss did not drop significantly to be as effective an incentive as the produc- nor did the absolute variation in possible tion tax credit because both function through profit outcomes. Relative to change in ex- the price mechanism. However, it has several pected profits, the variation in profit was undesirable characteristics as a subsidy. The next to the lowest, ranking above the pur- presumptions underlying its use as an incen- chase agreement. tive are that oil shale development is uneconomic and that the increasing (effective) Breakeven Price product price is the appropriate vehicle for By analysis, the breakeven price with the its subsidization. 5-year depreciation incentive was found to be To be an efficient subsidy through the price $46.00/bbl compared with $48.20/bbl for the mechanism, the value of the price subsidy 12-year depreciation. This reduction in should decrease as the product price in- Ch. 6–Economic and Financial Considerations ● 211 creases (i. e., as the need for the subsidy liabilities. Moreover, by inference, firms that decreases). However, the percentage deple- prefer an increased depletion allowance are tion allowance has the reverse effect. As the relatively unconcerned about risk of future product price increases, the value of the decreases in product price. Rather, they are price subsidy also increases. Conversely, as apparently betting in favor of continued long- the product price decreases and the need for term increases in the price of imported oil. No the subsidy increases, the value of the sub- firm seriously advocates this incentive. (See sidy actually decreases. This effect will make table 24.) it impossible to maintain the subsidy at a desired level. In analyzing this incentive, an increase in the depletion allowance from the current 15 In addition to its undesirable subsidy ef- to 27 percent was assumed. Such an increase fects, the percentage depletion allowance has would be a significantly less effective incen- poor risk-sharing characteristics. In fact, it tive than the construction grants, the produc- increases the risk associated with the uncer- tion tax credit, the low-interest loan, the tainty about future shale oil prices. Because price support, or the purchase agreement. the value of the price subsidy increases with Compared with these other incentives, the in- the product price, this incentive magnifies the creased depletion allowance would result in effects on a firm of changes in the product a much smaller gain in expected profits and price. The variance of aftertax income in- only a slight reduction in the risk of incurring creases as the percentage depletion allow- a loss. ance is increased. This incentive does not share in the risks either of project failure or of the uncertainties of investment and operat- Expected Profit ing cost. The depletion allowance will improve project economics but will not signifi- The increased depletion allowance re- cantly influence a firm’s ability to raise debt. sulted in a comparatively modest gain in expected profit—$140 million—compared with The effect of the percentage depletion al- no incentive. Because firms cannot claim lowance on economic efficiency is similar to depletion deductions in excess of 50 percent but more adverse than the production tax of taxable income, increasing the depletion credit. It does not affect the prices of re- allowance above 27 percent does not result in source inputs. Consequently, resources significant additional expected profit. should be combined in an economically efficient manner and a firm’s preference for spe- For firms with lower marginal tax rates, cific oil shale development technologies the gain in expected profit would be even should not be influenced. However, in effect, smaller. In the simulations, for example, the it alters the price perceived by a firm and $140 million gain in profitability calculated thus will influence its production and invest- using a 46-percent tax rate would be reduced ment decisions. Moreover, the contrary man- to only $70 million if the tax rate were 23 per- ner in which the subsidy effect increases as cent. (See table 26.) product price increases will make it difficult The effect of an increased depletion allow- for the Government to use this incentive to ance on profitability is also more sensitive to promote efficient decisions that reflect the the discount rate than any other incentive social benefits of shale oil production. tested. This sensitivity stems from the in- Like accelerated depreciation, percentage crease in the incentive’s value that accompa- depletion is a familiar component of the U.S. nies the increase in the real price of oil (and tax code, and would thus be very easy to ap- hence revenues). Thus, a higher value in later ply. The firms that will benefit most from an years is more sensitive to discounting than a increased depletion allowance will be those value that remains constant over time (as the having large before-tax income and large tax production tax credit does, for example). ————.——..—

212 An Assessment of 0il Shale Technologies

Risk nomics of oil shale development. Indeed, the only effect on project economics is to reduce Although a higher depletion allowance ac- the interest rate on debt for firms with low tually increases the variation in possible prof- bond ratings. Thus, over the life of a project, its, the gain in expected profits results in a a firm’s debt service obligation will be some- small reduction in the probability of loss. In what reduced. A loan guarantee will be of lit- the simulation the 27-percent depletion allow- tle or no value in improving project economics ance reduced the probability of loss to 0.05, for firms with strong balance sheets that can compared with 0.09 when no incentive was borrow at low rates. employed. The increase in the variability of profit outcome occurs because profits are This type of incentive requires the Govern- more sensitive to changes in future prices ment to share directly in the risks both of with the higher depletion allowance. project failure and of default by a firm on its debt obligations. However, as long as a firm’s Breakeven Price equity contribution to total project investment remains at a reasonable level (e.g., 40 per- Although the increased depletion allow- cent or more), a loan guarantee does not un- ance will result in a reduced breakeven price, duly shield a firm from economic loss (i.e., the this reduction is likely to be small. In the incentive does not introduce moral hazard). * simulations, the breakeven price fell from In the event of default, the loan guarantee $48.20 to $45.70/bbl. (See table 25.) does not protect equity owners against loss. As a result, it encourages management to Cost to the Government operate in an economically efficient manner, and provides only weak protection from the The cost of this incentive to the Govern- risk of investment cost uncertainty—but only ment is commensurate with its effect on ex- if it is for a percentage share of the capital re- pected profit. In the analysis, the increased quired for the project and if the firm can bor- depletion allowance cost $197 million, which row at a lower interest rate than would other- makes it the fifth most costly incentive. More- wise be possible. A loan guarantee does not over, it is not a cost-effective option since it share in the risks of operating cost and prod- results in the second lowest ratio of change in uct-price uncertain y. expected profit to Government cost. Of all the incentives that provide for private lending, it has the strongest effect in im- Loan Guarantee proving the ability of firms with limited debt capability to borrow in capital markets. By Under a loan-guarantee incentive, which guaranteeing the fulfillment of a specified has been frequently discussed in Congress portion of a firm’s obligations, the loan-guar- and by oil shale developers, the Government antee program provides an asset that finan- guarantees to lenders to repay a specified cially weaker firms may borrow against. portion (e.g., 50 to 70 percent] of the project debt if a firm defaults on its debt payments Given its limited effects on project econom- because of the economic failure of its oil shale ics, a loan guarantee has relatively minor ef- project. A loan guarantee would be adminis- fects on efficiency. It acts as a capital sub- tered selectively by a Government agency sidy and so may favor more capital-intensive without charge or for a fee. Under a fee ar- technologies. It does, however, improve com- rangement, a firm effectively buys an insur- petition in oil shale development by removing ance contract to guarantee debt repayment, a major barrier to entry for less well-fi-

A loan guarantee is primarily designed to *Moral hazard would exist if the guarantee was constructed facilitate project financing and, as a result, as to eliminate so much corporate risk that project failure is en- has only a limited subsidy effect on the eco- couraged+ Ch 6–Economic and Financial Considerations ● 213 nanced firms. Enhancement of competition Government Participation may lead to testing a broader set of technologies, and in the long run may result in higher Government participation has been dis- overall efficiency by reducing production cussed as part of several bills being con- costs. sidered in Congress. Although it has certain fundamental advantages if the primary pur- This incentive will present certain admin- pose of an oil shale incentive program is to istrative problems, even though the Govern- share risk, it would meet strong resistance on ment has previously used loan-guarantee pro- ideological grounds, and would be extremely grams. A firm’s application must be selective- difficult to administer. Moreover, it may lead ly reviewed and approved, thus increasing to inefficiency in oil shale development and the potential for delay. production activities. The loan-guarantee incentive benefits A Government participation program is smaller companies with an insufficient asset based on the assumption that oil shale devel- base to back the major debt requirements for opment is economically sound but has very undertaking an oil shale development project high risks. Because of these risks, private (i.e., companies with a limited capability to firms are assumed to be reluctant to under- raise debt that would otherwise have to bor- take projects, or willing to undertake them row at higher interest rates or be excluded only with the expectation of high profits on from oil shale development). In addition, their investment to cover their risks. Govern- larger companies with a large asset base but ment participation would provide a mecha- also large debt (i. e., a high debt/asset ratio) nism for it to share risks with private firms may also need guarantees to embark on an oil thus encouraging them to commit capital to shale project. With the increasing debt/equity oil shale projects. ratios evident in the petroleum industry, a growing number of firms fit this description. In such a program, the Government would Those with a strong balance sheet and large provide a specified share of equity. From that asset base will not benefit from a loan- point on, it would simply be an equity partner guarantee program, and for competitive in the project and would share proportionate- reasons may not prefer its implementation. ly in any project losses or profits. Depending on the terms of its agreement, the Govern- Loan guarantees tend to be preferred by ment could either be a silent partner or par- firms that have limited debt capacity. Superi- ticipate in management decisions. The part- or Oil backs them in principle, believing that nership could be managed through an exist- they will help some companies obtain financing agency or a separate, newly formed ad- ing to get their plants started. The Oil Shale ministrative unit (e.g., the proposed Energy Corp. (Tosco) reported that it would need Security Corporation). them to obtain financial backing, and SOHIO Natural Resources, a subsidiary enterprise Because Government participation is sim- with limited debt capability, claims it could ply a joint venture arrangement between the also take advantage of them. Occidental, a Government and private firms, this incentive considerably larger firm, advocates any and would not provide any significant subsidy to all types of loans or loan guarantees, espe- oil shale development. It would, however, cially nonrecourse loans. As would be ex- have the strongest effect of all the incentives pected, the largest and financially strongest on the sharing of risk between public and pri- companies find loan guarantees less desir- vate sectors. In this program, the Government able. (See table 24. ) would share in the risks associated with all 214 An Assessment of 011 Shale Technologies project uncertainties in proportion to its per- to manage the program, with the likelihood of centage ownership in a project. When the lengthy delays in getting the program to oper- project showed a loss, the Government would ate effectively. lose; when it showed a profit, the Government would win. Government participation would OTA’s analysis indicates that Government reduce a firm’s exposure to economic loss. At participation would most benefit firms that the same time, it would decrease the potential are relatively risk-averse, thus unable to fi- gains for a firm. That is, the variance in a nance an oil shale development project alone. firm’s expected present value of aftertax in- However, because private firms may join to- come would be proportionately reduced by gether in partnerships, there may be no in- the multiple (1 – SG)2, where SG equals the centive for them to enter a joint venture with share of Government ownership. the Government as an active partner. If the Government adopted a silent-partner role, The extent to which Government participa- however, a firm could take full managerial re- tion would assist a firm in raising debt will sponsibility for a project, while still receiving depend on the terms of its involvement in a the risk-sharing and financial benefits of the project. If the Government does not agree to joint venture. Such an arrangement is not guarantee a firm’s project debt, its participa- usually possible with any other private part- tion would have little effect on the firm’s ner. ability to borrow. Debt-financing support would still come from the firm’s own asset All firms except one oppose the Govern- structure. Alternatively, if the Government ment participation incentive, primarily be- provided a share of project debt or guaran- cause of their fears of bureaucratic ineffi- teed a share of project debt, a firm’s debt re- ciencies, of support of one technology to the quirements would be reduced, and loans exclusion of another, and of administrative could be more easily acquired. problems. The only advocate, SOHIO, has sought $15 million in Government appropria- A Government participation program tions to help fund its already approved full- would have essentially neutral effects on the sized module program. economic efficiency of private sector investment and operating decisions. By simply cre- The Government could also contract for the ating a partnership or joint venture, the in- construction of several modular plants it centive neither changes cost or prices, nor would then operate, either alone or through provides a project subsidy. * The primary ef- contracts. It could thus conduct operations to fect of this incentive on economic efficiency obtain accurate information about technical would be to reduce the effects of private sec- feasibility, project economics, and the rela- tor risk aversion. However, economic effi- tive merits of different processes. This would ciency may decrease if the Government de- be of assistance in evaluating its future pol- cides to operate as an active partner in oil icies toward oil shale, in disseminating tech- shale development projects. Efficiency would nical information, and in improving its under- be reduced if Government participation, as a standing of the value of its oil shale re- result of inexperience or bureaucratic inter- sources. After enough information had been ference, contributed to inefficient managerial obtained, the facility could be scrapped or decisions. sold to a private operator. This policy would provide the Government with information and A Government participation program experience. However, the cost would be much would entail the greatest administrative bur- higher than that of incentives to private de- den of all incentives. A new Government bu- velopers. reaucracy would probably have to be created Considering that the technologies to be *In theory, a Government participation program would be combined with a block grant program to achieve a highly effec- tested are proprietary, it is by no means clear tive subsidy and risk-sharing incentive program. that the Government would have the legal Ch. 6–Economic and Financial Considerations 215 right to publish all of the information. In addi- kind of Government intervention is likely to tion, its experience in designing, financing, discourage private developers from under- managing, and obtaining permits for an oil taking their own modular development and shale plant may not resemble that of private R&D programs. Government programs of this industry. Thus, the information acquired may kind tend to reduce the benefits that a par- be of little use to subsequent private devel- ticular firm could obtain from R&D or modu- opers. lar testing. Finally, the information argument tends to disregard the fact that patented and Most of the information secured through licensed technologies make definite provision Government ownership could be made avail- for the dissemination of technical information able as a condition of granting financial in- on both gratis and fee terms to possible users centives to private firms. Furthermore, this of a process.

Government Ownership Versus Incentives for Private Development Several factors favor incentives for private be expected to encourage efficiency. Incen- development. One is the amount and timing of tives must be limited, however, because man- Government financial support. With Govern- agement efficiency would decline under high ment ownership, Treasury funds would be levels of Government subsidy. used to supply front-end money during the A final factor is that private ownership construction period. This would involve very large initial outlays. With private ownership, and operation would develop industrial ex- incentives such as loan guarantees, purchase perience in designing, licensing, financing, building, and running an oil shale plant. Gov- agreements, and production tax credits would reduce and delay budget outlays much ernment ownership may not realistically sim- more than would be possible with Govern- ulate industrial experience. The regulatory, ment ownership. Furthermore, Government financing, litigation, and managerial experi- expenditures would be spread over the life of ences encountered by Government are usually much different from those of industry. the project. Only the failure of a project insured by a debt guarantee would obligate the Constructing an oil shale plant requires Government for more than a small fraction of committing major physical and financial re- plant cost. As noted previously, fee-based sources that would become unavailable for guarantees would reduce this risk. other purposes. Under the private option, funding would be diverted from alternative Another factor favoring private develop- private investments and consumption. The ment is that limited incentives would encour- Government option would, in the absence of age more efficient operation by leaving mana- higher taxes or funding through revenue gerial and cost risk intact. Cost-plus contract- bonds, either raise the Federal deficit or ing for a Government-owned facility could not withdraw funds from other programs.

Which Incentives Are Most Efficient and Effective? As the above discussion of alternative fi- ations. In general, all incentive programs nancial incentives indicates, there is no single must be properly administered in order to be “best” subsidy. Firms in different circum- effective, This is particularly true of nontax stances will tend to require different kinds of subsidies such as low-interest loans, debt incentives to avert the risks that prevent guarantees, price supports, and purchase them from undertaking commercial oper- agreements. These entail much greater ad- 216 ● An Assessment of 0il Shale Technologies ministrative involvement than do tax credits, to employ if the Government decides it is accelerated depreciation, or increased deple- necessary to provide financial incentives. tion allowances. The absence of close super- The subsidy effect of the purchase agreement vision of nontax incentives can lead to over- and price support incentives are relatively subsidizing developers. On the other hand, low for the contract price ($55/bbl), which the creation of bureaucratic mechanisms was computer simulated in the present anal- that are extremely time-consuming and com- ysis. This should not detract from the qualita- plicated, or which make the acquisition of the tive merits of these incentives. Furthermore, subsidy or its level dependent on future this analysis indicates that either loan guar- events that the developer cannot foresee, will antees or low-interest loans will be necessary radically reduce the subsidy effect of the in- to ensure significant participation by smaller centives. or even moderately sized firms. The high cost of providing low-interest loans suggests that OTA has concluded that production tax debt guarantees would be the best mecha- credits, purchase agreements, and price sup- nism through which to ensure this partic- ports are the most viable subsidy mechanisms ipation.

Are Financial Incentives Needed? The rationale for providing financial incen- requires to justify its investment relative to tives is that hastening the commercialization alternatives. of oil shale technologies, which although not immediately viable would probably be capa- Assuming that developers have some confi- ble of commercialization at a later date, dence in their present estimates of plant serves the long-run economic and national in- costs, and that these estimates contain con- terests of the United States, The assumptions tingencies for regulatory delay and environ- underlying this argument are that capital re- mental litigation, then the primary considera- quirements, remaining technical uncertain- tion becomes the ability to market at an ac- ties, risk of cost overruns, unstable regula- ceptable rate of return. Developers base their tory environments, and uncertainties about evaluation of marketing potential on the required rate of return and the feasibility of ob- present or future profitable marketability in- taining this return given the price of compet- dicate to developers that their capital would ing OPEC crude. Until very recently, it was be more profitably employed in alternative investments. An incentive or subsidy alters the accepted that the commercialization of shale economics of commercial production by at- oil would require some form of subsidy. tempting to either sufficiently reduce the risk In narrow economic terms it is no longer or raise the profitability to encourage devel- clear that shale oil requires subsidy to com- opment. pete profitably with conventional petroleum. Whether and to what extent oil shale de- Price hikes during the end of 1979 and the velopment will require subsidization depends beginning of 1980 have increased average on the present and anticipated future rela- posted spot prices for foreign and domestic tionship between oil prices and the cost of crudes by more than 30 percent. Wyoming producing shale oil. Expectations concerning Sweet and the best grades of North African these future trends involve a consideration of crude now have posted prices of between $34 such factors as: the developer’s confidence in and $38/bbl. The spot-market prices for these the accuracy of shale oil plant cost estimates, oils are between $40 and $50/bbl. world petroleum demand, OPEC cartel pric- If it is assumed that developers require no ing decisions, the political stability of foreign more than a 12-percent real return on their oil supply, and the rate of profit a company investment, and that current capital and Ch. 6–Economic and Financial Considerations 217 operating cost estimates are reliable, then Second, the present competitiveness of shale oil could probably be produced and shale oil assumes that developers are willing marketed profitably without subsidy. Pre- and able to accept an anticipated real dis- dicted decreases in next year’s OPEC exports count rate (i.e., rate of profit) of 10 or 12 per- (3 million bbl/d) along with the expectation of cent on an inherently risky investment. Given continued real price increases of at least 3 the nature of the risk, it is questionable percent per year, reinforce the belief that the whether developers would be willing to un- market outlook for shale oil will continue to dertake the investment at this rate. improve in the future. However, ruling out the need for financial incentives would be unwise Finally, shale oil’s emerging competitive- for several reasons. ness is related to recent oil price increases. If these increases contribute to recession in the First, the present competitiveness of shale industrialized West, petroleum demand can oil assumes realistic capital and operating be expected to decline. This could reduce cost estimates. For the reasons discussed prices in real terms, thus reducing the com- earlier in this chapter, this is still a risky petitiveness of shale oil. In the longer term, assumption, and construction and operating however, it should move to parity with con- costs are still escalating. Since a commercial ventional crude as a result of dwindling oil re- or modular facility has never been con- serves. However, shorter term price declines structed or operated, scaling-up the technol- could take place as they did during the years ogy will almost certainly add hitherto unfore- immediately following the oil embargo of 1973 seen costs as technical problems—even mi- to 1974. nor ones—are encountered. If it takes place in the context of commercializing or deploy- In the consideration of appropriate incen- ing a large number of synthetic fuel plants, tives, this relative change in the competitive- the shortage of already scarce equipment ness of shale oil implies that emphasis should such as valves, compressors, and heat ex- be placed on the desirability of incentives changers can be expected to further inflate that help with financing, while reducing the construction costs. World oil price increases risk of extreme OPEC selling price reductions in excess of the 3- or 4-percent real annual in real terms. Debt guarantees, price sup- growth assumed by developers would push ports, and purchase agreements are most construction costs up still further. likely to provide such assistance.

Economic and Budgetary Impacts The economic and budgetary impacts of oil these scenarios are discussed in detail in shale development will depend on the produc- chapter 3. Briefly, the scenarios are: tion levels and speed with which they are Production target in bbl/d of met. Low production levels are unlikely to Scenario oil by 1990 have significant effects on Government 1 ...... 100,000 spending, on the national rate of inflation, on 2 ...... 200,000 the level of national employment, or on the 3 ...... 400,000 cost and availability of capital. To examine 4 ...... 1,000,000 these impacts, four growth-related production scenarios were prepared that distinguish shale oil development by both the anticipated Industry Costs level of production and the required degree of Federal involvement. The rationales, the A standard commercial oil shale facility is technical descriptions of the envisioned conventionally described as one that would facilities, and the analytic assumptions of produce 50,000 bbl/d, with an on-stream

I ‘J – 2 “1 ~ ‘ - P _ ; , 218 ● An Assessment of Oil Shale Technologies operating factor of 90 percent, or 329 days Piceance Basins. Estimates are in third- per year. Such a facility would actually con- quarter 1979 dollars and assume a 5-year sist of a series of integrated modular retorts construction period for each plant. (normally five or six) each with a capacity of between 8,000 and 12,000 bbl/d. No single Scenario 1 Scenario 2 Scenario 3 Scenario 4 In billions 100,000 200,000 400,000 1,000,000 plant is likely to produce exactly 50,000 bbl/d. of dollars bbl/d bbl/d bbl/d bbl/d At present, the plans of the Colony operators Loans, ... , ., 0.9-I .35 1.8-2,6 3.6- 4.2 9.0-13.5 call for a commercial facility with a 45,000- Equity . . . ., . 2.1-3.15 4.2-5.9 8,4- 9.8 21.0-31.5 bbl/d capacity, tract C-b is projected to pro- Total ... , . 3.0-4.5 6.0-8.5 12.0-14.0 30.0-45.0 duce 57,000 bbl/d, a 76,000-bbl/d plant is pro- Maximum jected for tract C-a, Union Oil’s ultimate in- annual. , . . . 0.6-0,9 1.2-1.7 2.4-2.8 6.0-9.0 tention is to build a facility with a capacity in Given current estimates, an industry of 1 excess of 75,000 bbl/d, and Superior and Geo- million bbl/d would cost roughly $30 billion in kinetics expect to operate commercially prof- third-quarter 1979 dollars. But these esti- itable plants with small production capaci- mates are unlikely to be completely accurate. ties—11,500 bbl/d and 2,000 bbl/d, respec- Real cost escalations of 10 to 20 percent tively. would not be unexpected under the best of Determining the most efficient and cost-ef- circumstances. More importantly, if 1 million fective size for a commercial plant depends bbl/d are deployed over a lo-year period, on the amount, quality, and accessibility of capital cost increases for plant construction the shale resource on the tract, the method of are inevitable. Under such circumstances, mining, the type of retorting technology, and a the demand for skilled labor, for pollution variety of other factors that affect the cost of control equipment, for valves, for mining shale extraction, transportation, waste dis- equipment, for compressors, for heat ex- posal, and refining. changers, and for other needed equipment will completely outstrip supply. The conse- Current capital cost estimates for a 50,000- quences would be large price increases for bbl/d commercial-sized oil shale plant range these goods and services as well as construc- between $1.4 billion and $1.7 billion. In gen- tion delays. Hyperinflation of the costs of re- eral, these plants are expected to represent quired goods and services, equipment short- an approximately 20-percent economy of ages, and consequent construction delays scale in comparison with smaller (e.g., 9,000 could easily inflate total capital costs for fa- to 12,000 bbl/d) modular plants. A very large cilities by 30 to 50 percent in real terms. commercial facility of 100,000 bbl/d might Therefore, the costs of this scenario could represent a 10- to 15-percent economy of easily reach $45 billion. scale relative to a 50,000-bbl/d operation. Whether and to what extent these economies would actually be obtained would depend on Cost to the Government the particular properties of the development site, the mining techniques used, the technol- Each of the scenarios decribed above as- ogy adopted, and how efficiently the projects sumes a different extent of Federal involve- in question were managed. ment in the industrialization of oil shale. The scenarios differ from each other in the The estimated costs of industries of differ- amount of the target production and the de- ent sizes are presented below. These esti- gree of governmental cost and financial expo- mates assume a 30:70 ratio of debt to equity. sure. The cost to the Treasury is, in turn, de- They include the cost of hydrotreating and termined by the type and magnitude of the in- upgrading to premium crude quality and mi- centives that are provided. Those that have nor transportation costs. They do not include been evaluated in this assessment vary sub- the cost of major pipeline construction or unit stantially in the amount and kind of risk that train costs for transportation out of Uinta or they avert for the developer. They also vary Ch 6–Economic and Financial Considerations ● 219 with respect to their overall impact on project is known, and that the tax generation ability economics and potential company profits. of alternative Government uses of the moneys is also known. Since there is considerable In general, the incentives considered entail disagreement among economists over the as- costs to the Government that are directly re- sumption of what the Government discount lated to their impact on a firm’s expected rate should be, some uncertainty is intro- profits. (See tables 25 and 26.) That is, sub duced into the calculation. These calculations sidy costs to the Treasury are closely corre- assume a Government discount rate of 10 per- lated with their influence on overall project cent, which is the rate suggested by OMB. economics. However, the relation between the effect of incentives on a firm’s profits and Given these difficulties, the reported costs the cost of the incentives to the Government is to the Government of providing the incentives not exactly linear. Some subsidies clearly should be viewed as illustrative of the prob- provide more financial encouragement with able average cost of providing the incentive to less governmental cost and exposure than a number of developers. It should also be re- others. The real cost to the Government is de- membered that these estimates do not include termined by: 1) the gross cost of the subsidy, the administrative cost of overseeing the in- 2) the amount of increased tax payments due centive. Several percent could be added to to additional production, 3) the Government’s the cost of the incentive, in the cases of debt assumed discount rate (what it is assumed guarantees, purchase agreements, block could be gotten if the capital were employed grants, and low-interest loans. The costs to elsewhere), 4) the timing of the Government’s the Government reported in this chapter payment of the incentive, and 5) the timing of would apply only to first-generation facilities. a developer tax or other payback to the Gov- Subsequent plants would probably require ernment. less governmental involvement and thus Calculating the cost of incentives to the lower governmental costs. If the incentives in- Government is complicated by the difficulty cluded fade-out provisions as oil prices rose in determining the first three of these factors. in real terms and shale oil became more com- For example, the gross cost of the subsidy petitive, then the Government’s costs would (i.e., the size of the offered subsidy) is hard to also fall substantially for later plants—if the predict for several of the incentives. The price of world oil continues to rise faster than number of production tax credits that might the cost of building and operating shale oil be taken by developers is not entirely predict- facilities. able, nor is the extent of the financial obliga- In this chapter, the cost to the Government tion that the Government might incur under of providing an incentive is the gross subsidy debt insurance or guarantee programs. The to the firm less increased tax payments to the number of takers for price supports could Government. This cost was calculated in vary substantially depending on how they present value terms. The net cost for each were constructed, on the support price level, year (i.e., the subsidy less tax revenues) was and on future shale oil market conditions. discounted at the Government’s discount rate The amount of increased tax payment that (i.e., 10 percent). The resulting present value particular incentives might generate is also calculations were summed for all years. The difficult to predict. This is because the effec- nature of the Government cost calculations is tive tax rate that firms pay on production described in greater detail in appendix A. varies according to the circumstances of the Scenario 1: 100,000 bbl/d by 1990.—OTA’s corporation in question. The range is poten- analysis indicates that the production of tially from O to 46 percent on Federal taxes. 100,000 bbl/d by 1990 will probably take Finally, the calculation of these costs place without further subsidy beyond the gen- assumes that the Government’s discount rate eral purpose tax credits that are currently 220 An Assessment of Oil Shale Technologies available to any industrial or energy devel- If it were certain that any of the incentives oper. Consequently, this scenario would not included in these ranges would induce the require any additional cost to the Govern- desired level of production, the least costly ment. subsidy would be the best choice from the Government’s perspective. Unfortunately, Scenario 2: 200,000 bbl/d by 1990.—The this is not necessarily the case. As discussed cost to the Government of subsidizing the previously the particular corporate and fi- 200,000 bbl/d envisioned in this scenario nancial circumstances of individual devel- would depend, in part, on which incentives opers vary widely with respect to the specific are used to stimulate production. As is shown risks that they need or wish to avert. There- in table 25, the estimated cost to the Govern- fore, their incentive needs may be quite dif- ment of subsidizing a 50,000-bbl/d plant will ferent. Some firms may find it difficult to use depend on the incentives chosen. If the Gov- tax credits. Others may be too small or weak ernment chose to provide only one of the in- financially to take advantage of price sup- centives considered in this chapter, then its ports or purchase agreements. Instead, they costs would vary between approximately $0 require some kind of financing subsidy such and $494 million in 1979 dollars. However, this range should be adjusted in several as a low-interest loan or debt guarantee. ways. First, the construction grant subsidies Some form of choice among possible incentives is probably necessary in view of these are so costly and politically unpopular that differences. they should probably be dropped from consideration. Second, although the purchase If the Government provided a choice among agreement is a powerful incentive in theory, possible incentives, then the cost of financing its impact when set at $55/bbl over the life of this scenario would probably be between $1.2 the project is too low to have a significant in- billion and $1.4 billion in 1979 dollars. fluence on project economics. Consequently, Scenario 3: 400,000 bbl/d by 1990.—0n it should also be dropped from consideration. the basis of the same assumptions that were Each of the remaining subsidies would used in the second scenario, the cost to the yield substantial profits if a 12-percent dis- Government of providing a single incentive count rate is assumed. Although all but the would be between $800 million and $3.2 bil- low-interest loan will still yield a relatively lion in 1979 dollars. If developers were given small loss if a 15-percent discount rate is their choice among the incentives, then the assumed, this is offset by the fact that the cost to the Government to stimulate this level present calculations assumed a l-year con- of production would be between $2.8 billion struction delay. The cost of this delay is $117 and $3.2 billion in 1979 dollars. million. If such a delay does not take place, Scenario 4: 1 million bbl/d by 1990.—The then all of the incentives except the purchase costs to the Government discussed below as- agreement will provide a small profit (or sume that almost all of this production would small loss) in addition to the 15-percent dis- take place with incentives to private industry count rate (return on investment). rather than through direct Government own- Thus, the cost of spurring the construction ership. However, since the list of incentives of a 50,000-bbl/d plant with the use of a single being considered includes both a 33- and 50- subsidy would be between approximately percent construction grant, the following $100 million and $400 million over the life of analysis captures the financial consequences the project. Therefore, the cost to the Govern- of Government participation. It also assumes ment of stimulating the production of 200,000 that an effort to deploy the industry by 1990 bbl/d would be between $400 million and $1.6 would put enormous strain on U.S. manufac- billion. turing capacity (e.g., valves, heat exchangers, pressure vessels, and mining equipment), or billion and $7 billion. However, it is likely that architectural-engineering schedules, and on project failures and construction delays the reservoir of skilled workers. This would would prevent the production target from delay construction timetables and produce being met. Consequently, the above estimate sizable cost overruns. The precise amount of of cost to the Government would be more like- these overruns cannot be predicted. ly to represent a production in 1990 of 500,000 to 750,000 bbl/d rather than the full Conversations with representatives of in- 1 million bbl/d. dustry and major construction firms, plus an examination of the available literature, sug- It should be noted that the above calcula- gest that such cost escalations could easily tions do not include necessary administrative reach or exceed 50 percent of the original costs nor do they capture all of the costs of estimates. The calculations for the total additional refineries, piping, and transporta- capital cost of this scenario include this tion facilities that would be required for the assumption. It is difficult to predict the effect third and particularly the fourth scenarios. that such overall cost increases would have The estimates are in present value terms and on the cost of Government subsidies, since a do not represent, except for the block grants, large part of the increases would be ab- payment by the Government of a single lump sorbed by the developers, Increases in the sum. All the other incentives would allow total capital costs of the target production phased expenditures over a number of years, would not translate directly into higher gov- thus, limiting the Government’s financial obli- ernmental costs, but would more likely re- gations during any one year. Most important- duce overall production because of project ly, the calculations use OMB’s lo-percent dis- failures. How much the Government’s costs count rate, and assume that the gross amount escalated would be sensitive to the particular of the subsidies would be used in some equal- incentives used. They would also be affected ly productive manner if it was not spent on oil by the degree to which hyperinflation of over- shale. Assuming alternatively that these all plant costs and resulting project failures moneys were used less productively, then the reduced tax receipts. real cost to the Government of the subsidies In order to stimulate sufficient developer would fall substantially. For instance. the net commitment to stand a chance of meeting the cost to the Government of providing the low- production target, firms would have to be interest loan would be $453 million if a allowed to choose the incentive that benefited Government discount rate of 10 percent is them most. In which case, the total direct cost assumed. The cost would be $201 million if a to Government would probably be between $6 5-percent discount rate is assumed.

Capital Market Impacts and Financial Feasibility The capital outlays needed to develop a siz- the necessary financing, its achievement able shale oil production capacity are im- would mean severe distortions of the capital mense, e.g., $30 billion to $45 billion for just a markets, namely: 1) a significant increase in l-million-bbl/d capacity, This has led many to capital costs (interest rates and required question the financial feasibility of private return on equity), which would reduce other sector development and to argue that Govern- business investment and 2) distortions in par- ment financial guarantees and/or direct Gov- ticular economic segments such as housing, ernment participation are mandatory if there due to high interest rates and the “crowding is to be significant shale oil production capac- out” of mortgage financing. Yet proponents of ity by 1990 or even by 2000. Still others have shale oil development argue that there are asserted that even if the Government ensures significant long-run benefits to be gained. These include capital market benefits in form rate, for example, 100,000-bbl/d capac- terms of balance of payments, of inflation, ity (two prototypical plants) per year in sce- and of strength of the U.S. dollar. nario 3 and 200,000bbl/d (four prototypical plants) in scenario 4. Third and more realistic Concerns is to gradually build up the development rate from current levels to a target level of capaci- There is a clear need to address systemati- ty additions. For each scenario, figure 52 cally the financial and economic issues of shows the combinations of delay-overrun var- shale oil financing. Thus, it is necessary to iations and capacity addition variations. consider: 1) the level of required financing associated with alternative rates of shale oil Figure 52.—A Summary of Variations development, 2) the financial feasibility, 3) in Each Scenario the capital market impact in aggregate and on particular capital market segments, 4) fi- Uniform to 1985 nancial aspects of Government policy alter- 100,000 bbl/d to 1985 natives, and 5) the impact of shale oil on the and then no add it ions balance of payments, on inflation, on the No delay or overrun / Uniform strength of the U.S. dollar, and on tax reve- Cost = $1.5 billion (100,000 bbl/d nues. / Time = 5 years \ per year) Gradual buildup / Scenario Framework Scenario The development envisioned in either sce- 4 nario 1 or 2 would not entail significant Uniform to 1985 capital outlays, Thus these scenarios do not involve issues of financial feasibility and \ Y capital market distortions. Financial-econom- \ Delay and overrun I Uniform ic considerations would, however, cause vari- Cost = $2.1 billion (200,000 bbl/d ations to scenario 3 (pioneer commercial in- Time = 7 years per year) dustry) and scenario 4 (aggressive develop \ Gradual buildup ment). Two concerns within each scenario are: the effects of delays and cost overruns and variations in the timing of development. Delays and cost overruns.—In the absence Peak Financing Requirement of delays and cost overruns, it was assumed that the prototypical plant would take 5 years While the total capital outlay to put a shale to build and cost $1.5 billion in 1979 dollars oil industry in place may suggest financial in- (the upper end of current estimates for room- feasibility and the possibility of severe distor- and-pillar mining with surface retorting). To tions in the capital markets, it is critical to assess the effect of delays and cost overruns, recognize that the total is spread over a num- an adverse variation was considered to be a ber of years. Moreover, once there is signifi- 2-year delay and a $600 million overrun. cant capacity in place, much of the cash gen- Alternative plant initiation schedules.— eration is available to finance further There are several ways to reach a target lev- growth, so that even a growing capacity be- el for a given production capacity by 1990. comes “self-financing” at some point. One is to initiate the necessary capacity at a The key issue of aggregate financial feasi- uniform rate, and stop adding capacity in bility and capital market impact is the peak 1985 to reflect the 5 years from initiation to annual financing requirement. The annual fi- completion. Another is to add plants at a uni- nancing requirements for various scenario Ch. 6–Economic and Financial Considerations . 223 —— variations* are plotted in figure 53. The peak lays and overruns. It would be no more than financing requirements are summarized in $4.2 billion for the delay-overrun variation. table 27. Scenario 4.—The peak annual financing Scenario 3.—The peak annual financing requirement would be no more than $6.0 bil- requirement would be no more than $3 billion lion for a uniform addition of 200,000-bbl/d (1980 dollars) for a uniform addition of capacity per year with no delays and over- 100,000-bbl/d capacity per year with no de- runs. It would be no more than $8.4 billion for the delay-overrun variation.

The use of the phrase “no more than” in *For more details on the scenario variations, the cost and the paragraph above reflects the fact that revenue assumptions, the simulation methodology, and a de- very conservative assumptions about cost tailed case-by-case development of the cash flows, see Bernell and cash flow were used in each scenario in K. Stone, Shale Oil Financing: An Assessment of Financing Re- quirements, Capital Market Impact, Financial Feasibility and order to make certain that peak financing re- Finonciai Aspects of Policy Alterno tives. quirements are not understated.

Figure 53. —Year-by-Year Financing in Billions for Various Scenarios

#3: Uniform to 1985 #3: Uniform #3: Gradual buildup 5 - 5 - 5 —.. ? 4 - 4 - //’ -t 4 - / +. /0/------~%. 3 - 3 - 0 3 - 2 - \ 2 - 2 - \ \ 1 \ 1 1 - o 1 0 0 ‘ 1985 \ –1 –1 -1 –2 - –2 t -2-

#4: Uniform to 1985 #4: Uniform #4: Gradual buildup + + 10 - 10 9 “ 9 8 - 8 8 - ,--- 7 - 7 7 - / 6 - 6 6 - ,/’ / 5 - 5 5 - 4 - 4 4 - 1 3 - 3 - \ \ 2 - \ 1 \ 1 - \ o I 0 ‘ 1985 –1 - –1 –1 –2 - –2 –2 –3 - –3 –3 –4 L -4 [ -4 [

= No delay version ————— = Delay version SOURCE Off Ice of Technology Assessment 224 An Assessment of Oi/ Shale Technologies

Table 27.–Peak Financing for Each Scenario (billions of dollars)

Version No delay or overrun Delay and overrun Scenario 3 Uniform to 1985 ...... $3.00 $3.00 Uniform...... 3.00 4.20 Gradual buildup . . 2.40 3.90 Scenario 4 Uniform to 1985 .., ., . 6.00 6.00 Uniform...... 6.00 8.40 Gradual buildup ... . . 4,95 735

SOURCE Off Ice of Technology Assessment

Aggregate Financial Feasibility There is no significant problem of aggre- this level of financing should cause no signifi- gate financial feasibility. Assuming that the cant distortion of the housing industry. current rate of domestic business capital in- The capital flows are well within the finan- vestment grows at a conservative rate of 4 cial capacity of the major petroleum compa- percent into the mid-1980’s at the time of the nies. For instance, EXXON has announced a peak financing requirement, the $6 billion $6.5 billion capital investment plan for 1980. would be less than 3 percent of total domestic A survey of the 1979 annual reports of the 18 business investment and the $8.4 billion major integrated oil companies indicates cap- would be less than 4 percent. * ital investment programs exceeding $50 bil- While a figure of $6 billion to $8 billion lion per year. Moreover, cases such as the sounds like a large annual outlay, 3 to 4 per- SOHIO financing of its Prudhoe Bay develop- cent of net domestic business investment ment, and its share of the Alaskan pipeline, should cause no significant financial distor- indicate an ability for private enterprises tions in terms of interest rate shifts or capital with limited financial capacity to put together market flows. This amount is well within the creative financing packages without Govern- normal year-to-year fluctuation in domestic ment assistance, when there are promising business investment, and a small fraction of investment opportunities. year-to-year shifts in net domestic savings. Hence, not only is there no aggregate prob- Likewise, it is within normal shifts in capital lem of capital market capacity or distortion, flows from abroad. In fact, the international but there is also no significant problem of ca- capital markets are now recycling many pacity or feasibility for the private sector to times this amount of petrodollars. Finally, it is provide financing as long as shale oil is a a small fraction of the total annual mortgage profitable investment. financing market, where mortgage refinanc- ing intermediaries annually recycle tens of billions. Moreover, the experience of the past A Caveat 3 years has shown that thrift institutions can The analysis above has looked at an ag- compete for funds at times of high interest gressive development scenario in a clearly rates when rate ceilings are lifted. Hence, worst case for financial requirements and found no significant problem. However, it has *The annual rate of business expenditures for new plant and ignored other possible sources of significant equipment in 1979 is $174 billion ($180 billion seasonally ad- additional financing. Were shale oil financing justed annual rate in the fourth quarter). Hence, by the time of to be only one of several Government-sup- peak financing in the mid-1980’s, business expenditures for new plant and equipment should be well over $225 billion with ported projects, each with comparable peak 4-percent annual growth, financing requirements in the mid-to-late Ch 6–Economic and Financial Considerations ● 225

1980’s, then there is a potential problem in Table 28.–Finance Mix the sense of crowding out other domestic in- Government sharing vestment, distorting particular markets such Current Investment of construction as housing, or significantly increasing inter- tax credit only costs 20% est rates necessary to induce domestic saving Percent $ billions Percent $ billions and/or investment capital from abroad. Government 20 16 40 32 Private debt 40 32 30 24 While consideration of financing induced by Private equity 40 3.2 30 24 other Government programs is beyond the Total 100 80 100 80 scope of this report, this possibility must clearly be recognized, and an overall finan- SOURCE Off Ice of Technology Assessment cial impact assessment made.

Finance Mix were to persist for 10 years ($32 billion), the current debt capacity would tolerate such Thus far the analysis has focused on the amounts in terms of debt-equity ratios and in- total peak financing and secondary financial terest coverage. Hence, for the overall energy effects. In general, the capital markets are industry, there is no significant problem of very efficient at shifting funds between capi- providing either debt or equity, assuming that tal market segments. Therefore, the major the equity is primarily from retained earn- macro impact depends on the amount of over- ings. all financing regardless of the particular mix. Nevertheless, there are mix issues, especially capacity to provide new equity and ability to Smaller Companies and New Equity support debt without guarantees. For smaller companies, the financing bur- The investment tax credit implies that the dens can be formidable. Likewise, the magni- Federal Government automatically provides tude of equity financing for a single commer- up to 20 percent of the total investment. * A cial facility is onerous. The new equity mar- scenario of further Government support of ket is not likely to provide significant venture development cost beyond the investment tax capital for new enterprises or small compa- credit could be an additional 20 percent for a nies in this area. Without Government assist- total Government share of 40 percent. These ance, a small company can participate only two cases are summarized in table 28 assum- via joint ventures. However, this limitation is ing the remainder is 50-percent debt and 50- not unique to shale oil. Small companies can- percent equity. The actual share of debt in not generally undertake billion dollar capital the total financing is less, namely 40 percent investments in any industry. Moreover, such and 30 percent respectively. companies generally lack the managerial and Table 28 shows strikingly that there should technical resources to undertake such ven- be no financing problem for the major oil com- tures successfully. While financing is an panies. Both current earnings and retained obstacle for small companies, it is probably earnings (earnings after dividends) are many not as severe as building the organization to times this amount for the 18 largest compa- manage such a project. nies. Significant contributions to establishing a Debt capacity of the major oil companies is large shale oil industry should not be ex- also more than adequate. Even if peak needs pected from small companies. Both technical and managerial talent and financial re- *The use of 20 percent here assumes that the extra IO-percent investment tax credit continues. Otherwise, this figure sources for major development reside in the will drop to 10 percent. large energy companies. 226 ● An Assessment of Oil Shale Technologies

Secondary Financial Impacts and Benefits In addition to the peak capital require- For every dollar reduction in the price of ments and the direct impact on the capital world oil (at current import levels of approx- markets, there are also a variety of second- imately 3 billion bbl/yr), there is a $3 billion ary financial effects—balance of payments, improvement in the balance of payments. strength of the U.S. dollar, inflation, and tax revenue (net effect on the Federal budget). Taxes Balance of Payments and Strength The direct effect of any shale oil incentives of U.S. Dollar can be either a reduction in taxes and/or Government payments to shale oil producers. Shale oil development has two balance-of- Hence, the direct effect of incentives is to in- payment effects—the direct effect of its pro- crease the Government deficit. To the extent duction and the indirect effect from its in- that there is a net increase in economic activi- fluence on the world oil price. ty, there are countervailing tax revenue benefits. These include: 1) the taxes paid by shale Direct effect.—Producing shale oil will re- oil producers, 2) the taxes paid by suppliers duce the need for imports. There should be a to the shale oil companies, 3) the taxes paid one-for-one substitution of shale oil for im- by workers for shale oil companies, and 4) the ported oil. At a $30/bbl current-dollar price taxes paid by workers for shale oil suppliers. for imported oil in the mid- to late 1980’s, the shift in balance of payments is $5.5 billion It is very difficult to assess the impact of (scenario 3 with no delay) to $7 billion (sce- shale oil financing on Federal tax revenue. nario 4 with delay) in 1990. It would rise to One of the primary variables is the extent to $15.5 billion (scenario 3 with no delay) to which shale oil production and related eco- $27.0 billion (scenario 4 with delay) in 2000. nomic activity is incremental (net new domes- These effects are summarized in table 29. tic production) or substitutes for other eco- Indirect effect.—The indirect effect arises nomic activity. from price pressure exerted by domestic Estimates of the incremental Federal tax shale oil production on the price of world oil. revenue are summarized in table 30. Two cases are considered—loo-percent incre- Table 29.–The Current Dollar Improvement in the Annual U.S. mental domestic production and a more plau- Balance-of-Payments Position Associated With Afternative sible 50-percent incremental production. The Development Rate Scenarios effect is modest in 1990 due to the assumption Representative years of no taxes by the shale oil producers. How- Improved source 1990 1995 2000 ever, by 2000 it rises to several billion. These figures exclude secondary activity such as in- Scenario 3 with no delay or cost overrun and annual capacity additions at the rate of cremental tax revenues due to servicing the 100,000 bbl/d employees and suppliers. They also do not Direct substitution (billions)a , ... ., ., ., $5.5 $10.5 $15.5 reflect any benefits of higher employment in Scenario 4 with 2-year delay and a $600 million reducing unemployment compensation and cost overrun and uniform annual capacity additions at the rate of 200,000 bbl/d welfare payments. Direct substitution (billions)b , ., ., ., ., ., 7,0 17.0 27.0 Any reduction in the Government deficit aThls assumes the current dollar price of world 011 IS $30/bbl In each year and corresponds 10 starf-of.year capaclly oi O 5 mllllon In 1990, 1 mllllon In 1995, and 1 5 mllllon In 2000 plus will be a long-run benefit to the capital mar- 50 000-bbl/d average production from phase-in of 100,000 -bbl/d capacity In each year kets to the extent that it reduces deficit fi- blhls assumes the Currerl[ dollar prtce of world 011 IS $30/bbl in each Year and corresponds 10 sfafl-ol-year lull produc!lofl capacity of O 6, 1 6, and 26 mllllon bbl/d respectively for 1990 nancing and the associated “crowding out” 1995, and 2000 plus 100000 bbl/d average produc!lon from phase-in of 200 000-bbl/d capac- Ily In each year of private sector financing by Government SOURCE Office ot Technology Assessment debt. Ch. 6–Economic and Financial Considerations 227

Table 30.–A Summary of Estimates of the Improvement in been noted that this should be minor since the Federal Tax Revenue Attributable to Shale Oil Production From peak capital outlays are small as a proportion the Taxes Paid by Shale Oil Companies, Their Employees, Their Suppliers, and Their Suppliers’ Employees of total business investment, and would require only a modest change in saving. The Representative years various secondary financial effects (balance 1990 1995 2000 of payments, Government deficit, inflation) Scenario 3–uniform 100,000-bbl/d capacity also impact capital market rates. The long- growth and no delay Value of annual production (billions) $5,50$1050$1550 run effect of improved balance of payments, Proportion of annual production paid in taxes 15 .20 25 reduced inflation, and reduced deficits will Net tax Improvement. 100% new activity (billions) 83 2,10 388 be to reduce capital market rates—both in- Net tax Improvement 50% new activity (billions) 41 1.05 1,94 terest rates and required equity returns nec- Scenario 4–uniform 200,000-bbl/d capacity growth and delay essary for any given level of savings. The Value of annual production (billions) 700 1700 2700 long-run reduction should be several percent- Proportion of annual production paid in taxes. 15 .20 ,25 age points. Moreover, while the short-run im- Net tax Improvement 100% new activity (billions) 1.05 340 675 Net tax Improvement. 50% new activity (billions) pact of higher inflation would be adverse, the .53 1 70 3.38 fact that capital markets are “anticipatory” Notes on the lax proportions 1 The proportions used here ( 15 20 and 25) are developed In delall m Bernell K Stone (i.e., future looking) means that current rates S)ra/e 01/ F/nanc/rrg ArJ 4ssessrnenf of Fmamng Reqwrernenls Caplfa/ Marker knpm Fman- will reflect not just current inflation but also c/a/ Feas@//lly and Fmanc/a/ Aspects of F’o/Icy Allemahves They assume a 20 percent before- Iax rate of return for the compames 20 percent dlrecl labor expense 50 percent supplrer ex the future improvement in inflation, balance pense and 10-percent other Supplrer direct labor payments are assumed to be 50 percent of suppller revenue of payments, and the budget deficit. Thus, the 2 The corporate and personal [ax rates used were 50 and 25 percent respectively long-run improvements could outweigh both 3 The propofllons assume no corporate Iaxes Irom shale 011 producers [n 1990 (due 10 acceler aled depredation and [nvestment lax Credltsj a 25 percent elfectwe rate tn 1995 and a full 50- the short-run effect of inflation and the in- percenl (ate In 2000 creased financing need. Consequently, the SOURCE Off Ice of Technology Assessment overall effect of shale oil on capital market rates is at worst a minor short-run increase Capital Costs: Secondary Effects and a clear long-run decrease. The direct effect of more capital investment is to raise capital costs. It has already

Financial Aspects of Policy Alternatives Impact on Peak Financing taxes, either of which reduces funds available for private sector financing. From the viewpoint of aggregate impact, the most important Government action is that which prevents or at least minimizes delays General Impact of Subsidies (i.e., by removing environmental delays and The overall effect of subsidies and/or risk licensing delays once a plant is started), thus, reduction is to make investment more attrac- cost over-runs. tive and ensure more rapid development than would otherwise take place. Subsidies also Impact on Private Sector Share make possible more rapid private-sector de- of Peak Financing velopment once a basic industry is in place, i.e., beyond the 1990 period. Government subsidies in the construction and very early production stages reduce the Government willingness to subsidize, espe- private sector share of peak financing but not cially via production subsidies and minimum the overall impact. This is because the Gov- price guarantees, sends an important mes- ernment must raise its share via some com- sage to savers and the world capital mar- bination of Government borrowing or more kets—namely that there will be a significant 228 ● An Assessment of O/1 Shale Technologies

U.S. shale oil industry with decreasing reli- pacity of the capital markets, increases in ance on foreign oil. Hence it should reduce in- capital costs, or reallocations from other flationary expectations, induce savings, in- industrial-financial sectors of the economy. duce investment from abroad, and strengthen Major energy companies have the capacity to the U.S. dollar. These policies could, there- provide any reasonable mix of debt and equi- fore, have an immediate and significant bene- ty via retained earnings. ficial effect on the domestic capital markets via their impact on future expectations. Long-run secondary effects on balance of payments, strength of the U.S. dollar, infla- Summary tion, and the budget deficit are all favorable. The overall impact on capital markets should There is no significant problem in provid- . also be favorable, especially given that cur- ing peak financing requirements even for rent rates will reflect future expectations rapid shale oil development in terms of ca- about inflation and the balance of payments.

Effect on Inflation and Employment Oil shale programs will undoubtedly be a Even the realization of the second scenario part of a larger synthetic fuels policy. All of (200,000 bbl/d), would have negligible effects the legislation before Congress is concerned on national inflation and employment. How- with the development of a synthetic fuels in- ever, the inflationary effects of this produc- dustry as such. The development of oil shale, tion on the cost of the machinery and equip- were it to take place, would do so in the con- ment necessary to the industry might be text of some particular array of policies con- small, although discernible and could be sig- cerned with such issues as conservation, oil nificant, particularly on the price of labor, import reduction, coal conversion, and/or inland, and rents, in the immediate geographi- creased solar power usage. Furthermore, cal areas of development. shale oil development, like any other long- term financial commitment, will interact with Even the third scenario (400,000 bbl/d) Government policy and economic trends in would not have an appreciable effect on na- numerous areas such as monetary policy, tional inflation rates or employment levels, It fiscal policy, tax policy (the windfall profits would substantially affect local prices, have tax is particularly relevant), the characteris- an enormous positive impact on local employ- tics of the balance of payments, and overall ment, and a definable one on regional employ- capital availability. To evaluate how prices ment. Depending on the phasing of the influx and employment will be affected by oil shale of workers, the local expenditures by the de- development, it would be necessary to exam- veloper, and the approach taken in dealing ine these effects for all of the major synthetic with socioeconomic impacts, the inflationary fuels proposals before Congress, and attempt effect on land, labor, rent, and goods could be to assess the course of the U.S. economy over very large, particularly on land and rents. the next 10 years. This task is outside the (See ch. 10.) scope of this report. However, the Congres- sional Budget Office in its September 7, 1979 The prices for the machinery and equip- report to the Senate Budget Committee has at- ment used for constructing the facilities tempted to make such an analysis. would escalate sharply. It has been estimated that the construction of an industry with a The impacts on prices and employment na- 400,000-bbl/d capacity would use between 10 tionwide of the deployment of the first sce- and 20 percent of the current U.S. manufac- nario (100,000 bbl/d) would be insignificant. turing capacity for valves, pressure vessels, Ch. 6–Economic and Financial Considerations 229

heat exchangers, and certain kinds of mining The net effect will tend to push up the prices equipment.6 This would clearly be inflation- of the essential elements of production. ary for these industries. The extent would depend on the rapidity with which the indus- Assuming that all other factors remain the tries could respond to the increased demand, same, the tendency will be for the inflation how much in advance of need the equipment rate to fall by 0.05 to 0.1 percent and for the orders were placed, and the availability of level of unemployment to rise by 0.025 to 0.05 foreign substitutes. percent during the earlier period of development. During the latter half of the decade, It is likely that the fourth scenario (1 however, employment in the industry will million bbl/d by 1990) will affect the national grow sufficiently to very slightly reduce the economy somewhat differently from 1980 national rate of unemployment (i.e., 0.015 to through 1985 than it will from 1986 through 0.025 percent). During this time, the tendency 1990. The short-run direct effect of shale oil will be for increasingly rapid investment to development will be to use resources with no exert only a small influence on the rate of in- offsetting production. Hence, it would be flation. It is unlikely that this impact would clearly inflationary, although the direct infla- exceed 0.1 percent. These figures should be tionary impact might be offset somewhat by regarded as tendencies representing the di- price pressure on world oil. rection of the impact—if nothing changes. The long-run effect will be to reduce infla- Given the high probability that all things will tion because of the substitution of domestic not remain the same, these estimates should production for imports, the pressure on the be viewed with extreme caution. One fact is, world price of oil, the improvement in the bal- however, quite clear: oil shale development ance of payments, and the favorable impact by itself will have a very small impact either on the Federal budget. Moreover, because on national rates of inflation or on employ- capital markets set current rates on the ex- ment. pectation of future events, the anticipation of reduced inflation can lower current capital Although the national impacts would be costs. quite small, the local, regional, and sectoral effects would be much more substantial. De- Simultaneously, however, this oil shale pro- velopment of the magnitude envisioned in this gram could also exert inflationary pressure scenario would bring many operating, profes- on general prices over the longer term start- sional, and construction employees into the ing in the early to middle 1980’s because the area. This will unquestionably have an ex- high demand created by the level of invest- traordinary impact on local prices, rents, and ment would probably create temporary bot- land costs, as well as on local employment. tlenecks in various sectors of the economy, These issues are discussed in detail in and shortages of materials and skilled labor. chapter 10.

Construction Industry and Equipment Capacity

Current construction equipment capacity ● the availability of various kinds of long will severely hamper the ability to achieve oil leadtime equipment such as pressure shale production at the level assumed in the vessels, valves, compressors, pumps, fourth scenario. It is apparent that limita- heat exchangers, heavy mining equip- tions will be encountered in the following ment, and alloy components; areas: the capacity to move equipment to remote construction sites, and to transport . the capacity of design and construction shale oil by rail and pipeline to markets firms; or refineries; and 230 An Assessment of Oil Shale Technologies

● the availability of sufficient numbers of value near the level of expenditure required an adequately trained labor force to to construct a small commercial oil shale meet construction schedules. plant—$400 million per year.7 It can, therefore, be concluded that no more than 21 firms Meeting the production targets will neces- have the current capacity for such work. sitate substantial improvements in each area. Many of these are already booked years in Such an expansion of capacity will require a advance. However, workloads between now national commitment to divert resources from and 1985 will probably increase the number other areas and uses, will create bottlenecks of firms that are able to undertake projects of in other parts of the economy, and will lead to this magnitude. There is also the possibility rapid inflation of costs in the relevant mining, that by combining together, smaller firms will construction, and equipment industries. In be able to undertake such projects. order to achieve this production goal the following annual manpower and equipment In 1978, the construction industry con- needs would have to be met. tracted for $27.2 billion worth of new work, In these projections it is assumed that ap- only $21.6 billion of which was industrial proximately 20 commercial facilities having work. Thus, the annual construction costs of an average capacity of 50,000 bbl/d will be the oil shale plants that would have to be built constructed. Most would not reach the design between 1983 and 1990 to reach the million- stage until at least 1982. Their construction is barrel-per-day target represents 35 percent unlikely to be started until between 1983 and of the workload in 1978. 1984; and will not be completed until between 1989 and 1990. Consequently, many of the In particular, shortages of skilled labor can projects will be designed and constructed si- be expected during efforts to deploy an indus- multaneously, thus, severely taxing the ca- try of this size. In 1978, there were approx- pacity of equipment suppliers and construc- imately 45,000 workers in the United States tion firms. having the necessary technical and professional skills (e. g., draftsmen, engineers, man- These projects because of their size, com- agers, and scientists). From 1983 to 1990, plexity, and the vast array of skills and exper- shale oil plants producing 1 million bbl/d tise they require, will necessarily need to be would require 11,000 to 18,000 professional contracted to a limited number of large archi- employees, which is more than 36 percent tectural-engineering firms. Only a few design above process industry requirements in 1978. and construction firms have the managerial, At this time, the United States has a total con- technical, and economic experience to construction work force of around 4.5 million. struct such plants. An examination of the ex- During each year between 1983 and 1990, isting capacity of such firms by Engineering constructing the plants would require an ad- News Record on April 12, 1979, indicates that ditional 130,000 workers. The need for such a of the construction firms involved in building large labor force would act to hamper the manufacturing process facilities, only 21 con- deployment of an industry of this size, and tracted in 1978 for work having a total dollar would substantially inflate labor costs. Ch. 6–Economic and Financial Considerations ● 231

Chapter 6 References

IThis discussion is indebted to that presented on Synthetic Fuels of the Committee on the Budget by Robert Merrow, Constraints on the Commer- of the United States Senate, Sept. 27, 1979, pp. cialization of Oil Shale, RAND Corp., 1977, 46-47. zThis discussion in this section draws on mater- ‘Edward W, Merrow, Constraints on the Com- ial presented by Robert Merrow, Constraints on mercialization of Oil Shale, RAND Corp., Septem- the Commercialization of Oil Shale, RAND Corp., ber 1978, pp. 16-18. 1977, and Synthetic Fuels: A Report Prepared for ‘Wallace E, Tyner and Robert J. Kalter, “A Sim- the Budget Committee of the U.S. Senate, 1979. ulation Model for Resource Policy Evaluation, ” ‘Synthetic Fuels: Report by the Subcommittee Cornell Agricultural Economics Staff Paper, Sep- on Synthetic Fuels of the Committee on the Budget, tember 1977. United States Senate, September 1979, p. 180. ‘“A Fluor Perspective on Synthetic Liquids, ” Statement made by Cameron Engineers. Fluor Corp., 1979. “Synthetic Fuels, Report by the Subcommittee CHAPTER 7 Resource Acquisition contents

Page Page Introduction **** **** ** be** *, *O** 238 32. Distribution of the Oil Shale Resources in Colorado and Utah...... 244 The Evolution of Leasing and Land Exchange. 235 33. Estimated Shale Oil Production by 1990 Leasing Programs ● .*****@***.,*.,*****,* 237 in Response to Various Federal Actions. 250 Land Exchanges ...... 241 The Adequacy of Private Lands...... 241 Present and Potential Projects on Private Land ...... ● ...... ,...244 List of Figures Present and Potential Projects on Figure No. Page Federal Land...... 246 54. Ownership of the Oil Shale Resources of Is More Federal Land Needed? ...... 249 the Green River Formation ...... 235 55. Locations of the Tracts Offered for Policies ● ****, **, *.. *.. *,**, *,*.,*., 250 Lease Under the Prototype Program . . . . 239 Chapter 7 References .. ..,.....,...... 252 56. Privately Owned Tracts in the Piceance Basin...... ,.. 243 List of Tables 57. Thickness of the Oil Shale Deposits in the Piceance Basin That Yield at Least 25 Table No. Page gal/tonof Shale Oil...... 245 31. Tracts Offered Under the Prototype Oil 58. Location of the Sodium Mineral Deposits Shale Leasing Program ...... 240 in the Piceance Basin ...... 246 CHAPTER 7 Resource Acquisition

Introduction On May 27, 1980, the Department of the Interior (DOI) announced several oil shale decisions. Up to four new tracts will be leased under the Prototype Program and preparations started for a permanent leasing program. At least one multimineral tract will be included in the renewed Prototype Program. Land exchanges will not be given special emphasis, and no decision will be made to settle mining claims until the Supreme Court rules on Andrus v. Shell Oil (the oil shale mining claims discovery standard case). [Note: This case was decided on June 2,1980 (No. 78-1815).] The administration will propose to Congress legislation to give DOI the authority to grant leases bigger than the present statutory limitation of 5,120 acres, to provide for offlease disposal of shale and siting of facilities, and to allow the holding of a maximum of four leases nationwide and two per State. -

The resources of the Green River formation Figure 54.—Ownership of the Oil Shale Lands are owned by the Federal and State govern- of the Green River Formation ments, by Indian tribes, and by numerous pri- PICEANCE BASIN UINTA BASIN (COLORADO) (UTAH) vate parties. (See figure 54. ) Overall, the Fed- INDIAN 8% eral Government owns about 70 percent of PRIVATE FEE 9% PRIVATE FEE STATE 6% the land surface, which overlies about 80 per- zl~. cent of the resources. The Federal land contains the thickest and richest oil shale de- FEDERAL 79-. posits and essentially all of the large deposits FE DE FiAL 77°. of sodium minerals. About 20,000 acres (less e B than 1 percent) of the Federal land has been GREEN RIVER BASIN WASHAKIE BASIN allocated for private development through (WYOMING) WYOMING-COLORADO) the Prototype Oil Shale Leasing Program. In the future, it may be necessary to involve more public land for either private or governmental development, if certain technologies are to be tested or if a large industry is to be established rapidly. Releasing this land would be affected by the laws that govern leasing and land exchange, by unpatented @sATE%@’’’”o” mining claims over most of the Federal land, SOURCE Map of the Ma/or 0// Shale Ho/d/rigs —Co/orado, Wyom/ng Utah, and by other factors. Denver, Colo Cameron Engineers, Inc , January 1976 This chapter deals with the issues surrounding the use of Federal oil shale land. The following subjects are discussed: ● leasing and land exchange programs and their problems; and ● the possible need for committing more public land; ● options for involving more Federal land.

The Evolution of Leasing and Land Exchange The legal framework that governs the use both complex and unsettled. It incorporates a of public land for oil shale development is series of laws and policies dating back two

235 236 . An Assessment of 0il Shale Technologies centuries that reflect conflicting philosophies The Secretary of the Department of the Inte- about the role of the Federal Government as rior (DOI) was given authority to enforce the trustee of the public land. provisions of the 1872 Mining Law and to oversee the filing of claims and the granting The Continental Congress created the pub- of patents. The Petroleum Placer Act of 1897 lic domain from lands ceded to the new Con- added “lands containing petroleum or other federation by the individual States. In 1788, mineral oils” to those subject to the location the Constitution granted Congress the power and patenting provisions of the 1872 Mining to dispose of the public domain (including sur- Law. This action led to a flood of claims for oil face, mineral, and other rights) for the com- and gas reserves, and large areas of public mon benefit of all the States. By 1850, the land were transferred to private hands as a public domain extended to the Pacific coast, result. including the oil shale lands in Colorado, Utah, and Wyoming. The Preemption Act of In the early 20th century, the philosophy of 1841 and the 1846 Lead Mines Statute au- free exploration and occupation of the public thorized the transfer of public lands to private parties, and the Homestead Act of 1862 domain came under scrutiny because of the allowed settlement of Federal lands in the rise of the conservation movement and con- West for agricultural purposes. Some tracts cern over the dwindling supply of strategic materials, including oil. This led to two ac- along streams in the Piceance Basin were acquired by settlers under this Act. The Mining tions:

Law of 1866 declared the mineral lands of the ● public domain to be free to exploration and President Theodore Roosevelt’s execu- open to appropriation by those prospectors tive withdrawals of public lands that who found “lode-type” deposits on the land. contained coal, timber, oil, water, and other essential resources; and “Placer” deposits were excluded under this ● Act but were subsequently opened to appro- DOI’s stricter enforcement of its re- priation under the Placer Act of 1870. * quirements for granting of patents for mining claims. The Mining Law of 1872 combined, revised, and augmented the 1866 and 1870 President Roosevelt’s withdrawals were pro- laws, and subsequently governed disposal of tested in Congress, especially by representa- all minerals that are not otherwise explicitly tives of the Western States, but Presidential covered by other legislation. Prospecting was authority for such withdrawals was subse- recognized as a statutory right. Upon locating quently upheld by the Supreme Court. In l909 a valuable mineral, a prospector could: and 1910, President Taft withdrew the remaining public domain from appropriation by ● stake a claim encompassing all or part of the deposit; oil and gas claims. More controversy ensued, and in 1910, at President Taft’s request, Con- ● develop the deposit; gress passed the General Withdrawal Act— ● mine, process, and sell the minerals; and The Pickett Act—which authorized the Presi- ● obtain ownership to the land’s surface dent to withdraw public lands by Executive and its mineral values by paying from order from settlement, location, sale, or other $2.50 to $5.00/acre, by performing about entry. The withdrawals were to be temporary $500 worth of development work on the and could only be made for the purpose of $100 claim, and by carrying out at least evaluating the land for water powersites, ir- per year of “assessment” work until the rigation, classification, or other public uses. time that ownership was transferred by All lands thus withdrawn would remain open a legal document called a patent. for exploration, discovery, and appropriation *A lode deposit is confined by rock in the place where it was under those provisions of the Mining Law of originally formed. Placer deposits are lode deposits that have been broken down, transported, and redeposited in alluvial 1872 that applied to metalliferous (metal- sediment as a result of exposure to flowing water or ice. bearing) ores. Ch. 7–Resource Acquisition “ 237

In 1914, Congress severed known fuel and 1916 coincided with predictions of wide- fertilizer mineral rights from the rights to the spread fuel shortages as a result of diminish- surface of lands appropriated for agricultur- ing petroleum reserves. Based on informal al uses. The Stockraising Act of 1916 re- representations that oil shale would be served to the Government all mineral rights. treated as a locatable mineral under the Petroleum Placer Act of 1897, more than 10,000 claims of 160 acres each were filed The Mining Law and the other land-man- before 1920. Filing for oil shale claims was agement laws had little effect on oil shale ended in 1920 with the passage of the Miner- prior to 1916 because interest in the mineral al Leasing Act. Also in 1920, DOI determined was negligible. However, in 1914, the U.S. that oil shale had been a locatable mineral. Geological Survey began investigating the oil Questions related to the valid location and shale deposits to determine their potential for maintenance of these claims became a source yielding fuels. Publication of the results in of contention that has endured to the present.

Leasing Programs The Mineral Leasing Act of 1920 ended the sive to produce compared with conventional process of claiming Federal land for petro- petroleum, and therefore any additional leas- leum, gas, coal, oil shale, phosphate, and ing could only result in speculation, The sug- sodium minerals. However, private firms gestion was adopted by the Secretary and could be given an opportunity to develop transmitted to President Hoover, who issued these minerals through leasing programs ad- Executive Order 5327, which withdrew the ministered by DOI. The Secretary of the In- oil shale lands from leasing under the Miner- terior was required to assess annual rentals al Leasing Act. The order “temporarily” re- of 50 cents per leased acre, and the maximum served the lands for the purpose of “investi- size of an oil shale lease tract was limited to gation, examination, and classification, ” as 5,120 acres (8 mi2). No individual or firm required by the Pickett Act under which it could hold more than this acreage under was promulgated. lease. * Except for these provisions, the Sec- Since 1930, this temporary order has been retary was given broad discretionary powers modified on a few occasions. In 1932, for ex- to select lease tracts and to shape the terms ample, President Hoover’s Executive Order of development leases. Five oil shale lease ap- 6016 permitted oil and gas leases on the oil plications were filed with DOI after 1920. shale lands, and in 1935, President Roose- Three leases were issued, but all were subse- velt’s Executive Order 7038 authorized pros- quently canceled. pecting permits and development leases for In the early 1920’s, during the Harding ad- sodium-bearing minerals. The withdrawal ministration, Secretary of the Interior Fall order has also been modified from time to was alleged to have accepted bribes from an time to permit disposition of surface rights in oil company in consideration of noncompeti- limited areas. With these exceptions, it re- tive leasing of Naval Petroleum Reserve No. mained in effect and essentially unaltered for 3—the Teapot Dome field in Wyoming. In over 40 years, during which no oil shale 1930, during the era of caution that followed leases were issued. the Teapot Dome scandals, DOI’s Solicitor In 1952, President Truman issued Execu- suggested that oil shale lands be withdrawn tive Order 10355, which authorized the Sec- from leasing because shale oil was too expen- retary of the Interior to rescind the with- *Shares in several leases could be held, but the total area drawal order. Subsequent Secretaries, how- covered by the shares could not exceed 5,120 acres. ever, were reluctant to exert this authority 238 ● An Assessment of Oil Shale Technologies

for fear of creating the environment for a no acceptable bids were received for the in leasing scandal like Teapot Dome. DOI’s hesi- situ tracts in Wyoming. The lack of response tation was compounded by the uncertain was related to the poor quality of the Wyo- status of unpatented mining claims on much ming resources and to the primitive status of of the Federal land and by a feeling that shale in situ technologies. In 1976, DOI proposed to oil was not needed. lease two other in situ tracts in the richer Col- orado shales. Several sites were investigated In the 1960’s and early 1970’s pressure from congressional delegates from Colorado, and a supplemental EIS was begun. The idea Utah, and Wyoming, and urging from State was abandoned in 1977 when Colorado tracts officials and the energy industry, contributed C-a and C-b switched from aboveground re- to the formulation of two different but related torting (AGR) to modified in situ (MIS) processing. The reasons for this shift were tech- leasing attempts. The first was promulgated nical problems with the fractured oil shale on between 1964 and 1968 as part of a comprehensive oil shale program in the Johnson ad- tract C-b and a ban on the disposal of mining ministration under Secretary of the Interior and processing wastes outside of tract C-a’s Stewart Udall. Secretary Udall’s lease offer- boundaries. Development of both tracts was ings failed to attract private participation. resumed after a l-year delay and both are now proceeding towards commercial opera- Other portions of his program were carried forward into the Nixon administration, how- tions. ever, where they were supplemented by the Development of the Utah tracts has been Federal Prototype Oil Shale Leasing Program stopped by legal battles between the Federal under the direction of Secretaries Hickel and Government, the State of Utah, and private Morton. * firms over ownership of the lands encompass- The Prototype Program officially began on ing the tracts. There are basically two types June 4, 1971, when President Nixon in- of conflict. The first is related to the cir- structed the Secretary of the Interior to ex- cumstances under which Utah was granted pedite a leasing program that would encour- statehood. Under the Statehood Enabling Act age oil shale development while providing for of 1894, Utah was allowed to take title to four environmental protection. On June 19, 1971, sections out of each township with the intent Secretary Morton announced plans for the that the proceeds from their sale or use Prototype Program and simultaneously re- would be applied to public education. For var- leased the preliminary environmental impact ious reasons, selection of a large number of statement (EIS). In April 1972, DOI desig- these sections was delayed, and in some nated six tracts of about 5,120 acres each, cases whole townships were made ineligible which were offered for lease in 1974. Their by their inclusion in Federal reservations. In locations are shown in figure 55. Dates for lieu of sections in these townships, Utah was the sale of individual leases and other details allowed to select other sections in other town- of the Program’s initiation are summarized in ships. table 31. By the 1960’s, Utah’s stockpile of in lieu se- It is noteworthy that the initial develop- lections had reached 225,000 acres. Between ment plans covered a range of technological September 1965 and November 1971, Utah options: underground and surface mining, applied for 157,225.9 acres of land in the oil aboveground and in situ retorting, and mining shale area. Included were the present sites of in ground water aquifers and in dry zones. It lease tracts U-a and U-b. DOI declined to was estimated that the six tracts would be transfer the title to this land, and litigation producing a total of 250,000 bbl/d by 1980. ensued. To avoid delaying the Prototype Pro- This goal was immediately set back because gram’s initiation, DOI and Utah agreed that the proceeds from the leasing of tracts U-a *Both leasing attempts are discussed in detail in vol. 11. and U-b would be held in reserve until the Ch. 7–Resource Acquisition ● 239

Figure 55.— Locations of the Tracts Offered for Lease Under the Prototype Program

IDAHO I 1 GREEN — . . i \ I RIVER WYOMING I \

● Rock Springs W-a & W-b / BASIN WASHAKIE I I I BASINlx” --— . . ‘) --r--”--—--- SAND I WASH ● Salt Lake City UTAH --nI BASIN COLORADO

o 25 MILES c 1 1 1 1 1 I $ u ( H%/ I II 011 shale deposits of the Green Rwer formation

SOURCE T A Sladek, Recent Trends In 011 Shale–Part 3 Shale 011 Refln~ng and Some 011 Shale Problems, ” Minerals Irrdustr/es Bullet/n, VOI 18, No 2 March 1975 case was decided. Utah also agreed to hold This case should not have unduly con- the lessees to the terms of the Federal leases cerned the lessees because its outcome would if the State took title. The lawsuit proceeded not have affected the leasing regulations. through the U.S. District Court and the Cir- However, the situation was complicated cuit Court, which ruled in favor of Utah, and when a mining company applied for a prefer- is now in the U.S. Supreme Court, where it of the Interior could reject Utah’s applications for oil shale will be heard during the 1980 session. * lands as school land indemnity selections because the selected lands were grossly disparate in value to the school land grants *On May 19, 1980, the U.S, Supreme Court, in a 5-4 decision, that were lost to preemption or prior entry (Andrus v. Utuh, No. reversed the lower court decisions and held that the Secretary 78-1 522). 240 ● An Assessment of Oil Shale Technologies

Table 31 .–Tracts Offered Under the Prototype Oil Shale Leasing Program

Tract Location Date of sale Winning bidder Winning bid Development concept C-a Colorado 1/8/74 Rio Blanco Oil Shale project $210,305,600 Open pit mining: aboveground retorting (Gulf 011, Standard Oil of Indiana) C-b Colorado 2/1 2/74 C-b Shale Oil project (Atlantic 117,788,000 Underground mining: aboveground retorting a b Richfield, Tosco, Shell, Ashland) U-a Utah 3/1 2/74 White River Shale Oil Development 75,596,800 Underground mining, aboveground (Sun 011, Phillips Petroleum) retorting c b U-b Utah 4/9/74 White River Shale Oil Corp. 45,107,200 Underground mining; aboveground (Sun Oil, Phillips, Standard of Ohio) retorting W-a Wyoming 5/14/74 None In situ (suggested by DOI) W-b Wyoming 6/11/74 None In situ (suggested by DO I) alndlrec[ly healed retorfs (e g TOSCO It) bsubsequently umhed for common development ccomblna[lon 01 Indtrec[ly heated and dwec!ly heated retorls (e g TOSCO II and paraho or 9as combustion) SOURCE OftIce of Technology Assessment

Photo credit OTA staff

Development on Federal Prototype Leasing tract C-b ential State lease to the tract area. This might overlie most of the Federal oil shale lands, in- have superseded the Federal lease and there- cluding the Utah lease tracts. In the early fore obviated development of the tract by the 1970’s, when the Prototype leases were sold, Prototype lessees. Another suit was initiated, DOI was confident that the unpatented in this instance between the mining company claims would be invalidated, and that the and the State of Utah. Proceedings have been Government would retain title to the lands in stayed pending resolution of the in lieu liti- question. In early 1977, however, a court gation. decision in favor of the claimants was issued in a case involving unpatented claims in Col- A further complication was introduced by orado. Because this precedent could eventu- the unpatented pre-1920 mining claims that ally have resulted in validation of the claims Ch 7–Resource Acquisition 241 overlying U-a and U-b, the lessees sued for other two, Colorado tracts C-a and C-b, are and won a suspension in the lease terms, The being developed for MIS processing, The les- suspension is still in effect, pending a Su- sees of tract C-a are also negotiating for a preme Court decision on the issue of unpat- demonstration of the Lurgi-Ruhrgas AGR ented claims. * technology. If both tracts proceed to commer- In summary, no permanent leasing pro- cialization, they could produce a total of gram exists for the Federal oil shale lands, 133,000 bbl/d by 1987. With current plans, and under the present Prototype Program, one mining technique, one in situ process, and four tracts have been leased, but two are in- one aboveground retort will be evaluated, active because of legal uncertainties. The Open pit mining will not be tested, nor will other in situ or AGR techniques. All of the *On June 2, 1980, the U.S. Supreme Court decided in favor of mining will be conducted in ground water the Colorado claimants (Andrus v. Shell oil, No. 78-1815). areas.

Land Exchanges As discussed later, of the approximately larly suitable for the oil shale situations. The 400,000 acres of privately owned land in Col- first is the “blocking-up” of scattered or odd- orado, about 170,000 acres contain at least ly shaped tracts by exchanging portions of 10 ft of oil shale yielding 25 gal/ton. The total them for adjacent Federal land, thereby cre- potential oil yield from these richer tracts is ating a tract geometry that could be devel- at least 80 billion bbl, which would support a oped economically. Superior Oil Co. proposed l-million-bbl/d industry for 240 years. How- such an exchange for its property in the ever, much of the privately held land is lo- northern Piceance basin. In this case, a cated on the fringes of the oil shale basins, stringer of Superior land that extended into and contains thinner, leaner deposits than the Federal holdings was to be exchanged for does the adjacent Federal land. Furthermore, a parcel along the southern edge of the main some of the private tracts are in small, non- body of the Superior property. EXXON Corp. contiguous parcels (mainly former home- has also proposed to exchange numerous steads and small mining claims) that could small tracts along streambeds in the Piceance not be economically developed. Private oil basin for about 10,000 acres of Federal land shale development could be encouraged if near the basin’s center. these lands were exchanged for more economically attractive Federal tracts. The second option would involve exchang- The exchanging of private mineral-bearing ing a large block of private land on the fringe land for Federal land is allowed under sec- of the oil shale deposits for a substantially tion 206 of the Federal Land Policy and Man- smaller block of Federal land in the richer, agement Act of 1976 (FLPMA). Exchanges thicker areas. The Federal tract would have may be consummated provided that they are to be much smaller, in general, because the in the public interest and that the properties deposits under much of the Federal land are involved are within 25 percent of equal value. at least 1,000 ft thick; deposits on private The difference may be made up in cash. tracts along the basin’s fringe are seldom There are two options that would be particu- more than 250 ft thick.

The Adequacy of Private Lands Most of the privately owned lands in the through the filing of mining claims for oil Piceance and Uinta basins were acquired shale and other minerals under the Mining —

242 ● An Assessment of Oil Shale Technologies

Law of 1872. The provisions of the law resources were created on the bed of an an- quired that the mineral be “located” by the cient lake by the deposition of silt and organic prospector; that is, he had to sample the debris carried into the lake by rivers and deposit and demonstrate, through assay, that streams. The lake had a bowl-shaped cross it contained the mineral of interest. In gener- section (hence, the term “basin”), and more al, the oil shales in Colorado and Utah are sedimentation occurred near its depositional deeply buried and therefore not visible from centers, which lie north of the geometric the surface. However, some deposits are visi- center of the basin—on Federal land. The ble where streams have eroded through the Federal deposits are therefore much thicker overburden. The early prospectors obtained and, as a consequence, more amenable to samples from these outcrops, assayed them, large-scale development. The private lands, filed claims for the outcrop and for the adja- on the fringe of the basin corresponding to cent land (which, it was inferred, also con- the shoreline of the ancient lake, are much tained the mineral), and eventually obtained thinner. patents for the claimed land from the Govern- ment. Most of the original mining claims were Second, because the level of water in the quite small, but over the years the individual lake varied over time as the climate changed, claims have been purchased by major energy the lakeshore advanced and receded. When companies and consolidated into much larger the water level was high, organic matter was blocks that could be suitable for commercial deposited over a broader area and was con- development. verted to oil shale before it could be decomposed by exposure to the air. When the water The locations of the larger privately owned level was low, more inorganic silt was de- patented or “fee” lands in the Piceance basin posited, and any organic debris that was laid are shown in figure 56. * Because the oil shale down near the shoreline decomposed when deposits were first detected along the Col- the shoreline receded. As a consequence, the orado River, most of the fee lands are found deposits on the basin’s fringe are much in the southern part of the basin. Because of leaner on the average than the deposits to the the location requirements of the 1872 Mining north, and they occasionally are intermixed Law, they are generally found along stream- with layers of rock containing essentially no beds. Not shown in the figure are the numer- organic matter, This complicated stratigra- ous tracts of a few hundred acres that follow phy reduces the average oil yield from depos- the streams in the central and northern parts its on private land, and makes them less suit- of the basin. These were primarily early able for commercial development. homesteads and grazing lands, but many of them have been acquired by the energy com- The net effect of these two conditions is in- panies. They are still used for farming and dicated in table 32 and illustrated in figure stock raising, which retains control of the 57. As shown, the privately owned lands in water rights. Colorado and Utah include about 340,000 acres of deposits at least 10 ft thick that The location of the private lands has sever- would yield at least 25 gal/ton of shale oil. al implications for oil shale development be- The total potential yield from these deposits cause, although they are extensive, they are is about 100 billion bbl. In contrast, the Fed- not so commercially attractive as the Federal eral lands have 1.2 million acres of equiva- lands to the north. There are three reasons lent deposits with a potential yield of 460 bil- why they are not so attractive. First, they are lion bbl. much thinner and contain lower concentrations of kerogen than do the deposits on Fed- The third factor is that private lands con- eral land. This is because the oil shale retain essentially no commercially attractive deposits of nahcolite and dawsonite—the so- *The term “fee’” is derived from the Middle English word dium minerals that are potential sources of ~ie~: an inheritable or heritable estate in land. aluminum, glass, and the chemicals used to Ch. 7–Resource Acquisition 243

Figure 56.— Privately Owned Tracts in the Piceance Basin

INTERNATIONAL NUCLEAR d MEEKER

MOBIL Y7EQUITY

ARCO EOUITY STANDARD OF & CALIFORNIA UNlON COLONY \

OCCIDENTAL # @ N Go

outline of the Green /?iver m formation

A Proposed oil shale project (4

SOURCE Map of the Ma/or 0// Shale Ho/dlrrgs-Colorado, Wyom/rtg Utah, Denver. Colo Cameron Engineers, Inc , January 1978 —

244 An Assessment of 0il Shale Technologies

Table 32.–Distribution of the Oil Shale Resources in Colorado and Utah

— Ownership Colorado Utah Total — Federal Private Federal Private Federal Private - Ouantity of land (1 ,000 acres)...... 1,420 400 3,780 1,100 5,200 1,600 Deposits at least 10 ft thick and yielding at least 25 gal/ton (1,000 acres)...... 600 170 600 170 1,200 340 Potential yield of shale 011 (billion bbl)...... 390 80 70 20 460 100

SOURCE Adapted from Prospec(s for 0(/ .Sha/e Oeve/oprnen(-Colorado, Urah, and Wyormng, Department of the Intertor 1968 pp A-1 and A-2 control air pollution from flue gases. As cant exception is the land owned by Superior shown in figure 58, the deposits of sodium Oil Co., which lies along the northern edge of minerals stop short of the northern edge of the sodium mineral resources. the major private holdings. The only signifi-

Present and Potential Projects on Private Land Colony Development Operation (a consorti- centives, and until regulatory uncertainties um of Tosco and Atlantic Richfield Co.) and are alleviated. 1 Union Oil Co. own some of the more commercially attractive private land. The two com- Union Oil Co. began developing retorting panies have been developing retorting tech- technologies in the 1950’s. It owns about nologies since the 1950’s and early 1960’s. In 30,000 acres of land in the southern Piceance the late 1960’s Colony proposed to build a Basin, 20,000 acres of which contain oil commercial-scale project on its property, shale. Union tested its “A” aboveground which would use underground mining and retort on this land between 1954 and 1958. aboveground processing in TOSCO II retorts. Since 1974, Union has been studying a project The project was delayed by economic uncer- that would use the Union “B” retort to ex- tainties, and then resurrected in the 1970’s tract 75,000 to 150,000 bbl/d of shale oil from after the Arab oil embargo. It was subse- the company’s resources. The plant is to be quently suspended when more detailed eco- developed with a modular stage in which a nomic studies indicated a much higher cost single “B” retort with a capacity of about for the project (and hence for its oil) than 9,000 bbl/d will be tested. This project, the previously anticipated. The retorting process Long Ridge Experimental Shale Oil project, is has been tested at the semiworks scale (about in suspension until economic conditions im- 1,000 ton/d), and is regarded by Colony as prove sufficiently to warrant investment. A being ready for commercial application. minimum requirement at present is a production tax credit of $3/bbl of shale oil pro- The Colony project would produce 46,000 duced. 2 Union has obtained all of the key en- bbl/d with six TOSCO II retorts, each proc- vironmental permits required for the modular essing about 10,000 ton/d of ore. Because the project. project would include a product pipeline across Federal land, an EIS was required. A third major oil project involving private This was completed by the Bureau of Land land is the Superior project, which would in- Management (BLM) in 1977. At present, Col- volve the simultaneous recovery of shale oil, ony has many of the major permits required soda ash, alumina, and nahcolite from the so- to initiate the project, but it will not proceed dium mineral deposits. As indicated previ- until the economic climate is improved by fur- ously, Superior has proposed to exchange a ther increases in oil prices or Government in- long, thin portion of its tract for a parcel of Ch 7–Resource Acquisition 245

Figure 57.—Thickness of the Oil Shale Deposits in the Piceance Basin That Yield at Least 25 gal/ton of Shale Oil r RANGELY MEEKER

RIFLE ■

, Private (Fee) lands

Federal 011 shale lease tracts

{

GRAND JUNCTION

SOURCE Cameron Engineers, Inc .

246 ● An Assessment of Oil Shale Technologies

Figure 58.— Location of the Sodium Mineral Deposits in the Piceance Basin

Is MEEKER

El Private (Fee) lands Federal 011 shale lease tracts m --- Extent of the nahcohte deposits ) ++ Extent of the dawsorute deposits 5

SOURCE B Welchman, Sa//fre Zone 0// Sha/e and the /rrtegrated In SIfu Process, Houston. Tex The Multi Mineral Corp , May 1979 p 17 Ch. 7–Resource Acquisition ● 247

Federal land. BLM has issued a draft EIS for technique is being developed, is the only one the exchange, and recently completed a pre- for which a commercial target—2,000 bbl/d liminary assessment of the value of the two —has been announced. Occidental Oil Shale tracts in question, as required by the equiv- is conducting experiments on its land in the alent-value provisions of FLPMA. Superior’s extreme southern Piceance basin. However, land was found to have a significantly lower the tests at the Logan Wash site are support- value than the Federal land to be acquired. ing the development of Federal lease tract BLM has tentatively denied the application. C-b. The Logan Wash site has no commercial Superior is preparing a response to the denial potential. Equity Oil Co. is developing another and BLM’s decision is open to review. If the TIS process on private land in Colorado, but exchange were approved, the project could no production target has been announced. produce about 11,500 bbl/d of shale oil, plus the other byproducts, from a single Superior If all of the presently active or suspended aboveground retort. The resources on the projects on non-Federal land proceeded to tract could support one additional retort of commercialization, the total production the same size. would be 280,000 to 350,000 bbl/d. However, this would require the following: Tosco is also developing the Sand Wash project on land leased from Utah. It is in its ● for Union: a production tax credit; early stages and is proceeding at a relatively ● for Colony (and probably for Sand slow pace. Under its leasing arrangements, Wash): incentives and alleviation of reg- Tosco is required to invest $8 million in tract ulatory uncertainties; development over an 8-year period. The sink- ● for Superior: a land exchange and posing of a mine shaft has begun and will be com- sibly incentives; and pleted in about 1982. This will be followed by ● for Geokinetics: the continued support an experimental mining phase lasting from 2 by the Department of Energy (DOE) of to 3 years.3 Thus, by 1985, Tosco could be the company’s experimental program. ready to build its retorting plant, which could ultimately have a capacity of 50,000 bbl/d. If There are other private tracts that have re- a modular demonstration phase is included, sources similar to those of Colony and Union. the plant could be completed by 1995. If pre- These include the tracts owned by Chevron commercial experiments are not conducted, (Standard Oil Co. of California), Getty Oil Co., as would be the case for Tosco’s Colony proj- Cities Service Corp., and others. However, no ect, the plant could be completed as early as projects have been announced for any of 1990. However, this would require accelerat- these lands. In part, this reflects the techno- ing the experimental, design, and construc- logical positions of the other landowners— tion phases, which Tosco may not be willing they do not own advanced retorting technolo- to do in the absence of a highly favorable gies. They may plan to license the processes economic outlook. Tosco has not stated a posi- of the other companies, once these have been tion in regard to the types of encouragement demonstrated, or to develop their own proc- that would be required, but as a member of esses once the economic viability of the oil the Colony Development Operation, Tosco has shale industry appears assured. It appears suggested a need for financial incentives and that economic conditions would have to im- regulatory modifications, prove significantly in order to motivate these potential developers to complete their proj- Other private firms are also engaged in ects before, say, 1990. A much stronger set of R&D activities on their tracts and on land incentives may be required than would be leased from Utah. These projects are dis- needed by Union or Colony, who already have cussed in detail in chapter 5. The Geokinetics both good technological and resource posi- project, in which a true in situ (TIS) retorting tions, —

248 An Assessment of Oil Shale Technologies

Present and Potential Projects on Federal Land As discussed in volume II and mentioned could be producing at least 100,000 bbl/d by earlier here, only two projects are actively 1990. being conducted as part of the Prototype Leasing Program. Rio Blanco Oil Shale Co. is Multi Mineral Corp. has proposed to use a developing tract C-a using MIS methods. A mine shaft on Federal land in the northern Pi- demonstration of the Lurgi-Ruhrgas above- ceance basin to develop an MIS process to re- -ground retort may be included. Tract C-b is cover shale oil, alumina, and nahcolite from being developed as the Cathedral Bluffs deeply buried deposits. The shaft was drilled Shale Oil project. Occidental’s MIS technol- in 1978 by the U.S. Bureau of Mines to devel- ogy is being used, and no plans have been an- op mining techniques for sodium minerals nounced for a concurrent demonstration of and oil shale in the saline zone. * The proposal AGR technologies. The White River project on involves a three-phase project that could lead tracts U-a and U-b, which were unified for to a 50,000-bbl/d operation. joint development, is presently in suspension If all of the presently active and proposed pending resolution of ownership. projects involving Federal land were com- Paraho Development is also engaged in a pleted, the total production could exceed project involving Federal land at the DOE 300,000 bbl/d, plus any additional production research facility in Anvil Points, Colo. Anvil from NOSR 1. However, only 57,000 bbl/d of Points was the site of Paraho’s retort develop- this production is assured, because only ment program. Paraho is attempting to ex- Cathedral Bluffs is committed to commercialization. Rio Blanco is committed only to test- tend the terms of its lease to include a modular demonstration program and to obtain ing its development techniques at the precom- funding for the project. The outlook is uncer- mercial level—approximately 2,000 bbl/d. tain, because an EIS is required and none has The decision to proceed to commercial levels yet been issued, despite four attempts by of production will depend on the technical DOE. Paraho’s management is also pursuing feasibility of the MIS and Lurgi-Ruhrgas methods and on the existence of a favorable a production tax credit to improve the economic outlook for shale oil. economic and regulatory climate. Therefore, achieving 300,000 bbl/d from these opera- As mentioned earlier, EXXON Corp. has tions is likely to require the following: also proposed to exchange its scattered hold- ● ings for a single tract of Federal land in Col- for Cathedral Bluffs: continued techni- orado. The future of this proposal is uncer- cal progress and continuation of a favorable economic outlook; tain. If Superior’s land-exchange experience ● is regarded as typical, preparation and re- for Rio Blanco: technical progress and view of the EXXON proposal could take as favorable project economics, perhaps in- long as 8 years. Four years is more likely. cluding Federal financial incentives; ● for Paraho: extension of the terms of the DOE and the Department of Defense are Anvil Points lease and provision of a pro- preparing a management plan for developing duction tax credit; Naval Oil Shale Reserve No. 1 (NOSR 1), ● for White River: favorable resolution of which is contiguous to the Anvil Points site. the ownership dispute and possibly Fed- This project is in the early stages, and the eral incentives (Standard Oil Co. of Ohio potential production cannot be accurately es- (SOHIO) is a participant in the White timated. However, if all of the preliminary exploration, design work, and permitting can be *The Multi Mineral technology is discussed in ch. 5. The ge- completed by 1986, and if plant construction ology and stratigraphy of the oil shale basins are discussed in were expedited, DOE believes that NOSR 1 ch. 4. Ch. 7–Resource Acquisition 249

River project. SOHIO is also involved in ently banned by Federal statutes, including the Paraho operation.); and the acreage limitation of the Mineral Leasing ● for EXXON: approval of the proposed Act and the provisions of FLPMA, which land exchange. state: The potential production from tract C-a could be expanded by 75,000 bbl/d if the les- Nothing in this Act, or in any amendment made by this Act, shall be constructed as sees returned to their original open pit mining permitting any person to place, or allow to be plan. However, to allow maximum recovery placed, spent shale oil, overburden, or by- of the oil shale resource, lands outside of the products from the recovery of other mineral tract boundaries would have to be used for with oil shale, on any Federal land other than waste disposal and the siting of the process- Federal land which has been leased for the ing facilities. Such off tract land use is pres- recovery of oil shale . . .

Is More Federal Land Needed? As discussed in chapter 6, shale oil ap- lease tracts and also initiate projects on pears to be economically competitive, based private lands. on the present and projected prices of foreign crude oil and some premium-quality domestic The need for additional Federal land will crudes. However, technical, economic, and depend strongly on the size of the industry regulatory risks are inhibiting potential de- and the pace of its creation. It will also be af- velopers from making large capital invest- fected by the other Federal oil shale policies, ment commitments to shale development. especially those involving financial incen- These uncertainties are aggravated by some tives. This is shown in table 33, which indi- of the characteristics of the private lands cates how the industry’s capacity in 1990 which, in general, are not so favorable as might be affected by different Federal ac- those of adjacent Federal lands. Further- tions. As shown for case 1, about 60,000 bbl/d more, the privately owned lands contain es- could be achieved with no additional actions, sentially no commercially attractive deposits assuming that the Cathedral Bluffs project is of sodium minerals. Assuming that these min- completed and that Geokinetics reaches its erals could be extracted economically, they production target. If economic conditions en- could be sold as byproducts to enhance the courage Rio Blanco to continue and Sand economic feasibility of a project. Whether Wash to accelerate, production could reach more Federal land must be provided depends 185,000 bbl/d by 1990. If incentives are added (case 2) that assure completion of these two projects, that encourage the Colony how much production is desired; and Union projects to resume, and that also how rapidly the industry is to be cre- initiate a new project on private land, produc- ated; tion would reach 360,000 bbl/d. This could be whether production of sodium minerals, expanded in case 3 to nearly 400,000 bbl/d if or testing of the “multimineral” technol- the Superior land exchange is consummated ogies used to extract them, is desired; (or a lease issued for the desired parcel) and how much technical, economic, and envi- test sites are provided for the Paraho and ronmental information is desired to as- Multi Mineral processes. All three of these sist policymaking and the setting of envi- projects would involve providing access to ad- ronmental regulations; and ditional Federal land. whether financial incentives are provided that will encourage the continua- If the ownership conflicts surrounding the tion of present projects on the Federal Utah lease tracts are resolved in a manner —

250 ● An Assessment of Oil Shale Technologies

Table 33.–Estimated Shale Oil Production by 1990 in Response to Various Federal Actions

Case Federal action 1 2 3 4 5 6 7 8 None...... x Incentives for first-generation developers . . . . x x x x x Test sites for modular retortsb ...... x x x x x x Resolution of ownership issues on Utah tractsc. x x x x x Offtract land used ...... x x x x Proposed land exchanges...... x x x Incentives for second-generation developers (or improved economics) ...... x x Naval Oil Shale Reserves or expanded Prototype Program or permanent leasing. . . . x Production, bbl/d ...... 60,000- 360,000 390,000 490,000 560,000 620,000 850,000 1,000,000 185,000 f aASSumeS the entry of one as-yet unannounced developer blncludo~ the proposed superior 011 land exchange and a Ieasmg of Anwl POIIIIS by parafio DeVe@rrrerrl CReSurnptlOrl of the tract U-a/(J-b project may also depend on the availablhty of Incentives and On other lmProvemenfs In Protect economics aFor waste disposal from the o~n plt mme that was Ongmally proposed for traCt C-a elncludes the proposed Supertor 011 and EXXON land mcharws fonly 59,000 bbllfj IS llrmly Cwnrnmed SOURCE Off Ice of Technology Assessment favoring the lessees, and if appropriate in- development by leasing additional tracts or centives are provided, the White River proj- by developing NOSR 1 (case 8). The industry’s ect could resume. This would add 100,000 capacity in 1990 could then reach 1 million bbl/d to the industry’s capacity. Production bbl/d. could reach 560,000 bbl/d if Rio Blanco were given permission to use offtract lands and returned to its original open pit mining plan, In summary, reaching 200,000 bbl/d by as assumed for case 5. If the EXXON land ex- 1990 may not require the release of substan- change were completed (case 6), production tial tracts of Federal land, if the presently ac- would be increased by 60,000 bbl/d. As tive projects are technically successful and if shown for case 7, production might be in- the economic outlook remains favorable. Only creased to 850,000 bbl/d by providing sub- 60,000 bbl/d of this capacity is assured. sidies that were sufficiently attractive to en- About 400,000 bbl/d might be achieved if ef- courage the participation of the “second gen- fective incentives were provided and test eration” of developers—those who are not as sites allocated for retorting demonstrations. technically advanced as Colony and Union, or Achieving 1 million bbl/d by 1990 might re- who lack resources of equivalent quality. The quire subsidies, land exchanges, permission total additional capacity indicated corre- to use offtract land for waste disposal and sponds to about five additional major projects facility siting, and the leasing of additional on private land. The Government could also tracts or the development of the Naval Oil become more directly involved in oil shale Shale Reserves.

● To amend the Mineral Leasing Act of proving economic feasibility. It might also 1920.—The Act could be amended to in- allow the inclusion of a suitable waste crease the acreage limitations, or to set the disposal site within a tract’s boundaries size of the tract according to the recover- while still providing adequate oil shale able resources it contained. This might al- resources for sustained, large-scale opera- low more economies of scale, thereby im- tions, thus avoiding the need for separate Ch 7–Resource Acquisition . 251

offtract disposal authorization. The num- on the existing tracts. Leasing more than ber of leases per person or firm could also two more tracts, or leasing for the purpose be increased. This might provide additional of expanding near-term shale oil produc- encouragement to firms that do not own oil tion, would encounter political opposition shale lands because it would allow them to by the critics of rapid oil shale develop- acquire experience on one lease tract and ment. Leasing could begin sooner than un- then apply it to another while the first was der a new leasing program, if some of the still operating. A disadvantage would be potential lease tracts previously nominated that the number of firms participating in were offered. A supplemental EIS would be the leasing program could be reduced if a required. Construction on the tracts could few firms acquired all of the leases. One probably not begin until about 1985 and option would be to increase the number to production no sooner than 1990. Consider- one lease per State. This might encourage ation might be given to leasing a tract for a firm to develop a process in the richer de- multimineral operations, a process that is posits in Colorado and then apply it to the not being evaluated in any project at pres- poorer quality resources in Utah or Wyo- ent. (One of the primary goals of the Proto- ming. type Program is to obtain information about a variety of technologies. ) ● To amend FLPMA.—FLPMA could be amended to allow including conditions To initiate a new, permanent leasing pro- (such as environmental stipulations and gram.—An advantage would be that more diligence requirements) in any oil shale production could be achieved than is possi- land exchange agreement. This would im- ble under the present Prototype Program. prove the Government’s control over the A full EIS and a new set of leasing regula- exchanged parcel. It might also discourage tions would be needed. Without the infor- private participation. mation to be acquired by completing the present Prototype Program projects, it ● To allow offsite land use for lease —Legislation could be provided to might be difficult to prepare an accurate tracts. environmental assessment and to structure allow a lessee to use land outside of the comprehensive leasing regulations. Pro- boundaries of a lease tract for facility siting and waste disposal. This might permit duction could probably not begin until after larger, more economical operations (in- 1990. Abandonment of the Prototype Pro- gram would be implied, which might engen- cluding perhaps an open pit mine) and would maximize resource recovery on the der political opposition. tract. However, subsequent development To expedite land exchanges.—The review of the offtract areas would be inhibited. and approval procedures could be expe- (DOI estimated that Rio Blanco’s offtract dited by, for example, setting up a task disposal plan would reduce resource re- force within DOI specifically for oil shale covery from the disposal area by about 5 proposals. percent.) Government development.—The Govern- ● To lease additional tracts under the Proto- ment could develop the Naval Oil Shale Re- type Program.—There is no statutory lim- serves. Unless this were done by leasing to itation on the number of tracts that could private developers, it would involve compe- be leased under the Prototype Program. tition with private industry, and would en- However, DOI originally committed to leas- counter political opposition. It would also ing no more than six. Because two of the be very costly because the public would original tracts were not leased, offering have to pay the full cost of the facilities, two new ones might be justified, provided and it might discourage independent ex- that the technologies to be tested were dif- periments by private firms. Information ferent from the processes being developed useful in developing policies and regula- 252 ● An Assessment of Oi/ Shale Technologies

tions for the industry would be obtained. vestment decisions. Some of the informa- However, because the Government’s expe- tion is being acquired in the present Proto- rience with financing and operating a facil- type Program. It could also be obtained in ity would be substantially different from additional leasing programs or through li- that of private developers, the information censing arrangements with the owners of might not be useful in evaluating private in- the technologies.

Chapter 7 References

IHO F. Coffer and A. Christianson, eds., EPA Pro- ‘Ibid., at p. 27. gram Conference Report: Oil Shale, EPA-600/ 31bid. 0-79-025, July 1979, p. 90 CHAPTER 8 Environmental Considerations

Page Page Introduction ...... 255 Policy Options for Water Quality Management 314 Summary of Findings ...... 256 Safety and Health...... 315 Air Quality ...... 256 Introduction ...... 315 Water Quality...... 256 Safety and Health Hazards ...... 316 Occupational Health and Safety ...... 257 Summary of Hazards andTheir Severity. ....322 Land Reclamation...... 258 Federal Laws, Standards, and Regulations. ..324 Permitting...... 259 Control and Mitigation Methods ...... 325 Summary of Issues and R&D Needs ...... 326 Air Quality ...... + ...259 Current R&D Programs...... 326 Introduction ...... 259 Policy Considerations...... 327 Pollutant Generation ...... 259 Air Quality Laws, Standards, and Regulations 263 Land Reclamation...... 328 Air Pollution Control Technologies ...... 269 Introduction ...... 328 Pollutant Emissions...... 278 Reasons for Reclamation ...... 329 Dispersion Modeling...... 279 Regulations Governing Land Reclamation. ...329 A Summary of Issues and Policy Options. ....288 Reclamation Approaches...... 330 The Physical and Chemical Characteristics Water Quality...... 291 of Processed Shale ...... 332 Introduction ...... 29l Use of Topsoil as a Spent Shale Cover ...... 335 Pollution Generation...... 292 Species Selection and Plant Materials ...... 336 Summary of Pollutants Produced by Major Review of Selected Research to Date...... 339 Process Types...... 294 Summary of Issues andR&D Needs ...... 341 Effects of Potential Pollutants on Water Policy Options for the Reclamation of Quality and Use...... 295 Processed Oil Shales...... 342 Water Quality in the Oil Shale Region...... 296 Water Quality Regulations...... 297 Permitting...... 343 Technologies for Control of Oil Shale Water Introduction ...... 343 Pollution ...... 304 Perceptions of the Permitting Procedure. ....344 Ultimate Disposition of Waste Water ...... 308 Status of Permits Obtained by Oil Shale

Monitoring Water Quality ...... 309 Developers ...... 0.,.. 345 Information Needs and R&D Programs ...... 311 The Length of the Permitting Procedure .,,.. 346 Findings on Water Quality Aspects of Oil Disputes Encountered in the Permitting Shale Development...... 314 Procedure ...... 346 Page Page Unresolved Issues...... 347 54. Effluent Limitations for Petroleum Attempts at Regulatory Simplification...... 348 Refineries Using BestPracticable Policy Options...... ,.,....,.349 Pollution Control Technology...... 299 Chapter8 References...... 352 55. Effluent Limitations for Best Available Technology Achievable for Petroleum List of Tables Refinery Facilities ...... 299 56 New Source Performance Standards for TableNo, Page Petroleum Refineries ...... 300 34. Pollutants Generated bythe Colony 57 Colorado Water Quality Standards for Development Project ...... 262 Stream Classification B2 ...... 301 58. Utah Water Qualitv Standards for 350 PollutantsGenerated by the Rio Blanco Project on TractC-a...... 263 Stream Classification CW ...... 301 36. Pollutants Generatedbythe Occidental 59 Proposed Water Quality Criteria for Operation on TractC-b ...... 263 Designated Uses...... 302 37. The Federal and State Ambient Air 60 Primary Drinking WaterStandards . . . . 303 Quality Standards and Prevention of 61 Proposed Secondary Drinking Water Significant Deterioration Standards Regulations. ,.. .. ~.. .., ..~...... 303 That Influence Oil Shale Development . . 266 62. The Types of Contaminants in Oil Shale 38. National Standards for Prevention of Wastewater Streams and Some Potential Significant Deterioration of Ambient Processes for RemovingThem ...... 305 Air Quality, ...... 267 63. Relative Rankings of the Water 39. National New Source Performance Treatment Methods ...... 306 Standards for Several Types of Facilities 269 64. Estimated Costs of Water Pollution 40. EPA Standards for Best Available Air Control in Oil ShalePlants...... 306 PollutionControl Technologies for Oil 65, Sampling Schedule Summary for Surface Shale Facilities...... 269 and Ground Water Monitoring Program 41. Technological Readinessof Air Pollution at Tract C-b During Development Phase. 312 Control Technologies ...... 276 66. Animal Studies on the Carcinogenicity of 42. Costs of AirPollutionControl ...... 277 Oil Shale and ShaleOil ...... 320 43. Pollutants Emitted by theColony 67. Benzo(a)pyrene Content of 0il Shale and Development Project ...... 278 Its Products and of Other Energy 44. Pollutants Emitted by theRio Blanco Materials ...... 320 Project on Tract C-a...... 278 68. The Chemical and Physical Properties of 45, Pollutants Emitted by the Occidental Processed Shales ...... 332 Operation on TractC-b ...... 279 69. Estimates of Reclamation Needs Under 46. ASummary of Emission Rates From Five Various Levels of Shale Oil Production. , 338 Proposed Oil Shale Projects...... 279 70. Status of the Environmental Permits for 47. A Comparison of Atmospheric Emissions Five Oil Shale Projects, ...... 345 Used in Modeling Studies...... 282 48. Modeling Results for Federal Oil Shale Lease TractC-a ...... 284 49. Models Used in SupportofPSD Applications for Oil Shale Projects . . . . . 285 List of Figures 50. Areas of Inadequate Information and Suggested R&D Responses ...... 288 59. Designated Class I Areas in Oil Shale Page 51. Generation Rates for Principal Water Region ...... 268 Pollutants for Production of 50,000 bbl/d 60, Computation Modules in Atmospheric of Shale Oil Syncrude...... , . . . . . 294 Dispersion Models ...... 281 52. Quality of Some SurfaceStreams in the 61. An Aboveground Spent Shale Disposal Oil Shale Region ...... 297 Area ...... 307 53. Quality of GroundWaterAquifers in the 62. Summary of Occupational Hazards Piceance Basin...... 297 Associated With Oil ShaleDevelopment. 323 CHAPTER 8 Environmental Considerations

Introduction

The region where oil shale development emissions and by the leaching of soluble con- will take place is, at present, relatively un- stituents into surface and ground water sys- disturbed. The construction and operation of tems. Water quality could thus be degraded plants would emit pollutants and produce by altered nutrient loading, changes in dis- large amounts of solid waste for disposal. As solved oxygen, and increased sediment and a consequence, air, water, and soil could be salinity. degraded and the topography of the land could be altered. The severity of these im- For these reasons, each potential environ- pacts will depend on the scale of the opera- mental effect along with its control technol- tions and the kinds of processing technologies ogy should be examined with respect to its net used, as well as the control strategies that impact on the total environmental system. To must be adopted to comply with environmen- do this requires full understanding of the tal regulations. separate impacts on air, water, and land, the interaction between the individual parts of Control strategies have been proposed for the ecosystem, and the efficacy of the control purifying water and airborne emissions strategies. Such an analysis needs a complete streams, for revegetation, for protecting wild- and accurate data base which is as yet un- life, and for other specific areas of envi- available because no commercial oil shale ronmental concern. However, control tech- plants have been built. OTA’s environmental nologies that are applied to one area could analysis, therefore, is limited to examining adversely affect another area. For example, the effects that an oil shale industry would to control air pollution, airborne streams are have on the separate areas of air, water, scrubbed to capture dust and gaseous con- land, and occupational health and safety. In taminants. This produces sludges and waste- order to provide a basis for policy analysis, water that have to be disposed of along with the effects are quantified wherever possible other wastes. All of these have the potential and related to a production of 50,000 bbl/d. to adversely affect the land and the water. For each of the areas examined: Airborne pollutants, such as trace metals, impacts of oil shale operations are de- might enter surface streams and ground scribed; water in fugitive dust and or rainfall and applicable laws and regulations are could alter the chemical and biological bal- summarized, and their significance to oil ances of the water systems. Plant and animal shale analyzed; life as well as human health could be harmed control strategies proposed for compli- both by an increase in water contamination ance with the laws and regulations are and by the entry of the contaminants into the described and evaluated; and food chain. Similarly, without adequate con- policies that could be focused on key is- trols, the piles of solid waste could contami- sues and uncertainties are identified nate the air and water through fugitive dust and discussed.

255 256 ● An Assessment of Oi/ Shale Technologies

Summary of Findings

Air Quality ● The costs of controlling air pollution will be particularly sensitive to the strictness of the environ- Because of the oil shale region’s rural character, mental regulations and to the design characteris- its air is relatively clean and unpolluted. Occasional- tics and size of each project. Preliminary estimates ly, however, high concentrations of hydrocarbons indicate that air pollution control could cost from (possibly from vegetation) and particulate from $0.91 to $1.16/bbl of syncrude produced (rough- windblown dust occur. The development of a large oil ly 3 to 5 percent of the selling price of the oil). shale industry (or any industrial or municipal growth) will degrade the air’s visibility and quality. Even if ● the best available control technologies are used and The only means for predicting the long-range im- compliance is maintained with the provisions of the pacts of oil shale emissions on ambient air quality Clean Air Act, its amendments, and the applicable in the oil shale area and in neighboring regions are State laws, degradation will occur. It will take place mathematical dispersion models, which are the not only near the oil shale facilities but also in nearby Environmental Protection Agency’s (EPA) tool for pristine areas (e.g., national parks, wilderness enforcing the provisions of the Clean Air Act. Mod- areas). Some places may be affected more than eling of oil shale facilities presents a number of others from local concentrations of pollutants caused problems because of the topography and meteorol- by thermal inversions. ogy of the region, the chemistry of the emissions, and the unknown quantities of emissions expected Findings of the analysis include: from commercial-size facilities. In addition, dis- ● Oil shale mining and processing will produce at- persion models developed to date have been pri- mospheric emissions including those pollutants marily for flat terrain. Thus, their predictions con- for which National Ambient Air Quality Standards tain significant inaccuracies. More R&D needs to (NAAQS) have been established (i.e., sulfur diox- be undertaken in this area. ide, particulate, carbon monoxide, ozone, lead, and nitrogen oxides); as well as various other cur- ● rently unregulated pollutants (such as silica, Even with the use of BACT, the industry’s capacity sulfur compounds, metals, trace organics, and will be limited by the air quality standards govern- trace elements). ing PSD. A preliminary modeling study by EPA has indicated that an industry of up to 400,000 bbl/d ● Under the Clean Air Act, oil shale development will in the Piceance basin could probably comply with have to comply with NAAQS and State air quality the PSD standards for Flat Tops (a nearby Class I standards; maintain air quality, especially visibili- area) if the plant sites were dispersed. Additional ty, in adjacent Class I areas (e.g., national parks); capacity could be installed in the Uinta basin, comply with prevention of significant deterioration which is at least 95 miles from Flat Tops, A 1-mil- (PSD) increments (these specify the maximum in- lion-bbl/d industry could probably not be accom- creases in the concentrations of sulfur dioxide and modated because at least half of its capacity particulate that can occur in any region); comply (500,000 bbl/d) would be located in the Piceance with New Source Performance Standards (NSPS); basin. Policy options to address this limitation in- and apply the best available control technology clude the application of more stringent emission (BACT). standards, changes in PSD increment allocation procedures, and amending the Clean Air Act. ● A wide variety of control technologies could be applied to the emissions streams from oil shale processes. They are fairly well developed and have Water Quality been successfully used in similar industries. They should be adaptable to the first generation of oil Water quality is a major concern in the oil shale re- shale plants. However, full evaluation will not be gion, especially in regard to the salinity and sediment possible until they have been tested in commer- levels in the Colorado River system. The potential for cial-scale oil shale plants for sustained periods. pollution from oil shale development could come from Ch. 8–Environmental Considerations ● 257

point sources such as cooling system discharges; ● Although control of major water pollutants from from nonpoint sources such as runoff and leaching of point sources is not expected to be a problem, less aboveground waste disposal areas and ground water is known about the control of trace metals and tox- leaching of in situ retorts; and from accidental dis- ic organic substances. Research is needed to as- charges such as spills from trucks, leaks in pipe- sess their potential hazards and to develop meth- lines, or the failure of containment structures, Un- ods for their management. Other laboratory-scale less these pollution sources are properly controlled, and pilot-plant R&D should be focused on charac- the lowered quality of surface and ground water terizing the waste streams, on determining the resources could adversely affect both aquatic biota suitability of conventional control technologies, and water for irrigation, recreation, and drinking. and on assessing the fates of pollutants in the water system. Extensive work is already under- Specific findings include the following: way; its continuation is essential to protecting ● Surface discharge from point sources is regulated water quality, both during the operation of a plant under the Clean Water Act, and ground water rein- and after site abandonment. fection standards are being promulgated under the Safe Drinking Water Act. Solid waste disposal Occupational Health and Safety methods may be subject to the Toxic Substances Control Act and the Resource Conservation and The oil shale worker will be exposed to occupa- Recovery Act. The general regulatory framework is tional safety and health hazards. Many of these– therefore in place, although no technology-based such as rockfalls, explosions and fires, dust, noise, effluent standards have been promulgated for the and contact with organic feedstocks and refined industry under the Clean Water Act. Nonpoint products–will be similar to those associated with sources present regulatory and technological diffi- hard-rock mining, mineral processing, and the refin- culties, and at present are subject to less stringent ing of conventional petroleum. However, the workers controls. might be exposed to unique hazards due to the phys- ● Developers are currently planning for zero dis- ical and chemical characteristics of the shale and its charge to surface streams and to reinject only ex- derivatives, the types of development technologies to cess mine water. This eliminates point discharge be employed, and the scale of the operations. Poten- problems because most wastewater will be treated tial risks include safety hazards that might result in for re-use within the facility, and untreatable disabling or fatal accidents, and health hazards wastes will be sent to spent shale piles. The costs stemming from high noise levels, contact with irritant of this strategy are low to moderate, and develop- and asphyxiant gases and liquids, contact with likely ment should not be impeded by existing regula- carcinogens and mutagens, and the inhalation of fi- tions if it is used. brogenic dust. ● A variety of treatment devices are available for the Specific findings include: above strategy, and many of them should be well- ● Only a few fatalities have occurred during the min- -suited to oil shale processes. However, uncertain- ing of over 2 million tons of shale and the produc- ties exist regarding whether conventional methods tion of over 500,000 bbl of shale oil. The accident would be able to treat wastewaters to discharge rate has been one-fifth that for all mining, and standards because they have not been tested with much lower than that for coal mining. However, actual oil shale wastes under conditions that ap- this record was achieved in experimental mines proximate commercial production. There are also a that employed, for the most part, experienced number of uncertainties regarding the control of miners. Whether safety risks will increase or de- nonpoint pollution sources. For example, no tech- crease as mining activities are expanded cannot nique has been demonstrated for managing be predicted. ground water leaching of in situ retorts, nor has the efficacy of methods for protecting surface dis- ● Although the carcinogenicity of oil shale dusts and posal piles from leaching been proven. It is not crude shale oil has been demonstrated by some in- known to what extent leaching will occur, but if it vestigators, the conflicting results of other studies did, it would degrade the region’s water quality. combined with an overall lack of information pre- 258 ● An Assessment of Oil Shale Technologies

elude a determination of the severity of the risk. Specific findings include:

The incidence of diseases in other industries indi- ● cates that exposure to these materials could be Several approaches can be used to reduce the hazardous. deleterious effects associated with the disposal of spent oil shale. These include reducing surface ● The large variety of substances that will be en- wastes by using in situ processing or returning countered in retorting may present as yet unde- wastes to mined out areas; the chemical, physical, tected health hazards. Of special concern is the or vegetative stabilization of processed shale; and possibility of carcinogens in shale oil and its de- combinations of the above. rivatives, Possible synergistic effects from the products of modified in situ (MIS) operations ● Research has shown that vegetation can be estab- (which combine mining with retorting) could in- lished directly on processed oil shales. However, crease the level of risk. intensive management is required, including the ● Shale oil refining poses no special hazards since leaching of soluble salts, the addition of nitrogen most of its problems will be similar to those experi- and phosphorus fertilizers, and supplemental wa- enced in conventional petroleum refining. tering during establishment. Revegetating spent shale covered with at least 1 ft of soil is less sus- ● Health and safety hazards will be reduced by ceptible to erosion and does not require as much using pollution control technologies for air and supplemental water and fertilizer. Adapted plant water pollutants and by requiring specific indus- species are required for either option, trial hygiene practices. These are required by law and are expected to be implemented by oil shale ● The long-term stability and character of the vege- developers. However, it is essential that R&D on tation is unknown, but research on small plots the nature and severity of health effects keep pace suggests that short-term stability of a few decades with the development of the industry. Such infor- is likely if sufficient topsoil is added. mation will be useful in identifying and mitigating long-term effects on workers and the public. ● Reclamation plans will have to be site specific since environmental conditions vary from site to Land Reclamation site, Proper management will be required in all instances, if only to maintain plant communities in An industry will require land for access to sites, surrounding areas. H is even more important in for the facilities, for mining, for retorting, for oil the reclaimed areas. upgrading, and for waste disposal. The extent to which development will affect the land on and near a ● Shortages of adapted plants and associated sup- given tract will be determined by the location of the port materials such as mulches probably would tract; the scale, type, and combination of processing occur if a large (ea. 1 million bbl/d) industry is es- technologies used; and the duration of the opera- tablished. The problem is compounded by the in- tions. The facilities must comply with the laws and creasing demands from other mining operations regulations that govern land reclamation and waste such as coal and other minerals. disposal. Nevertheless, there will still be effects on land conditions (through altered topography) and ● The Surface Mining Control and Reclamation Act wildlife (through changes in forage plants and habi- provides for the kind of comprehensive planning tats). In addition, unless appropriate disposal and and decisionmaking needed to manage the land reclamation methods are developed and applied, the disturbed by coal development. New reclamation large quantities of solid wastes that will need to be standards that are applied to oil shale should pro- handled could pollute the air with fugitive dust and vide for postmining land uses that are ecologically the water with runoff and Ieachates from storage and economically feasible and consistent with piles and waste disposal areas. public goals. Ch. 8–Environmental Considerations 259

Permitting visor of the U.S. Geological Survey (USGS). Once the requirements for an EIS and DDP are satisfied, During the past 10 years an increasingly complex obtaining all of the needed permits can take more system of permits has been developed to assist the than 2 years. The project would not necessarily be Federal, State, and local governments in protecting delayed by the full length of the permitting sched- human health and welfare and the environment. Per- ule, because other predevelopment activities such mits are the enforcement tool established by Con- as engineering design, contracting, and equip- gress and the States to determine whether a pro- ment procurement could proceed in parallel, if the spective facility is able to meet specific requirements developer were willing to accept the risk that some under the law. of the permits might not be obtainable.

Operation of an oil shale facility requires more than ● The principal problems encountered to date with 100 permits from Federal, State, and local agencies. the permitting process are related to the needs of Included are those for environmental maintenance, the regulatory agencies for technical information for protection of worker health and safety, and for the and to differing interpretations of environmental construction and operation of any industrial facility law. Future problems may be more critical than (e.g., building code permits, temporary permits for those encountered thus far. Several relevant regu- the use of trailers, sewage disposal permits). Of lations are still pending that may increase costs or these 100 permits, about 10 major environmental force changes in the design of process facilities or ones require substantial commitments of time and re- control technologies. They may also add to the sources. control requirements. Another problem that might Findings of the analysis include: emerge is the ability of regulatory agencies to handle the increasing load of permit applications and ● The time required for preparing and processing a enforcement duties. permit application depends on the type of action being reviewed, the review procedures stipulated ● Several attempts are being made to simplify regu- under the law, the criteria used by agencies to Iatory procedures. These include the streamlining judge the application, and the amount of public of permitting procedures within specific agencies; participation and controversy that is brought to the design and testing of a permit review pro- bear. If Federal land is involved, then an environ- cedure for major industrial facilities that will coor- mental impact statement (EIS) will most likely be dinate the reviews by Federal, State, and local required. The EIS process may take at least 9 regulators; and the proposed Energy Mobilization months after the developer applies for permission Board to expedite agency decisionmaking and re- to proceed with the project. In the case of the cur- duce the impacts of new regulatory requirements. rent Federal lease tracts, additional time was Colorado has recently announced a joint review needed to prepare detailed development plans process designed to accomplish the first two of (DDP) for approval by the Area Oil Shale Super- these ends.

Air Quality Introduction ● Rates are estimated for the generation of air contaminants. The maintenance of air quality is necessary for the development of an environmen- ● The applicable Federal and State air tally acceptable oil shale industry. In this sec- quality regulations and standards are tion: described. The types of atmospheric contaminants ● The effects of these regulations and produced by oil shale unit operations are standards on a developing oil shale in- characterized. dustry are analyzed. 260 ● An Assessment of Oil Shale Technologies

● The air pollution control technologies minesite that produce fugitive dust (particu- that may be applied to untreated emis- late matter discharged to the atmosphere in sion streams are described and evalu- an unconfined flow stream). ated. The net rates at which pollutants will be emitted in treated streams are es- Atmospheric emissions are expected to be timated. much larger in open pit than in room-and- pillar mining because of the significantly ● Modeling procedures that may be used to predict and monitor compliance with larger quantities of solids that must be han- air quality regulations are discussed. dled on the surface. The mine dust problem will be further aggravated by road dust from ● Potential problems that commercial- scale operations may encounter in meet- transportation of overburden, and wind- ing standards are identified. blown dust from all operations. ● Key findings are summarized. Storage, transport, and crushing of oil ● Policy options are discussed. shale result in the emission of particulate,

CO, NOX, SO2, and HC from fuel in diesel en- Pollutant Generation gines, and particulate and silica from fugitive dust. Dust is the chief pollutant. The Oil shale mining and processing will pro- amount generated depends on the grade of duce atmospheric emissions including those ore, the extent to which its size must be re- pollutants for which NAAQS have been es- duced for retorting, the number of transfer

tablished: sulfur dioxide (SO2), particulate, points in the transportation system, and the carbon monoxide (CO), ozone (0 S), lead, and level and effectiveness of control strategies

nitrogen oxides (NOX); as well as various used. other currently unregulated pollutants, such Retorting technologies generate process as silica, sulfur compounds, metals, carbon heat by the combustion of fossil fuels, which dioxide (CO ), ammonia (NH ), trace organics, 2 3 produces a number of atmospheric emissions. and trace elements. The following discussion The amount of SO2 emitted depends on the examines the types of pollutants generated by sulfur content of the fuels used in the plant each unit operation. Where data are avail- and the extent to which sulfur-containing able, the rates at which these contaminants product gases are treated. The volume and will be produced by different oil shale facil- concentration of hydrogen sulfide (H2S), car- ities are estimated. bonyl sulfide (COS), and carbon disulfide

(CS2) in the offgas streams from retorts de- Unit Operations and Pollutants pend on the type of retorting technology. COS Mining can be carried out either using un- has been detected in the offgases from Law- derground (room and pillar) or surface (open rence Livermore Laboratory’s simulated MIS retorts and trace quantities of COS and CS pit) methods. The sequential steps in room- 2 and-pillar mining are drilling, blasting, muck- have been reported in the offgases from the ing (collection of the blasted shale), primary Occidental MIS process under certain oper- crushing, and conveying the reduced shale to ating conditions. It is not known whether the the surface for retorting. Potentially hazard- retort offgases from the Paraho, Union “B,” ous substances (silica, salts, mercury, lead) TOSCO II, or Superior processes contain COS or CS . may be released during blasting. Methane 2

may be released from underground gas de- The major source of NOX emissions is the

posits, and CO, NOX, and hydrocarbons (HC) combustion of fuel in boilers, air compres- may be emitted by incomplete combustion of sors, and diesel equipment. The specific lev- the fuel oil used both for blasting and in mo- els depend on the combustor design, the ex- bile equipment. In addition, particulate can tent of onsite fuel use, and the nitrogen con- be emitted as a result of blasting, raw shale tent of the fuels used to produce process heat handling and disposal, and activities at the or steam. Most of the fuels consumed in oil Ch. 8–Environmental Considerations ● 261 shale plants will be produced onsite. Both di- chrome, zirconium, and manganese.l At typi- rectly heated aboveground retorts (AGR) and cal retorting temperatures (ea. 900° F (480° MIS generally produce sufficient low-Btu gas C)), it is generally accepted that most trace to meet retorting requirements, plus an ex- elements are not volatilized. They leave the cess for other onsite uses such as power gen- retort in the spent shale product and in par- eration. Indirectly heated aboveground re- ticulate entrained in retort gases and shale torts produce less fuel gas, but it has a higher oil. Possible exceptions are antimony, arse- heating value. In either case, it is possible nic, beryllium, boron, copper, fluorine, lead, that some shale oil will be burned for process mercury, nickel, selenium, and zinc, which heat. Since both retort fuels (gases and shale could leave the retort as vapor and be con- oil) contain nitrogen, they could potentially densed in the liquid product.2 The heavy emit more NOX. metals in raw shale oil are of economic concern because they tend to destroy the effec- HC and CO will be emitted primarily in the tiveness of the catalysts used for refining. * exhausts of mobile equipment and in flue Their removal is not expected to present any gases from boilers and other combustors. HC major problems to the refiner. Several propri- will also be emitted in vapors from oil storage etary techniques are available for this pur- tanks, pumps, flanges, seals, and compres- pose. It has also been recognized that refining sors, and CO by blasting and rubblization catalysts need careful disposal because they during the preparation of MIS retorts. Emis- may contain nickel, cobalt, molybdenum, sion levels from storage tanks should not vary chromium, iron, and zinc, in addition to trace with the type of retorting technology. The elements captured from the shale oil. Emis- other HC and CO sources have a dependence sions can occur during the onsite regenera- on retorting technology that is similar to that tion of these catalysts and during the disposal described for NO . Equipment-related emis- X of spent catalysts in landfill operations. sions are a function of the amount of solids that need handling on the surface. Upgrading, refining, gas cleaning, and power generation produce such pollutants as The quantities and the chemical properties CS2, COS, SO2, H2S, NH3, and HC; with HC of the particulate emitted vary with retort- being the dominant fugitive emission.) Par- ing technologies. Retorts like TOSCO II that ticulate such as fly ash are also produced. require fine shale feed and produce very fine retorted shale, produce the largest amounts. The handling and disposal of raw and retorted shale could create serious fugitive dust The pyrolysis of an organic material like oil problems. This dust may contain harmful par- shale kerogen produces a certain amount of ticulate and possibly POM. The problems polycyclic organic matter (POM). POM, which are most severe for technologies like TOSCO is found in conventional crude oils, has also II that produce very fine spent shale. Dust been found in the carbonaceous retorted production should be less of a problem with shales from TOSCO II, Union “B,” and Para- aboveground retorts like those of Paraho and ho indirect retorts. It is rarely found in re- Union “B” that produce coarse spent shale, torted shale that has been subjected to a They should be even less significant for MIS strong oxidizing environment such as that en- because spent shale will remain underground countered in the Paraho direct retort. and will not be subjected to wind erosion. Trace elements (particularly the heavy metals) may be released by retorting opera- The Amounts of Pollutants Produced tions. Compared with average rocks, Green River oil shale contains much higher levels of It is difficult at present to estimate the selenium and arsenic; moderately higher lev- quantities of air contaminants that would be els of molybdenum, mercury, antimony, and *Refinery modifications to mitigate this problem are dis- boron; and lower levels of cobalt, nickel, cussed in ch. 5. 262 . An Assessment of Oil Shale Technologies produced by a commercial-size oil shale facil- that the tables show levels of pollutant gener- ity. The only field measurements that have ation, not pollutant release. been made to date have been for the small- Of the three designs —Colony, Rio Blanco, scale, short-term pilot-plant or semiworks and Occidental—Colony produces the largest operations of Colony Development, Paraho, 4 amount of particulate. This plan uses both and Occidental Oil Shale. These facilities do the most underground mining and TOSCO II not simulate normal operating conditions in a AGR, which requires a fine shale feed and full-size facility, and the measurements that produces a very finely divided shale. This have been made have been mostly of the regu- retorting method is also responsible for Col- lated pollutants. Only a few of the nonregu- ony’s exceptionally high production of HC. In lated pollutants such as trace elements have the TOSCO II retorting system, vaporized been measured, and those measurements shale oil and gases evolved during pyrolysis that have been reported show considerable are stripped of high molecular weight HC in a variation. Pollution production estimates condenser, and then burned to reheat the must therefore be confined to regulated pol- heat carrier balls. Because combustion is in- lutants and must strongly rely on theoretical complete, lighter weight HC are entrained in calculations. the offgas stream from the ball heater. The quantities of pollutants produced in an In generating steam for power, the Occi- industrial facility can be estimated by apply- dental design in which large quantities of ing pollutant generation factors to the mass low-Btu gas are burned produces the most flows of material through the plant. The pro- NOX emissions. Rio Blanco, which plans to cedure used for the calculation, although an burn coke from the upgrading units, produces approximation, gives estimates of the prob- less NOX but more particulate. Colony’s on- lem’s scope. Generation factors obtained site pollutant production in this step will be from the literature were applied to the mass negligible because it plans to purchase most balances published for Colony’s proposed of its electricity from offsite powerplants. TOSCO II retorting plant on Parachute Creek, for Rio Blanco’s combination of MIS and AGR The emission of SO2, produced in the NH3 processing on tract C-a, and for the Occiden- and sulfur recovery processes, is about the tal MIS operation on tract C-b. All flows were same for all three designs. Although both Col- scaled to a uniform production level of 50,000 ony’s and Rio Blanco’s CO emissions are high- bbl/d of shale oil syncrude. The results are er than Occidental’s, the differences are not summarized in tables 34 through 36. Note significant.

Table 34.–Pollutants Generated by the Colony Development Projecta (pounds per hour)b

Operation Particulate so, NO, HC co Mining ...... 1,480 0 250 50 440 Shale preparation...... 15,940 0 0 0 0 Retorting c...... 11,440 150 1,430 480 60 Spent shale treatment and disposal ...... 1,350 0 130 10 0 Upgrading...... trace 10 20 10 trace Ammonia and sulfur recoveryd...... , 0 32,200 0 0 0 Product storage ...... 0 0 0 150 0 Steam and power...... – — — — — Hydrogen production ...... 10 30 80 trace 10 Total ...... , . . . . . 30,220 32,390 1,910 700 510

c3Tafj~ shows the ItIVtIt Of pOllUlafll generation, not pollufanf release

bRoom.and.pillar mlnlng, TOSCO II retorting, scaled 1050,000 bbl/d Of shale oll syncrude production cFlgures do not include components of the product gas and VaPOr stream also, equivalent of H*S m retort 9as stream

SOURCE T C Borer and J W Hand, /derr//hcal/on and Proposed CorJlro/ 01 A/r Po//ufartfs from O/l Sha/e Operations, prepared by the Rocky Mountain Diwslon, The Pace Company Consultants and Engineers, Inc for OTA, October 1979 Ch. 8–Environmental Considerations ● 263

Table 35.–Pollutants Generated by the Rio Blanco Project on Tract C-aa (pounds per hour)b

Operation Particulates so, NO. HC co Mining. ,, .,,,.. ,. 1,050 4 340 80 430 Shale preparation. . . . ., . . . . 7,200 0 200 0 0 Retorting ., 8,900 52 320 100 0 Spent shale treatment and disposal 650 0 0 0 0 Upgrading. ., ., 7 0 7 13 0 Ammonia and sulfur recoveryd ., ., ., 0 19,200 0 0 0 Product storage ., ., 0 0 0 105 0 Steam and power. ~ ~ ~ ~ 210 250 1,220 13 0 Hydrogen production – — — — — Total 18,017 19,506 2,087 311 430

aTab[e shows lhe level of poilulanl generation not pollutanf release bundergroun~ mlnlng modlfled [n SIfU and TOSCO II aboveground retorlng scaled tO 50000 bblld of shale oll syncrude cFlgures do not !nclude components of The product 9as and vaPor stream also, ~qulvalen[ Of H,S In retofl 9as s(ream SOURCE T C Borer and J W Hand /deohf/cat/on and Proposed Corrtro/ of A/r Po//ufarrts lrorn 0// Shale OperaOorrs prepared by the Rocky Mountain Owslon The Pace Company Consultants and Eng(neers Inc for OTA Oclober 1979

Table 36.–Pollutants Generated by the Occidental Operation on Tract C-ba (pounds per hour)b

Operation Particulate so, NO, HC co Mining 4,540 0 300 120 180 Raw shale disposal ~ 450 0 100 10 0 Retorting c ~ 0 0 0 0 0 Upgrading. . 10 10 80 trace 10 Ammonia and sulfur recoveryd ., 0 24,000 0 0 0 Product storage 0 0 0 80 0 Steam and power. . 20 trace 2,800 0 0 Hydrogen production 80 20 220 20 20 Total 5,100 24,030 3,500 230 210

aTa~ie shows [he level of ~oliufan[ generation not pollutant release bunderground mlnlng modlfted in sdu retorting scaled to 50000 bbl d Of shale 011 syncwde cFlgures do not Include components of tne product gas and vaPOr stream dsol equivalent o! HIS m reforl 9as stream SOURCE T C Borer and J W Hand Idenhkaflon and Proposed Cofltrol of +Vr Po//ufartk from 0// .S/ra/e Opera(/orm prepared by the Rocky Mountain Ow!s!on The Pace Company Consultants and Eng[neers Inc for OTA Oclober 1979

It should again be noted that the tables may also act to constrain the ultimate size of show the amounts of pollutants generated, the oil shale industry. not the amounts released. Pollutant emissions are regulated by laws and standards, which Air quality regulation is called for by the are discussed in the next section. Compliance Federal Clean Air Act of 1970, as amended in with these laws and standards requires pollu- 1977, hereafter referred to as the “Act.” Reg- tion control technologies, which are dis- ulations and standards arising from this Act cussed later in the chapter. are implemented at the Federal level by EPA and at State levels in conjunction with addi- Air Quality Laws, Standards, tional regulations and standards imposed by the individual States. The following discus- and Regulations sion first highlights major provisions of the Act, and then analyzes those that are particu- Introduction larly significant for oil shale development. The existing and proposed regulations and standards governing air pollution from the oil Highlights of the Amended Clean Air Act shale industry are discussed here because they will affect the design and operating The Clean Air Act, as amended, estab- characteristics of oil shale facilities. They lishes a national program to regulate air .

264 ● An Assessment of Oil Shale Technologies pollution in order to maintain or improve air agers of affected Federal lands (and States in quality. The Act is universally applicable, but the case of Indian action). its provisions are most strongly directed to The classification of an area with respect those areas having the cleanest air (nondegradation areas) and those where air pollution to the ambient air quality has important con- may be hazardous to public health (nonattain- sequences. The Act divided the Nation into ment areas). The major elements of the pro- 247 air quality control regions (AQCRs) so gram established by the Act are: that pollution control programs could be locally managed. Compliance with an NAAQS ● the establishment of NAAQS for criteria is generally determined on an AQCR basis, air pollutants, but EPA allows smaller area designations for ● the submission by each State of a State some pollutants, if that is more suitable for implementation plan (SIP) to achieve and controlling pollution. maintain Federal air quality standards, ● These AQCR designations are highly signif- the preconstruction review of major new icant. Regions that are found by EPA to be in stationary sources, and ● nonattainment status—areas where air pol- PSD. lution presents a danger to public health— National ambient air quality standards.— are subject to a particular set of restrictions Regulation under the Act focuses on six cri- under the Act. On the other hand, nondegra- teria pollutants: particulate, SO2, CO, NOX, dation regions—where air is cleaner than the

03,, and lead. Two types of ambient air quality standards—are subject to a different set of standards are designated: primary stand- regulations, which are intended for “preven- ards, which protect human health; and section of significant deterioration. ” Regardless ondary standards, which safeguard aspects of an area’s classification, almost every new of public welfare, including plant and animal major source of pollution is required to life, visibility, and buildings. The Act sets undergo a preconstruction review. forth an exact timetable by which primary standards are to be met. Secondary stand- State implementation plan.—Each State ards are to be met on a more flexible sched- must submit an implementation plan for com- ule. plying with primary and secondary standards. A State can decide how much to reduce To achieve air quality goals, areas with air existing pollution to allow for new industry cleaner than NAAQS were divided into and development. State plans must also in- Classes I, II, and III. Certain Federal areas clude an enforceable permit program for reg- that existed when the Act was passed (e.g., ulating construction or operation of any new national parks, wilderness areas) were imme- major stationary source in nonattainment diately designated as Class I areas where air areas, or significant modification to an exist- quality was to remain virtually unchanged. ing facility. New processing plants and power All others were designated as Class II—areas stations must also satisfy emission standards in which some additional air pollution and set forth in the SIP. moderate industrial growth were allowed. In- Preconstruction review of major new sta- dividual States or Indian governing bodies tionary sources.—Under the SIP, each new can redesignate some Class II areas to Class III—areas in which major industrial develop- construction project is subjected to five types ment is foreseen and contamination of the air of preconstruction review. The objective of the review process is to determine: up to one-half the level of the secondary standards would be permitted. The States or ● compliance with NAAQS and State Air Indians can also redesignate Class II areas as Quality Standards (AQS); Class 1. Either type of redesignation is subject ● compliance with any applicable NSPS; to hearings and consultations with the man- suitability for a nonattainment area; Ch. 8–Environmental Considerations ● 265

● suitability for a nondegradation area. jor stationary sources owned or oper- (PSD regulations, including the use of ated by him in the State comply with BACT and PSD increments* will apply); emission limitations. and ● ● visibility. Review in nondegradation areas. This type of review, which concerns PSD, is The major elements of these preconstruction discussed below. review procedures are:

● Review for compliance with NAAQS. The prevention of significant deteriora- The applicant must submit plans and tion.—All SIPS must specify emission limita- specifications for review that show: tions and other standards to prevent signifi- methods of operation, quantity and cant air quality deterioration in each region source of material processed, use and that cannot be classified for particulate or distribution of processed material, and SO2, or has air quality better than primary or points of emission and types and quanti- secondary NAAQS for other pollutants, or ties of contaminants emitted; a descrip- cannot be classified with regard to primary tion of the pollution control devices to be standards because of insufficient informa- used; an evaluation of effects on ambient tion. air quality and an indication of compliance with PSD restrictions; and plans Under these PSD standards, maximum al-

for emission reduction during a pollution lowable increases in concentration of SO2 alert. A permit will not be given if it is and particulate are specified for each area shown that the source will interfere with class. For the other criteria pollutants, max- the maintenance of any ambient air imum allowable concentrations for a speci- quality standard or will violate any State fied period of exposure must not exceed the air quality regulation. respective primary or secondary NAAQS, Review for compliance with NSPS. The whichever is stricter. Act directed EPA to set national standards for fossil fuel powerplants, refin- A State can redesignate a Class II or III eries, and certain other large industrial area with respect to PSD only if it follows cer- facilities. If NSPS have been established tain procedures. These include an assess- for the new source, it must be shown ment of the impacts of the redesignation, pub- that the facility will not interfere with lic notice and hearings of such a redesigna- the attainment or maintenance of any tion, and approval by EPA. standard and that BACT will be used for reducing pollution. If a facility’s construction began after Jan- ● Review in nonattainment areas. In nonattainment areas, a new facility may be uary 1, 1975, a special preconstruction re- built only if: by the time operations com- view must be undertaken if it is located in a mence total emissions from it, and other nondegradation area. To obtain a permit for new and existing sources, will be less such a facility, an applicant must demon- than the maximum allowed under SIPS; strate that it will not cause air pollution in ex- the source complies with the more strin- cess of NAAQS or PSD standards more than gent of either emission limitations re- once per year in any AQCR. BACT must be quired by the State or achieved in prac- used for all pollutants regulated by the Act, tice by such a source; and the owner or and the effects of the emissions from the fa- operator demonstrates that all other ma- cility on the ambient air quality in the areas of interest must be predicted. The air quality impacts that could be caused by any growth *In part BAC’I’ is required 10 assure that no single facility associated with the facility must also be ana- wili consume the entire PSf3 increment. lyzed.

63-898 0 - 80 - 18 266 ● An Assessment of Oil Shale Technologies

Implications of the Clean Air Act for rado’s and Wyoming’s standards. In addition Oil Shale Development to the standards shown for Wyoming, the State has also promulgated regulations to The following provisions of the Act have limit ambient concentrations of H2S, hydro- particular significance for oil shale develop- gen fluoride, and other pollutants. The stand- ment: ards are more relevant to large coal-fired powerplants than they are to oil shale proc- ● compliance with NAAQS and State AQS; essing. ● maintenance of air quality, especially visibility, in adjacent Class I areas (e.g., Since the national standards are primarily national parks); directed to urban areas, they should not seri- ● compliance with PSD increments; ously restrict oil shale development in the ● compliance with NSPS; and near future. The annual-average pollution ● the application of BACT. levels allowed by ambient standards are National Ambient Air Quality Stand- much higher than the values normally meas- ards.—Ambient air quality standards pro- ured in the oil shale development area. How- mulgated by individual States cannot be less ever, the short-term standards for particu- stringent than the national standards. Thus, late and HC are occasionally exceeded by the States set the controlling standards if natural emissions such as windblown dust there is an approved SIP. Utah’s standards and HC aerosols produced by revegetation. are identical to the national standards, while Such naturally caused infractions of NAAQS Colorado and Wyoming have set more strin- could have restricted regional development. gent standards for a number of the criteria They actually did affect oil shale development pollutants. Table 37 shows both the national schedules on the four lease tracts located in standards (the same for Utah), and Colo- Colorado and Utah. According to the provi-

table 37.–The Federal and State Ambient Air Quality Standards and Prevention of Significant Deterioration Standards That Influence Oil Shale Development (concentrations in micrograms per cubic meter)

Prevention of significant Ambient air quality standards deterioration standards

Federal (primary) Federal (secondary) Federal Pollutant human health public welfare Wyominga Colorado a Utah a (Class 1) (Class II) so, Annual arithmetic mean, . . 80 None 60 80 80 2 20 24-hour maximum ... 365 None 260 365 365 5 91 3-hour maximum ...... None 1,300 1,300 700 None 25 512 Particulates Annual geometric mean. . . . 75 60 60 45 75 5 19 24-hour maximum . . . 260 150 150 150 260 10 37

/VOX (as NO,) Annual arithmetic mean. . . . . 100 100 100 100 100 None None Oxidants (as O,) l-hour ., ., ., ... . . 240 240 160 160 240 None None co 8-hour maximum 10,000 10,000 10,000 10,000 10,000 None None l-hour maximum . . . . . 40,000 40,000 40,000 40,000 40,000 None None Lead Quarterly. 1,5 1.5 1,5 1.5 15 None None Nonmethane hydrocarbons 3-hour maximum (6-9 am). . 160b 160b 160b 160b 160b None None

astate amblen( alr ~uallly qandards are ,de”tl~al to the Federal prlrnary standards unless prlfllecl lrl llallcs The s!ncter standard IS the Conlro[llrlg standard bNot a standard, a guide 10 show achievement of o] standard cAllowable Incremental change m ambient Coflcefltratlon SOURCE Olf{ce of Technology Assessment Ch. 8–Environmental Considerations . 267

sions of the Act, the tracts and their environs Table 38.–National Standards for Prevention of were nonattainment areas. As such, they Significant Deterioration of Ambient Air Quality were not subject to any additional develop- (concentrations in micrograms per cubic meter) ment. This potential barrier was cited by Maximum allowable increase some of the tract lessees in their requests for Pollutant Averaging time Class I Class II Class Ill activity suspensions in the fall of 1976. Particulates Annual 5 19 37 24 hour 10 37 75 In December 1976, EPA ruled that new de- so, ., Annual 2 20 40 velopment could proceed in a nonattainment 24 hour 5 91 182 area if the developer would offset new emis- 3 hour 25 512 700 sions by reducing the same emissions from an aEpA IS presently developing Incremental standards tor HC CO O, NOX and pb existing source in the same area. Although SOURCE Environmental Profechon Agency Work Group Po//ufIorI Cm(m) Guidance (or 01/ Sha/e De(e/oprr?en/ Appendices 10 /he Rewsed Llraf/ EPA Clnclnna!l Ohto July 1979 p possibly applicable to urban or industrialized 0-17 areas, such a policy was not relevant to the oil shale regions because there are no substantial existing industries against which to for Class I areas could affect the siting of oil offset oil shale emissions. EPA made a subse- shale facilities. Figure 59 shows the Class I quent ruling in July of 1977 that air quality areas located near oil shale country in Col- problems arising from natural sources would orado, Utah, and Wyoming. The two Colorado not preclude oil shale development, providing areas nearest the oil shale deposits are the that facilities complied with emission and existing Flat Tops Wilderness and the proposed Dinosaur National Monument. PSD standards. The history of this ruling and its effects are discussed in detail in the Preconstruction review for oil shale facil- analysis of the Prototype Oil Shale Leasing ities.—Under the Clean Air Act, each new oil Program. (See vol. II.) shale plant must be evaluated during a pre- A second consideration is the visibility pro- construction review to determine its ability to tection afforded to Federal mandatory Class I comply with NAAQS and PSD regulations. areas under the Act. Regulations are to be Projected emission levels will be regulated by promulgated by EPA by November 1980, and EPA’s NSPS, State emission standards, and the mandated use of BACT. by the States by August 1981. These regulations may affect the siting of future oil shale At present, there are no Federal emission facilities. standards that deal specifically with oil shale Compliance with standards for PSD.—PSD operations. However, NSPS have been devel- standards exist for Class I, II, and III areas. oped for fossil-fuel-fired steam generators, The oil shale area is a Class II region, which petroleum refineries, and Refinery Claus means that some additional pollution will be Sulfur Recovery Plants. Table 39 lists the existing and proposed NSPS for these facilities allowed, but pollution up to the level of ambient air quality standards will not be accept- as a guideline to what might be considered able. EPA’s PSD standards define the max- for oil shale plants. In addition, Colorado has developed emissions standards for shale oil imum allowable increases in S02 and particulate concentrations. These standards are production and refining that limit the sum of all S02 emissions from a given facility to 0.3 shown in table 38. lb/bbl of oil produced or processed. Plants In summary, an oil shale facility will have smaller than 1,000 bbl/d are exempt. Another to meet the PSD requirements for Class II Colorado regulation limits H2S ambient con- areas, and moreover, it will not be allowed to centrations from all shale oil plants to 142 degrade air quality in nearby Class I areas micrograms per cubic meter (142 pg/m3 or 0.1 beyond the limits specified under the PSD p/m). Utah and Wyoming do not have applica- provisions of the Act. Because most pollut- ble emission limits. BACT standards have ants emitted by oil shale facilities can travel been developed by EPA for those oil shale fa- long distances, the stringent PSD increments cilities that have applied for PSD permits, as 268 . An Assessment of Oil Shale Technologies

Figure 59.— Designated Class I Areas in Oil Shale Region

WYOMING ‘ -- — --- -- —r- ~-” DAGGETT I

. MOFFAT

● GRI==STONE

VER;AL I . I I DINOSAUR . ●1 UINTAH L.. —. —.—. —. — .—. — . . .—.

GRAND i MESA ‘“;.vDELT~-’-r- & . I L . —.—. — .–.5? ( I I I . s I . —. —. — . J LEGEND: 5 ❑ GUNNISON FOREST AREAS I MONTROSE i AREA DESIGNATIONS Federal Mandatory Class I Areas: 1, 2, 3,4, 6 Colorado Class I Areas: 5, 6,8 Draft Proposed (NPS) Class I Areas: 6, 8

CLASS I AREAS 1. Flat Tops Wilderness 5. Black Canyon of the 2. Mount Zirkel Wilderness Gunnison Monument 3. Maroon Bells—Snowmass Wilderness 6. Colorado National Monument 4. West Elk Wilderness 7. Arches National Park 8. Dinosaur National Monument

SOURCE: Environmental Protection Agency Work Group, ~0//ut/orI c20~fr0/ Gwdarme /of 0// Shale ~eveloweflf Awerrdmes to (he Rev/seal Draft, U S. Environmental Protection Agency, Clnclnnatl, Ohio, July 1979, p. D.41 Ch. 8–Environmental Considerations . 269

Table 39.–National New Source Performance Standards for Several Types of Facilities’

Operation Pollutant Removal or emission standardb Status Fossil fuel fired steam generators Particulates 0.1 lb/m Btu Existing

S02, NOx 0.8 lb/m Btu for gaseous fuels; 0.3 lb/m Btu for liquid fuels

Petroleum refineries H2S 0.1 gr/scf (dry) Existing HC Floating roof tanks or vapor recovery systems if true vapor 2 pressure IS between 1,5 and 11,1 lbt/in a and reporting system only if pressure is less than 1.5 lbf/in2a

Refinery Claus sulfur recovery plants H2S 0,1 gr/scf (dry) Existing Sulfur 250 p/m SO, for oxidation systems, 300 p/m total sulfur and

10 p/m H2S for reduction systems

Gas turbines NOx 75 p/mat 15Y0 oxygen Proposed for units over 10 so, 150 p/m m/ Btu per hour Gasification plants Sulfur 99,0% removal and 250 p/m total sulfur Guideline HC 100 p/m

Field gas processing units H2S 160 p/m Proposed so, 250 p/m for oxidation systems Sulfur 300 p/m for reduction systems apre~ented ~~ ~ g“lde to what mlghl be considered for oll shale facl[llles bib, ,nza = ~ound~ ~er square Inch absolute p/m = ~er mltlron Scf = standard cubic feel cStandards tor fossil fuel fired steam generators being fevlsed SOURCE Environmental protection Agency Work Group Pol)ul/on Con/ro/ Gu@arme for OIJ Sha)e Deve/opmenl ,.lppendmes fo fhe RewseO Dra(f. EPA Clnclnnatl Oh!o July 1979 p D 34 shown in table 40. These standards specify to be promulgated, cannot be determined at levels of removal efficiency for specific this time. pollutants, and in some cases also define the maximum concentration that will be allowed in the emitted stream. Air Pollution Control Technologies In summary, oil shale facilities will have to In order to comply with the air quality laws undergo preconstruction review. BACT will and regulations, oil shale facilities will have be required for all pollutants regulated by the to control their pollutant emissions. Various Act, and plants will have to comply with am- aspects of pollutant control are discussed in bient air quality and PSD standards for Class this section. II areas. Facility siting might be affected by PSD standards in adjacent Class I areas. The ● The control technologies that can be effects of visibility standards, which have yet used to reduce emissions of particulate,

H2S, sulfur compounds, NOX, HC, and CO Table 40.–EPA Standards for Best Available Air Pollution are described, and their potential appli- Control Technologies for Oil Shale Facilitiesab cations to oil shale mining and process- . ing are discussed. Pollutant Removal requirement Maximum emissions ● The technological readiness of these Sulfur 99.0% total recovery 15 p/m H S (reduction systems) 2 techniques are evaluated. 250 p/m SO2 (oxidation systems) Particulates. 99.O% from combustion No standard ● The costs of air pollution control in com- gas streams mercial-scale oil shale plants are esti- 99 80/o from materials- handling gas streams mated. Fugitive dust control NOx Complete combustion 0.5lb/mBtu co Complete combustion No standard Technologies and Applications HC Complete combustion No standard DUST CONTROL ap m = pafls per mlllhon ~These s[andards hake been used In EPA s PSO Cleclslon process In the Pas! Water sprays. —Water sprays can be used SOURCE Enilronmenlal Proteclton Agency Work Group Po//olIon Cor?ko/ G~,dancr for 0/1 Sha/e to control fugitive dust. If adjusted properly, Lleveopmenf 4ppeoUmes to /he Rewsed Llraf! EPA Clnclnnah Ohio July 1979 p D 35 no surface runoff will result. Water sprays 270 An Assessment of Oil Shale Technologies

are about 80-percent efficient for particles probably be used for gas streams from re- larger than about 5 microns, * but less so for torts and solid heaters. smaller ones. Adding a wetting agent reduces the surface tension and improves the wetting, Baghouse filters.—Fabric filters are gen- spreading, and penetrating characteristics of erally used where higher removal efficiency the water, increasing efficiency to 90 to 98 is required for particles smaller than about percent. Chemical binders, such as latex or 10 microns. A large number of bag-shaped fil- bitumastics, can also be added. They aid in ters would be needed to clean large gas flows. particle agglomeration and also increase the In general, all of the filters would be enclosed efficiency of removal. Water sprays, with or in the same structure, called a “baghouse,” without chemical additives, are potentially and would share input and output gas mani- applicable to raw and spent shale storage folds. As a gas stream passes through the and disposal, to crushing and screening, to baghouse, dust is removed by one or more of mining and blasting, and to surface trans- the following physical phenomena: inter- portation. They could also control traffic dust section, impingement, diffusion, gravitational from temporary roads, Larger, more heavily settling, or electrostatic attraction. The ini- traveled roads would probably need to be tial filtration creates a layer of dust on the paved. bag fabric. This layer is primarily responsible Cyclones.—Cyclone separators remove for this method’s high removal efficiency; the dust by means of centrifugal force. Single cy- filter cloth serves mainly as a support struc- clones remove about 90 percent of the larger ture. The operation is very similar to that of a particles, but less than 50 percent of those household vacuum cleaner. smaller than about 10 microns. Their removal efficiencies could be increased by using sec- The efficiency of a baghouse filter depends ond-stage cleaning in scrubbers, filters, or on the particle size distribution, the particle precipitators. Cyclones will be used largely to density and chemistry, and moisture. Under clean retort gases, and possibly for primary most conditions a properly designed and op- dust control in crushers and enclosed convey- erated baghouse will achieve a removal effi- ors. ciency of at least 99 percent for particles as small as 1 micron. Baghouse filters are likely Scrubbers.— Wet scrubbers use water to to be used for dust removal from crushers, remove dust entrained in gas streams. Many screens, transfer points, and storage bins. different types of devices are available, including spray chambers, wet cyclones, me- Electrostatic precipitators.—In electro- chanical scrubbers, orifice scrubbers, ven- static precipitators, an electrical charge is in- turi scrubbers, and packed towers. High-en- duced on the surface of a dust particle and ergy venturi scrubbers are probably the only the particle is captured on a screen having type that have sufficiently high removal effi- elements with the opposite charge. Dry pre- ciencies to satisfy emissions standards. Effi- cipitators have been used for many years; ciencies between 93.6 and 99.8 percent have wet precipitators and charged droplet scrub- been achieved for particles smaller than 5 bers have been developed more recently. All microns, but these efficiencies entail high types are in common use in the electrical pressure losses and constant gas flow rates. power generating industry, in cement and Scrubbers require considerably more energy steel plants, and in many other industries. than baghouse filters or electrostatic precipi- Precipitators have removal efficiencies of up tators. Scrubbers for particulate removal will to 99.9 percent, require little maintenance, can handle large flow rates, and have low energy requirements. They might be used in sev- *A micron is one-millionth of a meter. Removal efficiencies for different particle sizes are important because effects on eral oil shale operations, including mine ven- respiration and visibility vary with the particle size. tilation and the second-stage cleaning of dust- Ch. 8–Environmental Considerations . 271

laden streams from crushers and conveyors. Claus plant (see below). Absorption processes A wet precipitator was used at the Paraho can also remove sulfur compounds, such as

demonstration plant for the combined remov- COS, CS2, mercaptans, and thiophenes, which al of shale oil vapors and particulate from cannot be processed in a Stretford unit. Be- the retort offgas. One is being used in the cause of its low cost and simplicity, the Selex- Petrosix plant in Brazil for the same purpose. 01 process is a good candidate for use in oil shale plants. HYDROGEN SULFIDE CONTROL

The systems for removing H2S that are like- Claus process.—The Claus process, which ly to be used for oil shale operations can gen- is perhaps the oldest and best known method erally remove at least 98 percent of this pol- for recovering sulfur from streams that con-

lutant. They will probably be applied to gas tain both H2S and SO2, has several variations.

streams from retorting and upgrading opera- With a feed stream containing only H2S, the

tions. required S02 is obtained by oxidizing part of

the H2S to S02 by burning it in air, and then Stretford Process.—In this process, the mixing the combustion products with the feed gas stream is scrubbed in an absorption stream. The S02 and H2S are then reacted tower with a solution containing sodium car- with each other in a series of converters to bonate, sodium metavanadate, and anthra- produce elemental sulfur, which is removed quinone disulfonic acid (ADA). Reduction of by condensation. The feed stream must have the metavanadate with H2S in solution causes a relatively high concentration of sulfur com- sulfur to precipitate. The metavanadate is re- pounds in order to achieve a high conversion generated by oxidation with the ADA, and the efficiency with reasonable equipment size. reduced ADA is then regenerated by being oxidized in an air stream. The process was This process has problems with both main- developed for coal- gas treatment, but it has tenance and downtime, thus backup units are been used for many other purposes in a num- often needed. Problems arise from sulfur con- ber of plants, especially oil refineries, in the densation in the supply and product pipe- United States and Europe. lines. The procedures for startup and shut- Any COS and CS that may also be in the down are time-consuming, and moisture and 2 CO in the feed gas are particularly trouble- gas stream would not be removed in this proc- 2 ess and their presence would interfere with some. H2S removal. Therefore, before H2S removal The tail or treated gas from a Claus plant the gas stream would need to be pretreated to still contains fairly sizable concentrations of remove these compounds. H 2S and S02. It can be recirculated, mixed Selexol and other physical absorption with a large volume of stack gas and released, or treated in other systems. In oil processes. —In these processes, H2S is dissolved in a solvent and subsequently recov- shale plants, it is likely that the Claus plant ered. The solvent is recycled. The earliest effluent would require further treatment be- process, a simple water wash, was inefficient fore being released. Processes developed specifically for this purpose include the SCOT, because H2S is not very soluble in water. Modern processes use solvents in which it is Beavon, and IFP techniques described below, more readily dissolved. SCOT (Shell Claus Offgas Treating) proc- Absorption processes are usually used for ess. In this process, the offgas is heated treating high-pressure gases and for reducing with a reducing gas such as hydrogen,

the concentrations of H2S and other sulfur and the mixture is passed through a co- compounds to extremely low levels. These bait-molybdate catalyst bed where all processes involve the selective absorption of the sulfur compounds are reduced to

H2S from gases containing CO2. This produces H2S. The gas is then sent through an ab-

an H2S-rich stream that can be processed in a sorber where the H2S is dissolved and 272 . An Assessment of Oil Shale Technologies

concentrated. The concentrated H2S is Claus plant, its control may be required. The liberated from the absorbing medium by following technologies could be used for this heating and is returned to the Claus purpose. plant. ● Wellman-Lord process. This is a versa- The SCOT process is adversely affected by high concentrations of CO . tile process, widely used by many differ- 2 ent industries, and should be adaptable Since gaseous emissions from oil shale to the oil shale industry. Colony plans to processing are expected to be rich in use it for a commercial-scale above- CO , higher rates of recycling, more com- 2 -ground retorting plant. plete fuel combustion, and perhaps This process relies on the reaction of steam injection to dissolve the CO2 may SO2 with sodium sulfate to produce sodi- be necessary. um bisulfite. The bisulfite solution is ● Beavon process. In this process, the tail next heated in an evaporator. This re- gas from a Claus plant is mixed with hot verses the reaction, liberating a concen- combustion gases and passed through a trated stream of SO2. The SO2 can then catalyst where all the sulfur compounds be converted to either elemental sulfur are converted to H S. The H S-rich gas is 2 2 or sulfuric acid. The regenerated sodium cooled by a slightly alkaline buffer solution and then treated in a Stretford unit. sulfate produced when the reaction is The Beavon process is also adversely af- reversed by heating, is dissolved and recycled. The current version of this proc- fected by high CO2 concentrations in the feed stream. Its use in oil shale plants ess is considered to be a second-generation technique for SO removal. Previous would require adaptations similar to 2 those needed for the SCOT process. problems with sludge production and scaling have been reduced. ● IFP [Institute Francais du Petrok] process. The basic reaction in this process is ● Double alkali process. Double alkali the same as in the Claus process except technology resembles conventional wet that it takes place in a liquid rather than stack-gas scrubbing methods but avoids a gaseous phase. The liquid is a polyalky- most of their problems by using two alka- lene glycol with a 5-percent concentra- line solutions, sodium hydroxide and sodium sulfite, to convert SO to sodium bi- tion of a glycol ester catalyst. Both H S 2 2 sulfite. The spent scrubber solution is re- and S02 are very soluble in this liquid, and efficient conversion to sulfur regenerated by using lime or limestone to sults. The most important operating vari- convert the bisulfite to sodium hydroxide and a precipitate that is a mixture of cal- able is the H2S to S02 ratio which must be at least 2. The process is flexible and cium sulfite and calcium sulfate. The can accommodate wide changes in con- precipitate sludge, which contains the captured S0 , can be disposed of in taminant concentrations while maintain- 2 ing constant conversion rates. Also, be- ponds. cause the gases can be treated at higher Performance of the system is well- temperatures than in other processes, established, and over 99-percent S02 reheat losses are reduced. moval has been achieved with S02 concentrations in the treated flue gas of less SULFUR DIOXIDE CONTROL than 10 p/m. Potential environmental

The amount of SO2 that will have to be re- problems are associated with waste dis- moved will depend on the prior degree of gas posal because the solid residue contains treatment and the type of fuel used in proc- soluble alkaline sodium salts that could essing. Most oil shale plants will probably use pollute surface and ground water in the desulfurized fuel for heating, processing, and vicinity of disposal sites. power generation. Where large amounts of ● Nahcolite ore process. Nahcolite is a

SO2 are emitted, such as in the tail gas of a mineral that contains 70 to 90 percent Ch. 8–Environmental Considerations 273

sodium bicarbonate. It is found in the oil the flue gas from combustion sources for par-

shale deposits in the central Piceance ticulate or SO2 will also reduce HC and CO basin of Colorado. When crushed and emissions. With proper maintenance, it will placed in contact with hot flue gases in a probably be unnecessary to further reduce

baghouse, nahcolite converts SO2 to dry emissions from these sources. sodium sulfate. Typically, 20 percent of the required nahcolite would be used to Other emissions of HC will be caused by precoat the filter bags in the baghouse, preheating raw shale prior to retorting and and the remainder would be sprayed di- by storing crude shale oil and refined prod- rectly into the flue gas stream. The sodi- ucts. Incineration is probably the only realis- um sulfate produced and any unreacted tic way to control them. Storage tank emis- nahcolite would be sent to disposal, sions can be minimized by using floating-roof Pilot-plant experiments have shown that tanks, which can accommodate higher vapor pressures than cone-roof tanks without the S02 removal efficiencies are between 50 to 80 percent depending on flow rates need for venting. through the baghouse and the ratio of OTHER EMISSIONS CONTROLS nahcolite to SO . 2 Emission control by direct flame incinera- NITROGEN OXIDES CONTROL tion systems (also called thermal combustion) Nitrogen oxides are produced in the com- is widely used to reduce the amounts of HC vapors, aerosols, and particulate in gas bustion of fuels, NOX control can be approached in two ways: by adjusting combus- streams. These systems are also used to re- tion conditions to minimize NO production, move odors and reduce the opacity of plumes X from ovens, dryers, stills, cookers, and refuse or by cleaning the NOX that is produced from the stack gases, At present oil shale devel- burners. The operation consists of ducting opers plan to design combustor conditions for the process exhaust gases to a combustion chamber where direct-fired burners burn the low NOX production. Gas cleaning systems could be added in the future, if the need gases to their respective oxides. A well- designed plant flare system is a good example arises for further NOX control, However, with proper design and maintenance of combus- of direct incineration control. tion equipment, external control systems will Catalytic incineration is also used for the probably not be needed in order to comply same purpose. The chief difference is that the with existing regulations. combustion chamber is filled with a catalyst. HYDROCARBON AND CARBON MONOXIDE CONTROLS On contact with the catalyst, certain components of the process gases are oxidized. The emission of HC and CO will be caused The use of a catalyst allows more complete by the incomplete combustion of the fuel for combustion at lower temperatures, thus re- the boilers, furnaces, heaters, and diesel ducing fuel consumption and allowing the use equipment used in oil shale plants, The con- of less expensive furnace construction. How- trol of external combustion sources such as ever, catalysts are generally selective and boilers is primarily through proper design, may not destroy as many contaminants as di- operation, and maintenance. Well-designed rect flame incineration. In addition, because units emit negligible amounts of CO and only of the potential for catalyst fouling and poi- small amounts of HC. Instrumentation is soning, gas streams may need to be cleaned of needed to assure proper operating condi- smoke, particulate, heavy metals, and other tions, and comprehensive maintenance pro- catalyst poisons, grams will be needed to keep emission levels from rising due to fouling and soot buildup. Condensation is usually combined with The proper maintenance of diesel and other other air pollution control systems to reduce internal combustion engines can similarly the total pollutant load on more expensive keep HC and CO emissions very low. Treating control equipment. When used alone, conden- 274 ● An Assessment of Oil Shale Technologies

sation often requires costly refrigeration to for each regulated pollutant would depend on achieve the low temperatures needed for ade- the size of the facility; its location; the nature quate control. of the oil shale deposit; the mining, processing, and refining methods; the desired mix of Several methods can be used for cooling products and byproducts; the characteristics the gas streams. In surface condensers, the of untreated emissions streams; and the emis- coolant does not contact the vapor or condensate; condensation occurs on a wall separat- sions levels allowed by applicable environ- ing the coolant and the vapor. Most surface mental standards. The specific control equipment selected would be influenced by all of condensers are common shell-and-tube heat these factors, plus such considerations as the exchangers. The coolant normally flows through the tubes; the vapor condenses on the proximity to water and electrical power, the availability of land for solid waste disposal, cool outside tube surface as a film and is the labor and material requirements for drained away to storage or disposal. maintenance, the ease of operation, the dem- Contact condensers usually cool the vapor onstrated reliability in similar industrial situ- by spraying a liquid, at ambient temperature ations, the availability of equipment, the ex- or slightly cooler, directly into the gas stream. perience of the developer, and the cost. They also act as scrubbers in removing vapors that do not normally condense. The use An important consideration is the relative of quench water as the cooling medium re- technological readiness of each control meth- sults in a waste stream that must be con- od being considered. A developer needs confi- tained and treated before discharge. dence that a method can be directly transferred to oil shale operations from other in- The equipment used for contact condensa- dustries without undergoing extensive R&D. tion includes simple spray towers, high-ve- All of the techniques described previously locity jets, and barometric condensers. Con- have been applied to industrial processes tact condensers are, in general, less expen- similar to those encountered in mining, retort- sive, more flexible, and more efficient in re- ing, and upgrading of oil shale and its prod- moving organic vapors than surface condens- ucts. However, there are three characteris- ers. On the other hand, surface condensers tics of the potential oil shale industry that re- recover marketable condensate and present quire extrapolating these technologies be- no waste disposal problem. Surface condens- yond the present levels of knowledge: the ers require more auxiliary equipment and scale of oil shale operations, the physical need more maintenance. characteristics of the shale, and the nature of Condensers have been widely used (usually the emissions streams. with additional equipment) in controlling or- Scale of operation.—The proposed mining ganic emissions from petroleum refining, pe- operations are among the largest ever con- trochemical manufacturing, drycleaning, de- ceived and as such will require extraordinary creasing, and tar dipping. Refrigerated con- efforts to control air pollution. For example, densation processes are being used for the re- underground mining on tracts U-a and U-b covery of gasoline vapors at bulk terminals would have mine ventilation rates as high as and service stations. 12 million ft3/min. Cleaning this volume of gas could be both difficult and expensive. The The Technological Readiness of Control Methods large ventilation volume is required by mining health and safety regulations and cannot be As indicated, there are a wide variety of reduced. control technologies that could be applied to the emissions streams from oil shale proc- Open pit mines could be much larger than esses. The selection of suitable technologies underground mines. Problems with fugitive for a given facility would be based on a num- dust would be increased by the larger quan- ber of factors. The degree of control needed tities of solids that must be handled on the Ch 8–Environmental Considerations ● 275

surface. Much relevant experience has been whether conventional H2S control methods gained through the extraction and processing will work well with the low H2S concentra- of other minerals such as coal, copper, ura- tions in the offgas from MIS retorting. Remov- nium, and bauxite. The simpler control tech- al efficiencies that are too low could have niques (such as water sprays) have been conflicted with EPA’s previous BACT stand- thoroughly demonstrated. However, the po- ards for oil shale facilities, which required tential size of oil shale mines may create 99-percent total sulfur recovery, no matter problems for the more complex, collection- how small the concentration of sulfur com- type control systems that have worked well in pounds in the raw gas stream. smaller mines. The cost of air pollution control for deeply buried oil shale deposits is not The technological readiness of the major known. The amount of overburden that must control techniques is summarized in table 41. be removed, and for which pollution control The readiness of dust control methods is would be needed may be prohibitively large. shown to range from low to high, with a high confidence in water sprays, cyclones, and Physical characteristics of the shale.—Oil scrubbers and a medium confidence in bag- shale is a fine sedimentary material held houses and a low to medium confidence in together by its kerogen content. When proc- electrostatic precipitators. Similar ranges essed in certain retorts (such as TOSCO II or are shown for the other control techniques,

Lurgi-Ruhrgas) the shale can disintegrate into The readiness of the nahcolite S02 removal fine particles that are more difficult to collect process is rated as low because only a few and control than other mineral dusts. Other test results have been published for its per- retorts (such as Union “B” or Paraho) will formance with oil shale streams. Also, the produce a coarser product with fewer prob- technology is relatively new and has not been lems from dust. It is uncertain whether elec- used extensively in other industries. trostatic precipitators will perform effectively in commercial-scale operations because The Claus H2S process is regarded highly not much is known about the electrical prop- because it has a long record of successful erties of raw and spent shale particulate. application worldwide. The SCOT and Beavon tail-gas cleaning systems have a high Characteristics of emissions streams.—To rating because they are generally used in date, the streams from small-scale versions of conjunction with the well-established Claus discrete subprocesses (such as pilot retorts) systems. The fact that the feed to these sys- have been used to obtain preliminary evalua- tems would already have been treated in a tions of the efficiencies of pollution control Claus unit removes some of the doubts about technologies. It is not known whether these the effects on their removal efficiencies of the streams accurately represent the streams unique characteristics of oil shale emissions that would have to be controlled in an inte- streams. Combustion methods and evapora- grated commercial-scale plant. For example, tion controls to reduce HC and CO emissions it is not certain that the pollutants generated also have a high rating because they should by commercial-scale retorting, when combin- not be sensitive to any great extent to the ed with the pollutant streams from other sub- scale of operation or stream characteristics. processes (such as upgrading), could be ade- Fugitive HC and CO emissions are much more quately controlled with conventional meth- difficult to control. ods. Also, the effect of volatilized trace elements on the catalysts used in the SCOT The other control techniques are given and Beavon tail-gas cleaning systems and in medium ratings either because they have not incinerators has not been determined, The been tested with oil shale streams for sus- concentration of some of the pollutants gener- tained periods or because the effects on their ated by certain processes may be too low for removal efficiencies of the projected char- efficient control. For example, it is unknown acteristics of streams from commercial-scale 276 An Assessment of Oil Shale Technologies

Table 41 .–Technological Readiness of Air Pollution Control Techniques

Pollutant and control system Readiness rating Comments Dust Water sprays High Effective and in general use with wetting agents added as needed, Low cost, Increased water needs, Road paving High Also reduces vehicle maintenance, Cyclone separators High Low cost, Effective only for large particles. Scrubbers High Low capital cost and maintenance requirements, High energy and water requirements needed for high removal efficiency. Bag house filters Medium High efficiency, Moderate energy and maintenance requirements, Low cost. Not suitable for high- temperature gas streams. Requires more area than other systems, Waste-disposal experience lacking Electrostatic precipitators Low to medium Efficiency sensitive to dust Ioading, temperature, and particle resistivity. Good removal efficiency, Low operating costs and maintenance. Good for large gas volumes. High capital cost.

H tS Stretford process Medium Extensive application in refining industry, Good for large volumes of dilute gases, Being tested for MIS gases, Selexol, purisol, rectisol, Medium Being tested for coal gasification streams, No experience with oil shale emissions, istosoliam, fluor solvent, and other physical systems Claus process High Extensive experience in several industries. Needs concentrated feed streams. High maintenance needs and downtime, Tail gas cleaning SCOT process High Long experience with Claus plants. Beavon process High Long experience with Claus plants, IFP process Medium Used with Claus plants that produce elemental sulfur May be applicable directly to retort gases, so, Wellman-Lord process Medium Thirty Installations worldwide High capital cost. High energy requirements, Double alkali process Medium Used successfully in Japan since 1973. Waste disposal could be costly, Nahcolite ore process Low Limited but successful testing to date, NOx Combustion control High Can easily be designed into new plants Low capital and operating cost, Diesel exhaust control Medium Recirculation— of exhaust gases can lead to maintenance problems. HC and CO Combustion control High Use of excess air easily accomplished, Evaporation control High Use of floating roof tanks is very effective but Increases capital costs, Control of fugitive emissions Low Control is difficult because of the large number of dispersed sources

SOURCE T C Borer and J W Hand /derr//f/ca/lon and ProDosed Conlro/ of A/r Pllufarrk kern 0// .Sha/e OoeraOons DreDared bv the Rockv Moufltaln Ow!slon The Pace ComDanv COOSUltafltS and Engineers Inc for OTA, October 1979 plants are still not known. In the case of the sign, the scale of operation, and the extent of Stretford process, work is underway by Occi- emission removal required by environmental dental Oil Shale which, if successful, could standards, Small-size, temporary plants such significantly improve its readiness. as modular demonstration facilities would probably be designed for minimum front-end In general, the control technologies appear costs; therefore, control systems with small to be fairly well-developed, and should be capital requirements would be used rather adaptable to the first generation of oil shale than those with low operating costs. The lat- plants. Full evaluation will not be possible un- ter systems would be economically attractive til the methods have been tested in commer- over the 20-year operating life of a commercial-scale operations for sustained periods. cial plant but not over the 2- to 5-year lifetime of a modular plant. The design of the plant Costs of Air Pollution Control would also have an effect on the costs of control. Systems to recover the byproducts sulfur

The costs of controlling pollutants from and NH3 could be included in an integrated an oil shale plant would be particularly sensi- facility, for example, not specifically for air tive to the lifetime of a project, the plant de- pollution reduction but to increase plant reve- Ch 8–Environmental Considerations . 277 nues. Additional control technologies would ant generation was summarized in tables 34 be needed to satisfy environmental stand- through 36,5 DRI’s hypothetical control sys- ards, but overall control costs would be con- terns were based primarily on developer siderably less than if byproducts were not re- plans but in some cases were modified to covered, cover technologies— having higher projected removal efficiencies. Two regulatory sce- Another example of the effect of facility narios were considered. Under the “less design on control costs is whether the proc- strict” scenario for particulate control in the esses of upgrading and refining are included. Colony plant, for example, it was assumed If so, other subprocesses such as retorting that particulate reductions from point could take advantage of the efficient control sources would average 98.5 percent, and that systems that are an integral part of any mod- for nonpoint sources of fugitive dust reduc- ern refinery. If refining was not done onsite, tions of 92.2 percent would be required. The control systems would still have to be pro- average particulate reduction for the plant vided for the other operations. The same de- was assumed to be 98.3 percent, Under the gree of removal efficiency could be achieved “more strict” scenario, overall particulate but with higher costs. reductions of 99.5 percent were assumed for The relation of the cost of pollutant control point and nonpoint sources. With some differ- to the degree of removal is usually not linear, ences, similar control scenarios were as- i.e., the costs generally are considerably sumed for other regulated pollutants, and for higher to increase a pollutant’s removal from the other two oil shale projects. Results of 98 to 99 percent than from 90 to 95 percent. DRI’s analysis for the “more strict” case are Consequently, most control costs will be shown in table 42. strongly influenced by the degree of removal As can be seen, the control costs for in- required by environmental standards. Higher dividual contaminants vary widely from proj- removals will be more costly for individual ect to project. In each project, however, the plants but would allow the region to accom- largest capital and operating costs are for modate a larger industry within the frame- SO and particulate removal. Capital costs work of the air quality regulations. 2 for SO2 control equipment, for example, are The Denver Research Institute (DRI) re- over $25 million for the tract C-a and C-b proj- cently estimated the costs of environmental ects, which strongly rely on MIS retorting and control in the three projects for which pollut- which will have to clean large quantities of

Table 42.–Costs of Air Pollution Control (thousand dollars)

Colony projecta Tract C-b projectb Tract C-a prolect’ Overall Capital Operating Overall Capital Operating - Overall Capital Operating reduction cost cost reduction cost cost reduction cost cost Fugitive dust 92 2% $ 1,460 $ 564 98 4% $ 1,460 $ 577 Highd $ 1,460 $ 543 Particulates 99. 5% 29,400 6,499 80.2% 5,792 1,530 99.6% 34,340 8,499 so, 99,0% 9,910 7,240 99.0% 26,210 11,187 99.0% 29,800 12,844 NO, (e) (f) (f) (e) 12,866 3,882 (e) 12,866 3,882 HC and” CO, 50.5% f 7,785 3,766 56.5% 240 50 89.0% 878 182 Total. $58,555 $18,069 $46,588 $17,226 $79,344 $25,950 Cost per bbl of daily capacity $ 1,246 $ 817 $ 979 Cost per bbl of oil produced – $ 1,16 — $ 0.91 — $ 0.97 a47 000 bbl/d of shale 011 syncrude b57 000 bbl/d of crude shale 011 c81 000 bb[/d Of crude shale 01[ dRoads are paved Water sprays used for disposal areas eMaxlmum reduction achievable through adlustmenl of combustion conditions fLCIW reducflofl requlremen!s because of low-temperature retorflng and use Of Iow-flltrogen fuel In combustors SOURCE Oata adapted from Denver Research lnshfule Pred/cfed Cosk of Enwomnerrfa/ CcJmro/s for A Commerc/a/ 01/ Sha/e /rrdus(ry Vo/urne /–Arr Engmeenrrg Arra/ys/s prepared for the Department of Energy under confract No EP 78-S-02-5107 July 1979 pp 407-414 —— ——-

278 ● An Assessment of 011 Shale Technologies dilute retort gas. A much lower capital invest- operations in each facility would be treated ment (about $10 million) is needed for the Col- in control systems similar to those for which ony project because the TOSCO II retorts pro- DRI prepared cost estimates. In the Colony duce a much smaller volume of retort gas. project, for example, it was assumed that According to DRI’s analysis, the overall dusty air streams from crushers and ore stor- costs of air pollution control range from $0.91 age areas would be processed in baghouses, (C-b project) to $1.16 (Colony project) per bbl as would the flue gas from the retort preheat- of oil produced These costs would have been er. Flue gases from the retort and the spent considered very high in the early 1970’s when shale moisturizer would be treated in a hot oil was selling for about $4/bbl. They are less precipitator. A Stretford unit would be used for removal of sulfur compounds. NO and significant under present conditions with oil X prices exceeding $30/bbl. CO emissions would be reduced by combustion controls on all burners, and HC emissions would be reduced with floating-roof storage Pollutant Emissions tanks and a thermal oxidizer flare system. Controlled emissions rates are summarized Table 46 summarizes the rates of pollutant in tables 43 through 45 for three oil shale emissions both for the three projects, and for projects for which pollutant generation rates modular demonstration projects proposed by were calculated previously. It was assumed Union Oil Co. and Superior Oil. The Union and that the raw emissions streams from the unit Superior results are presented for their ac-

Table 43.–Pollutants Emitted by the Colony Development Project (pounds per hour)a

Operation Particulate so, NOx HC co b b Mining ., ., ., . . ., ., ... . . 10 0 250b 50 440 Shale preparation, ., ., 60 0 0 0 0 Retorting, . . ., . 120 140 1,430 270 50 Spent shale treatment and disposal” ~ ~ ~ . ~ ~ 40 0 130b 10b o Upgrading. ., . . ., ., . . ., . trace 10 20 10 trace Ammonia and sulfur recovery ... o 100 0 0 0 Product storage 0 0 0 20 0 Steam and power. ~ ~ ~ ~ ~ ~ ~ ~ . . . 0 trace 20 trace trace Hydrogen production ., 10 30 80 trace 10 Total ., ., ... 240 280 1,930 360 500 +

aR~~m.and.pillar Mlnlng TIJSCO II retorftng scaled to 50000 bbl/d of shale oll syncrude production bThese emissions are not included 10 Colony PSO permlf aPPllcatlOn SOURCE T C Borer and J W Hand /defrf/f/ca(/on and Proposed Con/ro/ of AM Pollufarrfs From 0(/ Shale Operations prepared by the Rocky Mountain Owlsion, The Pace Company Consultants and Eng[neers Inc for OTA October 1979

Table 44.–Pollutants Emitted by the Rio Blanco Project on Tract C-a (pounds per hour)a

Operation Particulate so, NOx HC co Mining ., . ., 20 0 340 6 435 Shale preparation. ., . ., . . . 26 0 0 0 0 Retorting. ., 92 52 320 98 0 Spent shale treatment and disposal’ ~ ~ ~ ~ ~ 32 0 0 0 0 Upgrading. ., ., ., ., ., 6 0 6 13 0 Ammonia and sulfur recovery, ... ., . 0 0 0 0 0 Product storage. ., 0 0 0 105 0 Steam and power ., ., . . . ~ 210 250 1,220 13 0 Hydrogen production ., ., – — — — — Total ., ., ., . . ., ., ... - 386 302 1,886 235 435

auflde@~Ound Mlnlng M [s and Tosco II abovegfound retorting scaled 1050,000bblld of shale oil Swcrude woduchofl SOURCE T C Borer and J W Hand. /derrf/l/ca(/orr and %oposed Confro/ O( AM f’o//ufanfs from 0// S/ra/e Opera(/errs, prepared by the Rocky Mountain Owlslon The Pace Company Consultants and Engineers Inc for OTA October 1979 Ch. 8–Environmental Considerations ● 279

Table 45.–Pollutants Emitted by the Occidental Operation on Tract C-b (pounds per hour)a

Operation Particulate so, NOx HC co Mining 20 0 300 10 180 Raw shale disposal 80 0 100 10 0 Retorting, 10 0 0 0 0 Upgrading 10 10 80 trace 10 Ammonia and sulfur recovery. 0 240 0 0 0 Product storage 0 0 0 80 0 Steam and power 20 trace 2,800 b o 0 Hydrogen production 80 20 220 20 20 Total 220 270 3,500 120 210

a Underground mlnlng MIS retofilng scaled 1050000 bbl d of shale 011 syncrude production bAssumes gas turbines for power generation SOURCE T C Borer and J W Hand (der?hflcallon and Proposed Cofl(ro/ of AU Po//uranrs from 0// Shale Operal/ons prepared by the Rocky Mountain Dlvlslon The Pace Company Consultants and Engineers lnc for OTA October 1979

Table 46.–A Summary of Emissions Rates From Five Proposed Oil Shale Projects

Pollutant emissions, lb/hr

Project and retortinq technology Shale oil production Particulates SO2 NOx HC co Colony TOSCO I I aboveground retort 50,000 bbl/d syncrude 240 280 1,930 360 500 Rio Blanco MIS plus Lurgi-Ruhrgas aboveground retort 50,000 bbl/d syncrude 386 302 1,886 235 435 Occidental MIS 50,000 bbl/d syncrude 220 270 3,500 120 210 Superior Superior retort plus nahcolite and alumina recovery 11,500 bbl/d crude 75 347 172 20 47 Union Union Oil ‘ ‘B’ aboveground retort 9,000 bbl/d crude 35 81 100 59 43

SOURCE T C Borer and J W Hand /deflflf/cat/on and ProDosed ConVo/ ot AK Pol/u(an(s From 0// Sha/e Operations prepared by the Rocky Mounlain Olvlslon The pace Company Consultants and Enav neers Inc for OTA October 1979 tual design conditions, which provide about granted for modular-scale operations on C-a one-fifth of the shale oil produced by the (1,000 bbl/d) and C-b (5,000 bbl/d). EPA there- other projects. Because emissions rates are fore expects the projected emissions rates at not always directly related to plant capacity, these production levels to comply with all ap- the much smaller modular projects are not plicable Federal and State emissions regula- expected to have equivalently lower rates of tions. However, it should be noted that the emissions. In fact, S02 release from the evaluation of the environmental impacts of oil Superior project (11,500 bbl/d) is expected to shale development also requires a considera- be significantly higher than from the three tion of the effects of the emitted pollutants on 50,000-bbl/d projects. In part, the high rate of ambient air quality, which is protected by Superior’s emissions is related to the nature NAAQS and PSD limitations. Without large- of its process, which includes unique sub- scale operating facilities, the effects of emis- processes for the recovery of nahcolite and sions on air quality can only be predicted by alumina. They also arise from the scale of using mathematical models. operation, which does not encourage the use of large-scale, costly controls that would be cost-effective for the larger operations at Col- Dispersion Modeling ony and on the lease tracts. The Nature of Dispersion Models EPA has granted PSD permits for the Col- ony and Union projects at the levels of opera- The Clean Air Act, through the regulations tion listed above. Permits have also been promulgated for attainment of NAAQS and -——

280 ● An Assessment of Oil Shale Technologies

PSD standards, requires the use of mathe- flow near prominent terrain features, but can matical models to relate the emissions from a usually ignore chemical reaction, aerosol source and the resulting incremental impact coagulation, deposition, and visibility effects, that the source causes on a point some dis- which generally become most significant over tance away. At present, models are EPA’s larger distances and longer time periods. In tool for enforcing the provisions of the Act contrast, regional models can sometimes ig- and are the only means for predicting long- nore terrain features, but must consider long- range impacts of oil shale emissions on am- range atmospheric conditions and their ef- bient air quality in the oil shale area and in fects on chemical reaction, coagulation, depo- neighboring regions. sition, and visibility. Air quality models are mathematical de- A key feature that must be considered in scriptions of the physical and chemical proc- evaluating the use of any model to estimate esses of transport, diffusion, and transforma- compliance with NAAQS and PSD regulation that affect pollutants emitted into the at- tions is its ability to simulate worst case con- mosphere. In these models, specified emis- ditions, which are those meteorological condi- sions rates and atmospheric parameters are tions that lead to the highest ground-level con- used as input data, and the effects on ground- centrations. These conditions vary depending level pollutant concentration and visibility of on the location of the emitting facility, its con- plume rise, dispersion, chemical reaction, figuration, and the nature of the surrounding and deposition are simulated. Some models terrain. Some candidate worst case condi- are designed to simulate small-scale airflow tions for the oil shale region include: patterns over complex terrain within a few ● several days of atmospheric stagnation miles of the pollution source. These near- during which emissions would accumu- source models can predict the effects of oil late under an inversion in a valley; shale emissions in the immediate vicinity of the plant. They are used during preconstruc- ● a looping stack-gas plume that would tion review to indicate the facility’s expected bring maximum pollutant concentrations compliance with PSD regulations. directly to ground level; ● Other models simulate broader airflow a plume trapped in a stable atmospheric behavior over distances of hundreds of miles. layer and transported essentially intact These regional dispersion models could be to nearby high terrain; used to simulate the effects on a large area of ● fumigation, when a plume is transported an entire industry, including numerous indi- from a stable layer at medium heights to vidual plants. Regional-scale models can be the ground level. (Fumigation conditions used to predict impacts on air quality in near- normally persist for less than an hour. by Class I areas. The time scale of the input They are usually the worst case for data and the output predictions should be ap- emissions released from stacks); and propriate to the size of the region being simu- ● moderate wind conditions in which a lated. Small increments can be used for near- stable polluted layer spreads uniformly source modeling; increments of several days and causes visibility reduction over a for regional dispersion models. large area. (This is usually the worst Most models incorporate a series of com- case for emissions released near ground putational modules, as shown in figure 60. A level.) major difference between the models lies in It is reasonable to assume that some worst the manner in which the input data are ma- case conditions (e. g., several days of atmos- nipulated and in the application of the com- pheric stagnation) could occur several times putational modules. Usually, not all of the a year, while others might occur only a few modules are used in any given model. Near- times over the lifetime of an oil shale project source models need to simulate complex air and might not be detected during a 1- to 3- Ch 8–Environmental Considerations 281

Figure 60.—Computation Modules in Atmospheric creasing altitude. Their mathematical ex- Dispersion Models pressions are relatively simple, and can often ‘m’ss’””ra’es~ be run on a hand calculator. However, most Background Gaussian models rely on straight-line simula- Plume rise w module tion of pollutant trajectories and do not con- Source characteristics sider spatial, temporal, and vertical vari- Atmospheric conditions ! ations in atmospheric conditions. As a result * t Dispersion Wmdfleld and other meteorological they tend to overestimate ground-level pollut- data + :%?: ant concentrations at distances greater than II 1 I 30 miles from the source. +, Reaction kmetlcs Chemical reaction Numerical or non-Gaussian models such as module Pollutant characteristics grid models are more useful for simulating $ I I I near-source complexities. They estimate pol- I lutant concentrations at each point in a three- dimensional pattern overlying the region of interest. For detailed computations and high accuracy, the spacing of the grid points must

Aerosol coagulation be small and the time interval between suc- I mcdule I cessive iterations must be short. Because of these characteristics and due to the complex t mathematical manipulations used, grid mod- Airborne concentration module els require the use of high-speed computers, and input data must include highly detailed

1 i wind field information. Such information is Visibility module Deposition usually not easily obtainable without a very lwocass (wet & dry) expensive atmospheric monitoring program. module Grid models can also be used for simulat- YGROUND ing long-range effects over a large region if SOURCE E G Walther, et al The Eva/uaf/on of AI{ Oua//fy CJ/spers/on Mode/ /rrg for 01/ Sfra/e Deve/opmerrt prepared for OTA by the John Mu Ir ln - information is available on conditions in the stltute for Environmental Studies, Inc October 1979 upper atmosphere. In these applications, terrain details usually become less important. Complex terrain features, which must be ac- year environmental monitoring program prior curately simulated in near-source modeling, to the start of constructing a project, can be simulated through use of an average Gaussian models* and grid models are roughness factor. However, because of the commonly used to simulate near-source dis- longer timespan being modeled, slow chemi- persion effects. Gaussian models were devel- cal reactions that involve, for example, SO2 oped for the relatively simple air flow pat- and NOX, become significant. Aerosol size terns over flat terrain. They can be modified, distribution (critical in visibility analysis) and with a significant loss of accuracy, to simu- the contributions of other polluting sources late complex flow around terrain obstacles, are also important. and up and down valley floors. They can A critical problem in applying regional simulate some worst-case conditions, such as models is caused by the fact that pollutants very low wind speeds, but not looping plumes pass through several meteorological regimes or variations in wind direction with in- on their path from source to deposition point. *A Gaussian model is based on a theoretical pattern of fre- Budget models, which divide the affected re- quency dlstrihution in which a bell-shaped (or normal) curve gion into discrete air cells, can be useful shows the d is! ribu lion of probabi]i ty associated with different Isues of a va riahle quantit y— in this case pollutant concentra- under these circumstances because they deal tions. only with the flow of air into and out of one

63-898 0 - 8CI - 19 282 ● An Assessment of Oil Shale Technologies cell and with the reactions that occur within photochemical reactions between HC and the cell. If the cell size or iteration increment NOX. * Thus, the conventional set of reactions is too large, important details such as rapid used to model urban photochemistry would deposition in transition areas between low- have to be augmented to accurately simulate lands and mountains may be missed. These the oil shale situation. deficiencies can be compensated for by using Also, oil shale operations emit much fugi- time trajectory models, numerical fluid flow tive dust. Proper modeling of these emissions models, box models, or sector average must consider the role of wind in creating the models. emissions as well as its role in dispersing them. In the mountainous areas downwind of Problems With Dispersion Modeling in oil shale plants, precipitation may cause the the Oil Shale Region wet deposition of the oil shale emission, thus lessening the regional transport of visibility Modeling of oil shale facilities presents a impacts but increasing impacts on ground- number of problems because of the topogra- level ecological systems. phy and meteorology of the oil shale region, the chemistry of oil shale emissions, and the Another problem in developing accurate unknown quantities of emissions expected dispersion predictions for oil shale facilities from commercial-size facilities. Dispersion is the fact that the input data on emissions models developed to date have been primarily can only be estimated, since no commercial- for flat terrain. The terrain of the oil shale ize plants have yet been built. This problem region is very complex, including many val- is exemplified in table 47, which presents a leys and canyons. Furthermore, some devel- summary of emissions data used in several opers have proposed siting their plants in the early modeling studies. These studies varied middle of a cliff face or near a canyon rim. widely with respect to the quantities of the Simulating this geometry presents unique emissions that were assumed for various modeling problems. In addition, the chemistry types of retorting technologies and the levels of oil shale emissions is quite different from that of powerplants in urban areas and may *Photochemical reactions are induced in the atmosphere by lead to increased oxidant formation through u] traviolet radiation from the Sun.

Table 47.–A Comparison of Atmospheric Emissions Used in Modeling Studies

Total emissions (lb/hr) Production capacity Study and site Retort (bbl/day) Study date so* NOx HC Particulates Battelle Colorado TOSCO II 50,000 1973 143 732 300 1,285 Federal Energy Administration Colorado TOSCO II 50,000 1974 1,332 1,464 317 741 Stanford Research Institute Colorado and Utah TOSCO II 100.000 1975 3,111 4,078 600 650 Colony Colorado TOSCO II 63,000 1975 282 1,806 324 829 317 1,746 304 842 Tract C-b Colorado TOSCO II 45,000 1976 267 1,634 262 776 353 1,894 313 968 Tract C-a Colorado TOSCO II 6,000 1976 26 322 112 148 56,000 265 994 185 573 Tracts U-a and U-b Utah Paraho 10,000 1976 8.4 108 0.88 68 50,000 148 1,369 55 452

SOURCE Adapled from the Enwronmenlal Prolectlon Agency A f’relvmrrary Assessmertrof fhe Env/ronrnerUa/ hnpacfs from (7// .Sha/e L7eve/oprnenfs July 1977 p 110 Ch. 8–Environmental Considerations 283 of production, Even if the estimates for the cluding completely different retorting tech- TOSCO II operations are scaled to the same nologies and levels of operations. As noted in production capacity, they vary by as much as volume II, the tract C-a lessees originally con- an order of magnitude. Much of this discrep- templated open pit mining and aboveground ancy is associated with assumptions by ana- retorting in a combination of TOSCO II and lysts about environmental-control technol- directly heated retorts (like the Paraho kiln). ogies and their efficiencies, Although individ- In phase I, a single TOSCO II retort would be ual modeling runs provide some insight into used to produce from 4,500 to 9,000 bbl/d of site-specific air quality effects for a given shale oil. In phase II, several TOSCO II and retort capacity under specific meteorological directly heated retorts would be used to pro- conditions, substantial variations in the induce up to 55,800 bbl/d. The lessees con- put-data assumptions prohibit comparing dif- ducted modeling studies that estimated the ferent retorts, levels of development, and air quality impacts of each development plant locations, phase. Both long- and short-term effects were studied with an EPA Gaussian Valley model, The Application of Dispersion Models to modified to account for the mixing-layer ef- Oil Shale Facilities fects of rough terrain and for inversion episodes. Results were reported in the DDP in The application of flat-terrain models to March 1976.’ the oil shale region requires many adaptations in order to provide rough estimates of The lessees subsequently adopted a new the impacts of a particular facility on am- plan that was also phased but which involved bient air quality. Near-source models have underground mining and MIS processing. The been used to estimate the effects of emissions lessees prepared a revised DDP and per- from single proposed facilities. Such effects formed new modeling studies. Two mathe- must be modeled to qualify for a PSD permit matical models were used: long-term (annual) from EPA. A preliminary study has also been effects were studied with an EPA model modi- undertaken by EPA to estimate the regional fied for high terrain and atmospheric stabil- effects of several oil shale plants. Since only ity; shorter term (3 to 24 hours) effects were estimates are available for the levels of emis- studied with a modified Gaussian model. As sions from commercial-size facilities, model- in the earlier modeling studies, meteorologi- ing results can only be considered approx- cal measurements made on the tract were ima te, used as input data to the models. Worst case predictions for both phases were reported in One example of the use of near-source the revised DDP in May 1977.9 models was a study performed for Colony De- velopment by Battelle Northwest Laborato- The results of both sets of studies are re- ries. Colony was considering two plant loca- ported in table 48. Predictions are presented tions: one in the valley of Parachute Creek, for both offtract ambient air quality and for the other on an adjacent site atop Roan Pla- the incremental quality degradation. Also shown are the relevant NAAQS (either pri- teau. A model predicted that NOX concentrations near the valley site would exceed the mary or secondary, depending on which is more stringent), the Federal PSD increment national standards; SO2 and particulate would barely meet the standards. The model limitations, and the corresponding Colorado predicted that the corresponding pollution ambient air standards. All standards shown levels near the plateau site would be an order are those that currently apply to the oil shale of magnitude lower. Because of this predic- region. tion, Colony selected the plateau location.67 The models predicted that both phases of Another example is the work undertaken both plans should be in compliance with ap- for Federal lease tract C-a. Models were run plicable standards, However, the off tract for widely different operating conditions, in- concentration of nonmethane HC was pre- . —

284 . An Assessment of Oil Shale Technologies

Table 48.–Modeling Results for Federal Oil Shale Lease Tract C-a

Revised DDP (May 1977) Original DDP(March 1976)

National standards Colorado standards Ofttract ambient air Offtract increment Otftract ambient air Ofttract increment b c b c d e d e Averag- PSO increment Ambient PSD Increment Phase l Phase II Phase l Phase II Phase l Phase II Phase I Phase II a Pollutant ing time NAAQS Class II Air Category II MIS MIS/TOSCO II MIS MIS/TOSCO II TOSCO II Aboveground TOSCO II Aboveground

So2 Annual 80 20 80 20 84 8 32 27 10 11 1 2 24-hour 365 365 91 102 8 5 3 23 28 14 19 3-hour 1,300 512 700 512 352 25 30 20 91 103 82 94

NOX Annual 100 None 100 None 8 13 6 11 16 10 14 8 Particulates Annual 60 19 45 19 9 12 03 3 16 22 10 24-hour 150 37 150 37 10 12 1 3 34 41 22 29 Nonmethane HCf 3-hour 160 None 160 None 65 90 0.3 25 221 129 156 64 Lead Quarterly 15 None 15 None — — — — — — — — o, l-hour 240 None 160 None — — — — — — — —

aslrlcter Ot primary and secondary standards bcapacll 4000 bbl/d (MIS) ccapaclty 57000 bbl/d (MIS) + 19.000 (TOSCO 11) dcapaclty 9000 bbl/d (TOSCO l{) ecapaclly 55800 bbl/d (TOSCO II and. e 9 ~ paraho) \Not a standard a guide to show achievement of the O, standard SOURCE Data adapted from onglnal and revised detaded development plan for tract C.a See refs 8-9 dieted to exceed the Federal and State guide- particulate, and nonmethane HC and lower lines during Phase I of the old plan. It should levels of NOX than the revised concept (un- also be noted that in the old plan the off tract derground mining, MIS, and limited above- increment for HC is only slightly less than the -ground retorting). Although the revised facil- 3-hour average guideline. In the new plan, ity is to have 36 percent more shale oil capac- however, offsite concentrations and incre- ity, ambient air impacts and PSD increments ments for both phases are well within compli- are generally lower. ance. With respect to regional modeling, EPA has With respect to the effect of scale of opera- used a modified Gaussian model to predict tion, the table indicates that, in general, the the effects on air quality at the Flat Tops impact of the smaller scale phases of both Wilderness Area of oil shale operations at the plans are nearly equal to those of the corre- Colony site (50,000 bbl/d), on tract C-a (1,000 sponding larger scale phases. This is ex- bbl/d), on tract C-b (5,000 bbl/d), and at the plained by the lessees’ intent to use the first Union site (9,000 bbl/d). * The total shale oil phase of each plan to obtain reliable data on production was about 65,000 bbl/d, of which emissions levels and dispersion characteris- about 77 percent was assumed to come from tics, and then to use these data to design con- Colony’s TOSCO II retorts. The model was trol technologies for the subsequent commer- limited in that only one source could be mod- cial phases. Also, final commitment to the eled at a time, so four runs were needed to commercial operations was not to be made model the industry. In each run it was as- until technical and economic feasibility stud- sumed that the wind was blowing from the ies, based on operating data obtained in the source directly to Flat Tops. The cumulative early phases, could be completed. To avoid impacts of the industry were estimated by unnecessary capital commitment in the initial adding the increments from each source. Re- phases, the first facilities were designed for sults indicated that about 20 percent of the minimum investment requirements. PSD increment for particulate would be con-

sumed, and about one-third of the S02 incre- It is difficult to interpret the technology- ment. Simple linear scaling would indicate related effects of old and new plans for tract that the industry would be limited to about C-a because the levels of operation are dif- 217,OOO bbl/d by the PSD restrictions on S0 , ferent, and different models were used to 2 and to about 325,000 bbl/d by the particulate simulate air quality impacts. However, a PSD. qualitative comparison is possible. The table indicates that the original concept (open pit *Flat Tops Wilderness Area is approximately 65 miles from mining and aboveground retorting) would tract C-a, and 50 miles from tract C-b and the proposed Colony have caused higher ambient levels of SO2, and Union projects. Ch. 8–Environmental Considerations 285

Such scaling is highly inaccurate for a the exception of the Colony project, only number of reasons. First, Gaussian models small-scale plants were modeled. Some devel- tend to overestimate ground-level concentra- opers, such as Rio Blanco and the tract C-b tions of SO2, because they do not allow for for- lessees, have also modeled the effects of com- mation of sulfate particles from S02 and their mercial-scale operations at the same loca- subsequent deposition. Second, it is impossi- tions. However, EPA has not yet evaluated ble for the wind to be blowing from four di- the results of these studies for adequacy rections at the same time. Third, the pro- under the PSD-permitting process. jected SO2 and particulate concentrations at Flat Tops were affected strongly by the Col- ony project, which is predicted to emit more The widespread reliance on the Gaussian Valley model should also be noted. All of the SO2 and particulate than the technologies proposed by tract C-a, tract C-b, and Union. It developers relied on this model for simulation was EPA’s opinion that a better estimate of near-source effects. PSD permits were would be that as much as 400,000 bbl/d could granted for the projects because the models be accommodated in the Piceance basin by represented the state-of-the-art of near- the PSD standards for Flat Tops.10 EPA’s source dispersion, and because most of the analysis did not consider any project in the projects were of relatively small scale. The Uinta basin, the eastern edge of which is models used are deficient in many respects. about 95 miles from Flat Tops. Therefore, For example, the Gaussian Valley model can there are no estimates available of the addi- be used for estimating pollutant dispersion in tional capacity that could be installed in Utah stable atmospheric conditions in complex ter- without exceeding the PSD restrictions at rain, However, as described previously, it tends to overestimate SO concentrations and Flat Tops. The proposed Dinosaur National 2 Monument, about 50 miles north of tracts U-a cannot handle most worst-case conditions. and U-b, could also limit operations in Utah if Also, Gaussian models when applied to com- it is designated as a Class I area. * plex terrain introduce error by a factor of 5 to 10 when computing concentrations on high- terrain features. This factor of error in the Evaluation of Modeling Efforts model’s capability, coupled with a 2 to 5 error Table 49 lists the models used by oil shale factor in estimating emission concentration, developers to support PSD applications for increases the level of uncertainty in deter- their projects. EPA has accepted the results mining compliance with air quality stand- of these studies as evidence of expected com- ards. In a recent workshop conducted by the pliance with air quality regulations, and PSD National Commission on Air Quality, it was permits have been granted. Note that, with recommended that the Valley model be used only for screening purposes in complex terrain situations, and that it not be used for de- *A Department of the Interior task force in September 1979 recommended Iha t the Dinosaur Nntional N!onument be desig- termination of compliance with NAAQS or na led as a Class I n rcn. PSD standards. ’

Table 49.–Models Used in Support of PSD Applications for Oil Shale Projects — Maximum shale Project Retorting technology 011 production Model used Colony Development Operation TOSCO II 46,000 bbl/d Gaussian Valley model, modified for rough terrain, to study effects of long-distance transport. Box model for effects of trapping inversions near source. Union 011 Co Long Ridge Union ‘‘B’ 9,000 bbl/d Modified Gaussian Valley model. RIO Blanco 011 Shale (tract C-a) Modular MIS 1,000 bbl/d Modified Gaussian Valley model C-b Shale 011 Venture (tract C-b) Modular MIS 5,000 bbl/d Modified Gaussian Valley model Occidental 011 Shale Inc Logan Wash Modular MIS 5,000 bbl/d Modified Gaussian Valley model

SOURCE Ofllce of Technology Assessment 286 ● An Assessment of Oil Shale Technologies

Other models that have been used to pre- ity, near-source effects and more distant dict emissions from proposed oil shale facil- impacts could be modeled simultane- ities include the CRSTER and the AQPUF2. * ously. The CRSTER model is generally used by EPA ● Chemical reaction and deposition mod- to simulate effects of emissions from tall ules should be included wherever the stacks in complex terrain. It tends to overesti- modeled region is large enough for these mate pollutant concentrations where plumes effects to be significant. are intercepted by terrain features higher ● A simulation of photochemical oxidant

than the plume rise height, ” The CRSTER formation and of the conversion of SO2 to model used by Rio Blanco in their DDP could sulfates should be combined in the same not handle fugitive dust emissions, gravita- model. tional settling, separated stacks, chemical reactions in the plume, some high-terrain More specific research needs can be iden- features, and a change of wind direction with tified for the oil shale region. The models used height. All of these variables are important to to date have given only rough estimates of the accurate prediction of some near-source ef- impacts of oil shale development on ambient fects. The AQPUF2 model also used by Rio air quality. Because the models are only ap- Blanco in their DDP for short-term studies proximations, they cannot provide definitive was better able to simulate plume behavior in answers to crucial air quality questions. No complex wind fields and to compare the ef- commercial-scale oil shale facilities exist that fects of emitting stacks a significant distance could supply the data for verification. Fur- apart from each other. The effect of wind thermore, essential information is lacking on speed on the generation of fugitive emissions meteorological conditions in locations other was not simulated in any of the models used. than in the immediate vicinities of some of the proposed development sites. Research and Development Needs The models themselves need to be improved for the oil shale region. Near-source The problems of modeling pollutant disper- models need to be modified to better simulate sion in the oil shale area are also encountered chemical reaction, coagulation, deposition, in other regions with complex terrain, such and visibility effects of oil shale plumes dur- as the Ohio River Valley and the Four Corners ing stagnation periods. Models are also need- area of Colorado, Utah, Arizona, and New ed that can simulate the effects that several Mexico. The Dispersion Modeling Panel at a facilities would have on air quality in a small recent workshop conducted by the National area having complex terrain. This capability Commission on Air Quality recommended the will be critical in evaluating the effects of following research on the modeling of atmos- ] second-generation oil shale plants. A good pheric dispersion in such areas: ] site for analysis would be the southeastern . Regional models should be developed corner of the Piceance basin. PSD permits that can simulate effects at long dis- have already been issued for three projects in this area, which contains much of the private- tances from the sources, For SO2, these distances could approach 600 miles. Up- ly owned oil shale land in Colorado. More ap- wind pollutant concentrations should be plications may be submitted in the near fu- determined and used as input data to the ture. Models are also needed that can simu- models. late the effects of wind rate on generation ● The regional models should allow the use and transportation of fugitive dust from stor- of a fine-resolution grid spacing near the age and disposal areas. pollution sources, and a coarse spacing Many of these improvements also are at greater distances. Given this capabil- needed by regional dispersion models. In par- *CRSrI’ER is a Gaussian model developed by EPA, AQPUF2 is ticular, existing models should be modified to a segmented-plume Gaussian rough-terrain model, simulate long-range visibility effects of oil Ch 8–Environmental Considerations ● 287 shale plumes. This capability will be required The state-of-the-art of near-source and re- to respond to the forthcoming visibility reg- gional dispersion modeling is being advanced ulations. Visibility models exist that deal with by R&D programs under the sponsorship of the formation of aerosols and particulate EPA and other organizations. The following from SO2 and NOX, but these models are ap- projects are of particular importance to eval- plicable to examinations of urban smog and uating the air quality impacts of oil shale powerplant emissions. Greater emphasis plants. would have to be given to HC reactions in order to modify these models to simulate oil EPA is funding a project with DRI to shale plume effects. combine information on oil shale emissions and meteorology, and to use region- The need to model the cumulative impacts al models to assess air impacts from sev- on regional air quality is particularly impor- eral commercial-size oil shale facilities. tant. Each scenario should include specifica- The model will also handle emissions tions for the locations of oil shale plants, a from other sources such as traffic, pow- characterization of their pollution control erplants, and other mineral-processing technologies, and estimates of their emissions plants. rates. The region’s meteorology would have to EPA is funding a project with the Univer- be accurately characterized over periods of sity of Minnesota to develop a simple several days, or for at least the time required model of aerosol dynamics, including for the full impact of the combined emissions conversion of gases to aerosols, that may to be experienced in nearby Class I areas. be of use in evaluating the effects of the Computational modules would have to be in- chemistry of oil shale plumes on visibili- cluded for the effects of emissions, disper- ty. sion, aerosol dynamics, chemical reaction, Los Alamos Scientific Laboratory is deposition, and visibility, The model also funding a project with the John Muir In- should handle differences between daytime stitute for Environmental Studies to de- and nighttime mixing heights and atmos- velop a multiple-source visibility model pheric chemistry, In addition, the regional that could be applied to regional disper- models would have to be validated, either sion studies in the oil shale area. In a through tracer studies in the oil shale region related study, the University of Wyoming itself or by examining the ability of the model and Los Alamos are funding a project to to simulate the behavior of emissions from a develop a regional haze model which group of coal-fired powerplants or smelters. might be useful in assessing visibility ef- One type of tracer study that could be used fects of oil shale plumes. to validate the models is the release of sulfur EPA is funding an in-house project at Re- hexafluoride, or a similar tracer compound, search Triangle Park to develop a multi- followed by the monitoring of tracer concen- ple-layer atmospheric model that is de- trations at numerous ground-level locations. signed to explain regional O3 patterns in A dense pattern of monitoring stations would the Northeast. It may also be useful for be needed to locate maximum concentrations, explaining the high O3 concentrations because the widely varying wind patterns in encountered in the oil shale area. the oil shale region prevent any attempt to EPA is funding a project with Systems characterize total wind fields by interpolat- Applications, Inc., to model the air quali- ing data from a few stations. Baseline meas- ty effects of oil shale industries with urements of pollutant concentrations and vis- capacities of 400,000 bbl/d (including ibility parameters upwind from the source tract C-a, tract C-b, Colony, Union, Supe- would be required to accurately simulate the rior, tract U-a, and tract U-b) and 1 mil- chemical interactions of the tracer plumes. lion bbl/d. The model will handle all 288 ● An Assessment of 011 Shale Technologies

sources simultaneously and will model suggested R&D responses are summarized in visibility effects. The project is designed table 50. Some of the uncertainties, such as as an extension to EPA’s early regional dispersion behavior, could be reduced some- modeling exercise. Its major objective is what by means of laboratory studies and to estimate cumulative impacts on exist- computer simulations; others, such as the ing and proposed Class I areas such as performance characteristics of control tech- Flat Tops. nologies, may necessitate full-size facilities and extended programs under actual operating conditions. It is important that emissions A Summary of Issues and Policy Options studies and monitoring and modeling pro- Issues grams keep pace with oil shale development. LIMITS ON OIL SHALE DEVELOPMENT INADEQUATE INFORMATION The atmosphere has a finite carrying ca- Extensive work has been undertaken in the pacity; that is, it can only disperse limited public and private sectors to determine the quantities of airborne pollutants. The effect degree of pollution control that will have to be of the carrying capacity of air in the oil shale used by oil shale facilities to protect air quali- region on the long-term development potential ty. However, no large-scale facilities exist to of oil shale resources is unknown. A crude re- verify the predictions arising from this work. gional modeling study undertaken by EPA has Furthermore, the dispersion characteristics indicated that an industry of 200,000 to of treated emissions streams cannot be accu- 400,000 bbl/d could probably be controlled to rately predicted because modeling and moni- meet PSD regulations in the Piceance basin. It toring methods are not yet adequate. In its is unclear whether a larger industry (the present state of development, modeling can order of 1 million bbl/d) could be established be used, but the results must be carefully in- in the Piceance and Uinta basins without vio- terpreted. Therefore, it is not known what im- lating air quality regulations. pacts oil shale unit operations will have on air quality at various shale oil production lev- Additional questions arise regarding the els. Specific areas of uncertainty and some manner in which PSD increments will be allo-

Table 50.–Areas of Inadequate Information and Suggested R&D Responses

Area of uncertainty Relevance Research need Baseline air quality conditions and Inhibits accurate modeling of emis- Regional characterization studies, including measurement of visibility and meteorological characteristics sions dispersion and deposition concentrations of criteria and noncriteria pollutants and determination of meteorology, especially with respect to worst case conditions. Emissions characteristics Prevents evaluation of control effec- Characterization of stream and fugltive emissions, beginning with pilot-plant tiveness and cost and reduces studies and continuing with first-generation modules and pioneer commercial- modeling accuracy. size plants. Streams from individual unit operations should be Integrated to simulate expected commercial conditions. Performance of control Inhibits modeling and cost Additional pilot-plant and demonstration-plant programs. technologies estimation. Dispersion behavior Inhibits evaluation of near-source and Improvement in modeling and monitoring techniques for complex terrain, regional air quality impacts. including development and validation of near-source and regional dispersion models Models to be validated for the terrain and meteorology of the 011 shale region and for emissions similar to those expected from 011 shale operations. Trace element behavior Inhibits evaluation of the effects of 011 Monitoring of trace element concentrations in process feed streams, treated shale development on human health, emissions streams, and fugitive emissions. Examination of the effects of plants, and animals. conventional control technologies on trace elements. Determination of the relationships between trace element concentrations in soils and plants and nutritional problems. Development of indicator species Studies of the synergistic effects of trace elements on vegetation

SOURCE Ofl[ce of Technology Assessment Ch. 8–Environmental Considerations ● 289 cated to potential oil shale developers. The oil shale basin that could be developed, and thus shale region has been designated Class II, but limit the ultimate size of the industry that several Class I areas exist nearby that could could operate within the basin, be affected by oil shale operations. The law prohibits any facility to exceed the PSD limi- UNDEFINED REGULATIONS tation in any area, including the area in The Clean Air Act stipulates a need to pro- which the facility is to be sited and any adja- tect visibility in Federal mandatory Class I cent areas, Thus, oil shale developers will areas. While regulations are to be promul- have to demonstrate that their facilities will gated by EPA by November 1980, and by the satisfy both Class II PSD standards and Class States by August 1981, uncertainties still ex- I standards. ist as to the potential implications for oil shale development in regard to the siting of Under the present regulatory structure, future oil shale facilities. In addition, EPA is PSD increments are allocated on a first-come, presently developing incremental PSD stand- first-serve basis. The first oil shale plants in a ards for HC, CO, O3, NOX, and lead. Oil shale given area could exhaust the entire incre- facilities will have to comply with these new ments. If this occurs, subsequent developers, standards. who might be delayed by the preliminary status of their processing technologies, will not Another area of uncertainty concerns be able to locate in the same area, regardless emission standards for hazardous air pollut- of the efficiency of their air quality control ants under section 112 of the Clean Air Act, strategies. To date, the emissions that are regulated are asbestos, vinyl chloride, mercury, and berylli- Under the provisions of the Act, new facil- um. Controls have been required for indus- ities can be located in a polluted area if they tries that produce these substances at high are able to offset their emissions by reducing rates. To date, the oil shale industry has not the emissions of other industrial plants in the been included under the regulations for these same area. This strategy may be feasible in pollutants because it is expected that they urban industrialized areas, especially where will be generated at low levels, if at all. How- existing facilities are old and do not employ ever, EPA is in the process of developing haz- state-of-the-art air pollution control methods. ardous emissions standards for POM, arse- It is not applicable to the oil shale areas at nic, and possibly other substances. It does not present because there are few industrial fa- appear at this time that these substances will cilities against which to offset new emissions. be regulated for oil shale operations, but the It probably will continue to be inapplicable as regulations could be applied to oil shale if the the area industrializes, because any new substances are found in the emissions plants will be built with the best available streams during future characterization stud- control technologies to reduce emissions to ies. Furthermore, it is also possible that addi- minimum levels. A subsequent oil shale devel- tional regulations could be promulgated for oper would thus be forced to improve on these substances that have already been detected control methods. It is uncertain whether this in these streams. could be done at reasonable cost. It should also be noted that a recent U.S. These constraints could result in each oil Circuit Court of Appeals decision in the case shale plant being surrounded by a buffer of Alabama Power, et al. v. EPA may result in zone in which no additional industrial activ- significant changes in the PSD regulations. ities (including oil shale development) would The definition of baseline conditions, fugitive be allowed. Without reliable regional air dust control requirements, and monitoring re- quality modeling studies, it is impossible to quirements are among the issues on which predict the width of these buffer zones, How- the court has rendered a decision. As a result ever, it is very possible that such zones could of the decision, EPA proposed certain revi- substantially reduce the area of a given oil sions to the PSD regulations on September 5, 290 . An Assessment of Oil Shale Technologies

1979. However, the effect of the court deci- all prospective oil shale developers prior sion and the proposed regulations on the con- to their preparation of PSD applications. ditions for PSD permits for oil shale facilities This effort would seek a coordinated is unclear at this time. strategy for maximizing shale oil production while maintaining the ambient air Policy Options quality at regulated levels. Implementa- tion could be constrained by, for exam- LIMITS ON DEVELOPMENT ple, antitrust laws. Siting constraints will probably not be Alter existing regulatory procedure in al- severe for an oil shale industry of 200,000 to location of PSD increments. Under this 400,000 bbl/d. However, it appears likely that option, EPA would allocate a portion of a large industry (the order of 1 million bbl/d) the total PSD increment to each firm could encounter siting difficulties because of when it applied for a PSD permit. The re- the Class H status of the resource region, the maining portions of each increment possibility that the initial facilities will ex- would be reserved for future industrial haust the total PSD increments over large growth. Although this option would areas, and the existence of Class I areas near allow for a certain level of additional the region. If this appears to be the case, growth, it could impose technical and there are several possible actions that could economic burdens on the individual ap- be taken. These are briefly described below. plicants, because each proposed facility would be required to maintain lower Retain the current regulatory structure. emission levels than would be the case This option would not alter existing air under the existing regulatory structure. quality standards and PSD regulations Redesignation of the oil shale region as promulgated under the Clean Air Act. from a Class II to a Class III area. This Under existing law, all oil shale facilities option would lower air quality but would would have to undergo a preconstruc- allow for more industrial development. tion review before a PSD permit would The action would be initiated at the be granted. The use of BACT would be State level, with final approval being required, and the developer would have necessary from EPA. The following cri- to demonstrate that air quality regula- teria would have to be satisfied: tions would not be violated either within the Class II area of development or in —the Governors of Colorado, Utah, or nearby Class 1 areas. As indicated previ- Wyoming must specifically approve ously, the current policy of allocating the redesignation after consultation PSD increments on a first-come, first- with legislative representatives, and serve basis might constrain the commer- with final approval of local govern- cialization of those technologies that are ment units representing a majority of in the early phases of development, and the residents of the area to be redesig- in addition might limit the ultimate size nated; of an oil shale industry within the re- —the redesignation must not lead to pol- source region. lution in excess of allowable incre- Coordinate issuance of PSD permits for ments in any other area; and oil shale plants. This option would not —other procedural and substantive re- alter existing PSD regulations as promul- quirements for redesignation under gated under the Clean Air Act. However, State and Federal law must be satis- it would change the current approach to fied. the issuance of PSD permits for oil shale While such an option would appear to plants by EPA. Rather than issuing PSD allow for about twice as much oil shale permits on a first-come, first-serve basis, development as is presently possible EPA would encourage coordination with under a Class II area designation, con- Ch. 8–Environmental Considerations ● 291

straints would still occur because of the ance basin and an unknown amount in nearby Class I areas. Utah and Wyoming, but at the cost of in- Amend the Clean Air Act. This congres- creased air pollution. sional option would exempt the oil Shale region from compliance with certain provisions of the Clean Air Act. Con- IMPROVE TECHNICAL INFORMATION gress might direct EPA and the States in Additional analysis is needed of the poten- question to redesignate the oil shale re- tial effects of oil shale development on air gion from a Class 11 area to a Class 111 quality. Such analysis will be useful in identi- area, and to exempt the oil shale devel- fying long-term R&D needs in protecting air opers from maintaining the visibility and quality and in identifying siting problems im- air quality of nearby Class I areas. This posed by existing air quality regulations and option would remove the major uncer- standards. Some options for improving the tainties surrounding the siting of oil quality of technical information might in- shale facilities within the resource re- clude: the further development of existing gion itself, and would remove any siting R&D programs, the coordination of R&D work barriers connected with the degradation by Federal agencies, the redistribution of of nearby Class I areas. Such an option funds within agencies for air quality re- would allow development up to the Class search, increased appropriations to agencies III standards, which permit lower air to accelerate their air quality studies, and the quality than Class II standards. Thus, passage of new legislation specifically tied to this option would allow an industry of up funding R&D relating to air quality impacts at to 800,000 bbl/d to be sited in the Pice- various levels of oil shale development.

Water Quality Introduction might be released. Much work has been done to describe the quantity and quality of sur- Development and operation of oil shale fa- face and ground water resources in the oil cilities could contaminate surface and ground shale region. However, little is known about water from point sources such as cooling wa- the nature and ultimate impacts of the pollut- ter discharges, nonpoint sources such as run- ants produced by oil shale processing. For ex- off and erosion, and accidental discharges ample, a number of these pollutants may be such as spills from trucks, leaks in pipelines, carcinogenic, mutagenic, and teratogenic.* or the failure of containment structures. The Information is not available on the risks pollutants could adversely affect aquatic posed by these pollutants at the levels likely biota, irrigation, recreation, and drinking to be encountered in the surface and ground water. The severity of these impacts will be water affected by oil shale development. determined by the scale of operation, the In this section: processing technologies used, and the types and efficiencies of the pollution controls. . The types of wastewaters produced by oil shale operations are characterized. The water systems may be affected during ● Rates for the generation of these con- the operating lifetime of an oil shale facility, taminants are estimated. and such long-term impacts as those from the ● Potential impacts of effluent streams on leaching of disposal piles could continue for surface and ground water are identified. many years after operations ceased. Accu- rate prediction of the impacts requires an understanding of the characteristics, trans- *(krcino~ens cause cancer. Nlutagens cause mut[ltions in port routes, and fates of the pollutants that offspring. ‘1’era togens cause fetal defects. 292 ● An Assessment of 011 Shale Technologies

● The quality of surface and ground water Pollution Generation resources in the oil shale region is examined. The following discussion examines the ● The applicable Federal and State water types of effluents generated by various oil quality regulations and standards are shale processes. Where data are available, described. the rates at which these effluents are pro- ● The effects of these regulations and duced by different types of facilities are standards on a developing oil shale in- estimated. dustry are analyzed. ● The pollution control strategies that may Unit Operations and Effluent Streams be applied are described and evaluated. The net rates at which pollutants will be Mining will produce dusty air and gases emitted in treated streams are then esti- that must be cleaned to protect the miners. mated. Wet scrubbing of this mine ventilation air will ● Procedures for predicting and monitor- produce wastewater streams that will have ing compliance with water quality regu- to be treated. If the shale deposits are located lations are discussed. in ground water aquifers, then mine drainage ● Issues and R&D needs are summarized. water will be produced that must be con- ● Policy options are discussed. sumed, discharged to a surface stream, or re-

1%0(0 credit OTA staff Mine dewatering at tract C-a— water quantity has been greater than anticipated at this site Ch. 8–Environmental Considerations ● 293

injected into the aquifers. The drainage wa- produce significantly different quantities of ters will contain inorganic salts, chloride and wastewater with different types and concen- fluoride ions, and boron. They should not con- trations of contaminants. For example, a tain significant concentrations of dissolved Claus/Wellman Lord sulfur recovery system gases or organic chemicals, although dis- would produce a neutralized acidic wastewa- 15 solved H2S may be found in some locations. ter; a Stretford sulfur absorption unit would Retorting produces water by combustion of not. hydrogen, by release of moisture present in Steam generation and water cooling.— the feed shale, and by chemical decomposi- High-quality water must be used to generate tion of kerogen. In some aboveground retorts steam for power generation or process needs. (such as TOSCO 11 and Lurgi-Ruhrgas), this Generally, the boiler feedwater must be water is entrained in the retort’s gas stream treated to remove inorganic salts. The treat- and is condensed when the product gas is ment (usually lime softening or ion exchange) cooled. This “gas condensate” will be con- generates liquid wastes. In addition, the

taminated with NH3, CO2, H2S, and volatile or- water in a boiler becomes concentrated in ganics, but will not contain appreciable quan- dissolved materials, and a portion must be tities of inorganic salts. In other processes continually replaced with freshwater. The (such as in situ retorting or the Paraho or chemical species in the boiler wastewater Union “B” aboveground retorts) some of the (blowdown) will be similar to those in the raw water may condense within the retort or in water, but they will be more concentrated. the oil/gas separators. This “retort conden- Wet cooling towers will be used to cool the sate’ will contain H2S, NH3, CO2, and dissolved organics, plus inorganic salts that water that is used in heat exchangers. Cool- have been leached from the shale in the re- ing towers work by evaporating a portion of tort, Trace elements and toxic metals could the water passing through them. This evap- also be present. oration concentrates the chemicals that enter with the feedwater, just as in a boiler. The Upgrading will include several operations: water that must be removed to control the ac- gas recovery, hydrogen generation, gas-oil cumulation of solids (blowdown) will be chem- and naphtha hydrogenation, delayed coking, ically similar to the feedwater but will also

NH 3/acid-gas separation, foul-water strip- contain chemicals that are added to control ping, and sulfur recovery. Gas recovery and the growth of algae in the tower. hydrogen generation produce little wastewa- Spent shale disposal. -Spent shale from ter. However, hydrotreaters and cokers pro- aboveground retorting will be exposed to duce foul condensates that are contaminated leaching by rainfall, snowmelt, or irrigation with dissolved gases and organics. Gases are water. If wastes are disposed of by backfill- usually removed within the upgrading unit. ing mines, they may be leached by ground Thus, the principal pollutants in the final ef- water. Leachates from various spent shales fluent stream are dissolved organic com- have been studied by a number of investi- pounds. 16 17 gators. Their properties vary widely with Air pollution control.—Dust scrubbers and the retorting process but in general they con- water sprays will produce an effluent that tain significant concentrations of total dis- contains suspended solids and dissolved in- solved solids (TDS), sulfate, carbonate, bicar- organic salts. Effluent streams from gas bonate, and other inorganic ions, and lesser cleaning devices will also contain solids and amounts of trace elements and organic com- salts as well as HC, H2, NH3, phenols, organic pounds. They are alkaline, with pH values acids and amines, and thiosulfate, and thio- ranging from 8 to 13. Their addition to the cyanate ions, The principal sources of waste- naturally occurring waters in the oil shale re- water will be scrubbers and units for the region could result in significant water quality 14 covery of sulfur and NH3. Different devices changes, but the severity of the risk is diffi- 294 ● An Assessment of Oil Shale Technologies

Table 51 .–Generation Rates for Principal Water Pollutants for cult to ascertain. For example, one leachate a was tested according to EPA procedures, and Production of 50,000 bbl/d of Shale Oil Syncrude (tons/d) the spent shale could not be classified as a Type of retortinq facility hazardous waste on the basis of its trace ele- Aboveground Aboveground MIS/ ments and toxicity .18 However, some spent direct indirect MIS aboveground shales could be classified as hazardous be- Gas condensates 19 NH . 75.6 147 276 189 cause of the presence of organic residues. 3 H 2 S 0.9 23 15 1.1 co 136 17.5 541 371 Leaching of in situ retorts.—In situ retort- 2 ing presents an environmental problem be- BOD : : 19.2 285 18,5 127 Subtotal 232 63 837 574 cause ground water is found in many of the Retort condensates deposits to which this process could be ap- NH3 (b) (b) 3,5 2.4 H S. . . (b) (b) – – plied. The increases in permeability that 2 co2 (b) (b) 48.2 331 would result from mining, fracturing, and re- BOD ., (b) (b) 10.1 7.3 torting would facilitate leaching after dewa- Subtotal – — 62 43 tering operations are discontinued. Soluble Upgrading condensates NH . 134,2 1342 134,2 134,2 materials in the spent shale would thus enter 3 H 2 S 58.8 58.8 58.8 58.8 the ground water and would eventually reach co* 1,4 14 14 1.4 surface streams. Such transport would take BOD 3.7 37 37 3,7 long periods of time. However, if aquifers are Subtotal 198 198 198 198 contaminated, cleanup would be virtually im- Blowdown and waste treatmentc Ca/Mg/Na d 60 6.3 12,2 11 2 possible. Chloride. 5.3 57 09 0.8 Fluoride ., – — 03 0.2 Sulfate 6.5 6.8 8.4 76 Summary of Pollutants Produced by Subtotal 18 19 22 20 Major Process Types Mine drainage treatment CO3 =/ HCO3 -e (f) (f) 23,1 23,1 Boron (f) (f) 01 0.1 Approximate rates of generation of major Ca/ Mg/Nad. (f) (f) 145 14,5 pollutants are summarized for four facilities Chloride (f) (f) 0.7 0.7 in table 51. * Five factors should be kept in Fluoride. (f) (f) 05 0.5 Silica. ., ., (f) (f) 05 0.5 mind in reviewing this table: Sulfate (f) (f) 126 12.6 — — ● The rates are for the generation of pol- Subtotal 52 52 lutants—not for their release to the en- Total, 488 295 1,171 887

vironment. The rate of release will be de- a;ons per stream day bAssumes above-ground retorts operated a! temperatures that do not Produce condensate termined by the strategies that are used cln~]”de~ water pretreatment Above-ground plants use Colorado Rwer wafer MIS and MIS’ to remove the contaminants. above-ground plants use mme drainage waler ● dGalclum magnesium and sodium Ions Retort condensates are not shown for ecarbonale and bicarbonate IOnS the AGR processes because it is as- fAs~umes above-ground relorflng plants are not located w ground water areas sumed that the retorts will be operated SOURCE Of ftce of Technology Assessment at temperatures that will avoid condensation of water vapors within the retort. fleets present developer proposals. It This should be achievable with most re- would not be valid for future plants in torting systems. However, others (like the center of the Piceance basin. the Union “B”) may produce substantial ● No retort leachates are shown for the quantities of retort condensate. MIS retorts because the rate of leaching ● No mine drainage water is shown for the and the efficacy of control systems can- aboveground plants because it is as- not be accurately estimated. One study sumed that they will not be sited in estimated that a commercial MIS facility ground water areas. This assumption re- might yield over 2,000 ton/d of soluble salts, but only crude estimates were 20 *See app. C for details, made of the rate of release. Ch 8–Environmental Considerations ● 295

No rates are shown for trace elements, increase over 500 mg/1, treatment for munici- heavy metals, or toxic organic chemicals pal and industrial water users becomes more because these are produced in much costly, and the yield of irrigated farmlands smaller amounts than the major pollut- might be reduced. 29 For public drinking water ants. However, they can be both more supplies, EPA recommends limits of 500 mg/1 hazardous and more difficult to re- for dissolved solids and 250 mg/1 for both move.21-28 chlorides and sulfates. 30 The estimates indicate that MIS processing on tract C-b will produce the greatest quanti- Oil and Grease ty of wastewater contaminants for treatment, Because large amounts of shale oil will be mostly because of the large gas condensate produced, processed, and transported, there stream. A substantial difference is shown be- is a possibility of oilspills. If they cannot be tween the aboveground direct and above- contained or removed, detrimental impacts -ground indirect plants with respect to the would occur to aquatic biota. Small spills, rates at which pollutants are generated in the such as from pipeline leaks, could cause local gas condensate streams: the directly heated damage. If undetected, the long-term impacts facility produces about four times as much could be substantial. Oil and grease in public dissolved gas (largely CO2 and NH3). This is water supplies cause an objectionable taste because more air is introduced into directly and odor, and might ultimately endanger pub- heated retorts. The trend is consistent with lic health. the even higher gas condensate production of the MIS retorts, which are also assumed to be Suspended Solids directly heated. Sedimentation problems will be increased Effects of Potential Pollutants on because large amounts of land will be disturbed, which will increase the area’s sus- Water Quality and Use ceptibility to erosion. Suspended solids make Salinity surface water cloudy and increase its temperature, thereby affecting aquatic life. Sus- Oil shale development could increase the pended solids in industrial waters can dam- salinity in surface and ground water systems age some types of equipment. through two processes: Concentration of naturally occurring Temperature Alteration saltwater as high-quality water is with- An industry may alter stream tempera- drawn for consumptive uses. (This effect tures by discharging warm waste streams, by is discussed in ch. 9.) consuming cool water, or by lowering the Salt loading from leaching of waste dis- ground water table. Discharges from power- posal piles and in situ retorts, from re- plants could also increase temperatures, but lease of saline mine or process waters, the developers do not expect to do this. The and from ground water disturbances construction of new reservoirs could also caused by reinfection. alter stream temperatures. While tempera- Salinity increases are a significant problem ture is not a critical factor in water for in- because as water becomes more mineralized, dustrial use, for drinking, or for irrigation, its municipal, domestic, ecological and agri- tion, wildlife, Federal lands, and Indian reservations all com- cultural utility is reduced. * If dissolved solids pete for its waters. PresentIV, salinity of the Colorado River at IIoover Dam is 745 mgl. Unless efficient control technologies “I’his is of ma jor importance because the Colorado River sys- can be employed, estimates have indicated that a large oil tem is one of the most important river systems in the South- shale industry has the potential, due to salt loading and salt west. I t serves :~pproxima tel~’ 15 m i]iion people. ~funicipalit ies, corwent ration, to increase the salinity level a t Hoover Dam bv agrirul t u re, energv proriuc t ion. i ncfus t rv and mining, recrea- several mg 1. — —

296 ● An Assessment of Oil Shale Technologies large variations would affect all aquatic life, Microbial Contamination both directly and indirectly (e.g., by influenc- ing their susceptibility to disease and toxic The microbial contamination of surface compounds. )3] Because the Colorado River waters could occur if rapid population system is large, and variations in water tem- growth overloads sewage treatment facil- peratures occur naturally, it is not expected ities. (See ch. 10 for a discussion of the prob- that oil shale development will significantly lems of rapid growth.) Improperly treated affect its temperature. 32 sewage containing viruses, bacteria, and fungi could be released into the water system. These problems could be controlled by the Nutrient Loading construction or expansion of sewage treat- The potential sources of nitrogen and phos- ment plants. phorous are ground water discharge, runoff from raw and spent shale, municipal wastes, Water Quality in the Oil Shale Region and chemical fertilizers used for reclaiming land. These nutrients would adversely affect The current properties of the water define nearby surface waters, but the effect on the how it must be treated before it can be used total river system is uncertain. The overall in oil shale facilities. More importantly, they impact will depend on where the facilities are define the level to which wastewater must be located and on the degree of waste treatment treated before it can be discharged. In gener- used. al, regulations do not permit the discharge or reinfection of wastewater unless it is at least Toxic Substances as pure as the receiving stream or aquifer. As indicated by the data in table 52, the quality Sources of toxic trace elements and organ- of surface streams is highly variable. It also ic chemicals include stack emissions from tends to deteriorate between upstream and processing operations, chemicals used in up- downstream reaches, as exemplified for Pice- grading and gas processing, leachates from ance Creek east and west of tract C-b. All of raw and retorted shale, and associated in- the streams described in the table satisfy the dustrial and municipal wastes. These sub- standards promulgated by EPA and the U.S. stances are of concern because of their po- Public Health Service for the maintenance of tential impact on aquatic life, and on human aquatic life and wildlife. Moreover, with the health through drinking water supplies and exception of Evacuation Creek, all are suit- irrigation. Concentrations of certain minerals able for irrigation water supplies and for live- in the region’s water already exceed the lim- stock watering. Evacuation Creek’s boron its set for certain water uses. * Oil shale de- content exceeds the irrigation standard, and velopment could increase these levels and its dissolved solids level exceeds the livestock could also add other toxic contaminants. For watering standard. However, none of the example, cadmium, arsenic, and lead, and streams satisfies the standards for public other heavy metals could be leached from drinking water. The standard for dissolved spent shale piles. Organic compounds (phe- solids is exceeded by all the streams, espe- nols, benzene, acetone) that are suspected cially Yellow Creek and Evacuation Creek. carcinogens and that have been identified by Evacuation Creek also exceeds the standard EPA as high-priority hazardous water pollut- for boron, sodium, and sulfate ions. The sodi- ants also are found in oil shale process um standard is also exceeded by Yellow waters. Creek, and the sulfate standard by all three creeks and the spring. *For example, the boron content in Eva ma lion Creek, near Ground water is generally of poorer quality lease tracts U-a and U-b exceeds the irrigation standard. See the next section on water quality in the oil shale region for a than surface streams. The quality of alluvial more detailed discussion, aquifers and of the upper and lower bedrock Ch. 8–Environmental Considerations ● 297

Table 52.–Quality of Some Surface Streams in the Oil Shale Region (mg/l)

Basin Piceance Uinta Piceance Piceance Piceance Piceance Piceance Uinta Piceance Creek Piceance Creek Spring at Evacuation Stream Colorado River White River east of C-b west of C-b Yellow Creek WIIIOW Creek Wallow Creek Creek

Reference 14 15 16 16 17 16 16 15

b Ammonia NA 006 NA NA 0.153 01 01 006 Bicarbonate 168 241 542 601 1,470 606 540 575 Boron NA 0088 NA NA 0.642 0.2 0.6 1. 95 Calcium 72 72 70 79 319 143 161 214 Carbonate NA 02 00 00 118 01 01 00 Chloride 205 42 16 14 124 40 08 66 Dissolved solids 734 551 718 944 2,430 995 910 4,948 Fluoride NA 003 10 0.7 2.09 17 14 09 Hardness NA 299 NA NA 541 576 516 1400 Magnesium 19 29 47 69 112 53 28 209 pH NA 82 82 82 87 79 7.9 79 Silica 70 13 16 17 105 13 13 10 Sodium 153 78 130 160 746 138 125 972 Sulfate 158 188 170 300 550 350 310 2.889 aSee reterence IISI bDala not ava(lable SOURCE Office of Technology Assessme~t ground water aquifers in the Piceance basin Table 53.–Quality of Ground Water Aquifers near Federal lease tracts C-a and C-b is in the Piceance Basin (mg/l) shown in table 53. * Water from the alluvial Aquifer Alluvial Alluvial Upper Lower and upper aquifers could be used for irriga- Referenced 17 16 16 16 tion, but its high dissolved solids content Ammonia 0337 NAb NA NA could harm many crops, Water from the low- Bicarbonate 573 1,220 550 9,100 Boron 1 25 NA NA NA er aquifer could be used only with very toler- Calcium ., 102 57 50 74 ant plants on permeable soil, and that from Carbonate 11.4 NA NA NA some portions of the aquifer could not be used Chloride 17.9 42 16 690 Dissolved solids 1,190 1,750 960 9,400 at all because the lithium and boron concen- Fluoride 0367 46 14 28 trations would be toxic to many plants. Ex- Hardness 600 NA NA NA cept for the lower aquifer, the ground water Magnesium 839 80 60 95 pH 65 NA NA NA resources could be used for livestock, All of Silica NA NA NA NA the water would be suitable for maintenance Sodium. 202 490 210 3,980 of aquatic life and wildlife. Sulfate 467 430 320 80 None of the aquifers meets drinking water aSee reference IIsl bDala not avadable standards. Special problems are encoun- SOURCE Off Ice of Technology Assessment tered with boron, which in one sample of lower aquifer water exceeded the drinking water 34 standard by a factor of 320. Also, the aver- Water Quality Regulations age fluoride concentration in lower aquifer water is about 28 times the drinking water 35 Regulations for the maintenance of surface standard. Dissolved solids concentrations in and ground water quality have been promul- the lower aquifer range from a level that gated under the Clean Water Act and the would satisfy drinking water standards (500 Safe Drinking Water Act. They are imple- mg/1) to over 40,000 mg/1, A concentration of 36 mented at the Federal and State levels, to- 63,000 mg/1 was reported for one sample. gether with additional State standards. In the “I’he grounci water resources of the Piceance basin are de- following discussion, the provisions of these scribed in ch. 9. The bedrock aquifers are separated by the oil shale deposits of the !vlahogany Zone. Alluvial aquifers are Acts that are of particular significance to oil genera]ly found near the surface in valley walls and floors. shale are emphasized.

63-898 0 - 80 - 20 298 . An Assessment of Oil Shale Technologies

The Clean Water Act be monitored and regulated with some precision, and they are suited to the application of The objective of the Federal Water Pollu- control devices. Nonpoint sources are sites tion Control Act (FWPCA) is “to restore and from which there is uncollected runoff. Exam- maintain the chemical, physical, and biologi- ples are irrigated fields and waste disposal cal integrity of the Nation’s waters. ” In 1972, areas. They present regulatory and techno- FWPCA was amended to establish a complex logical difficulties, and as a result, they are program to clean up the Nation’s waterways subject to less stringent legal controls. by limiting the effluents of all classes of polluters. These limits were to be tightened until FWPCA established a complex regulatory the ultimate goal of no pollution discharge scheme to control pollution from industrial into navigable waters was achieved. The min- point sources: ing industry had difficulties meeting the re- ● by July 1977, all nonmunicipal polluters quirements of this program. Congress re- must use the “best practicable pollution sponded to these problems, and to the recom- control technology currently available” mendations of the National Commission on (BPT); public sewage works must use Water Quality, by further amending the Act secondary treatment; in 1977. The amended Act, now called the ● by July 1983, nonmunicipal point sources “Clean Water Act” refined FWPCA’s regula- must use the “best available technology tory scheme for point sources and empha- economically achievable” (BAT), munici- sized the control of toxic effluents. EPA, the pal sewage treatment plants must use Army Corps of Engineers, and the States are the “best practicable waste treatment responsible for implementing and enforcing technology;” this Act. ● special effluent standards for toxic pol- The goals of the Act are: lutants must be met prior to the 1977 deadline; ● the discharge of pollutants into naviga- ● new facilities must use the “best avail- ble waters shall be eliminated by 1985; ● able demonstrated control technology;” wherever attainable, water quality and which provides for the propagation of ● special restrictions, based on ambient fish, shellfish, and wildlife and for rec- water quality standards, must be used if reation in and on water, shall be the national effluent standards will not achieved by July 1, 1983; ● meet water quality targets in a given discharge of toxic pollutants in toxic basin. amounts shall be prohibited; and ● a major R&D effort shall be made to de- The 1977 amendments changed this frame- velop- the technology necessary to elimi- work: the July 1977 BPT deadline was ex- nate the discharge of pollutants into the tended until April 1, 1979, for point-source navigable waters, the waters of the con- polluters who demonstrated a good-faith ef- tiguous zones, and the oceans. fort to achieve compliance, and the BAT provisions were completely revised. Industrial To achieve these goals, emissions standpoint-source pollutants were divided into ards are to be set to limit discharges from three classes—toxic, conventional, and nonpoint and nonpoint sources, and ambient conventional. Each is treated differently. standards are to be established for the quali- Toxic pollutants cause death, disease, behav- ty of surface waters. ioral abnormalities, cancer, genetic muta- Effluent standards. —Different ap- tions, physiological malfunctions, or physical proaches are used for control of point and deformations in any organisms or their off- nonpoint sources. Point sources release a col- spring. Sixty-five toxic pollutants must meet lected stream of pollutants through sewers, the BAT standards by July 1, 1984; others pipes, ditches, and other channels. These can must meet BAT standards within 3 years Ch. 8–Environmental Considerations ● 299 after effluent limitations are established. Table 54.–Effluent Limitations for Petroleum Refineries Using Conventional pollutants include biological Best Practicable Pollution Control Technology (BPT) oxygen-demanding substances, suspended (pounds per 1,000 bbl of feedstock) solids, fecal coliform, and changes in pH. Average of daily values They are subject to the application of “best Maximum for for 30 consecutive conventional control technology” by July 1, Effluent characteristic any 1 day days shall not exceed 1984. In general, this standard is less strin- Biochemical oxygen demand (BOD 5 ) 192 102 gent than the BAT standard. Nonconvention- Total suspended solids 132 84 al pollutants—those classified as neither tox- Chemical oxygen demand 136 70 011 and grease 60 32 ic nor conventional—will be subject to the Phenolic compounds 014 0068 BAT standards no later than July 1, 1987. Ammonia as N 83 38 Sulfide 0124 0056 Specific limits on these effluents must be Total chromium O 29 017 adhered to by individual polluters. In prac- Hexavalent chromium 0025 0011 tice, effluent limitations are developed by pH Must be within the range of 6.0 to 90 EPA for each industry. No discharge of any SOURCE E R Bales and T L Thoem feds j Pololoo Coflrro GUAInI-e lo, 0 .Wk Lle~eoo pollutant from a point source is allowed un- menl Append/x Envlro!lfnenldl ProtectIon Agency Cinclnnaft Ohio July 1979 0 D 9 less a National Pollutant Discharge Elimi- nation System (NPDES) permit has been the following wastewater management proce- granted. To obtain a permit, the polluter must dures: meet the applicable effluent limitations, tech- sour water stripping to reduce NH3 and nology standards, and water quality goals. H2S; Permits are obtained from EPA or from the in- ● segregation of sewers; dividual States, if they have taken over the ● no discharge of polluted cooling water; regulatory role. Cancellation of permits for and noncompliance is one method of enforcing the oil, solids, and carbonaceous wastes re- Act, because without a permit, many industri- moved just prior to discharge. al operations cannot be carried out. It should be noted that permits do not simply recapitu- The BAT standards illustrated in table 55 late the effluent guidelines; additional ambi- were defined using additional treatment ent standards may also be imposed. Table 55.–Effluent Limitations for Best Available Technology Special attention is given to new sources Achievable (BAT) for Petroleum Refinery Facilities and to sources that discharge into publicly (pounds per 1,000 bbl of feedstock) owned treatment works. In practice, performance standards for new sources are often Effluent Iimitations equivalent to the 1983 BAT limitations devel- Average of daily values Maximum for for 30 consecutive oped for existing industries. Any new source Effluent characteristic any 1 day days shall not exceed that complies with an applicable standard of Biochemical oxygen demand performance is not to be subjected to more (BOD 5 ) . 32 2.6 stringent standards during the first 10 years Total suspended solids. 3.0 26 Chemical oxygen demand 168 134 of operation. 011 and grease 060 0.48 Expected effluent limitations for oil shale Phenolic compounds 0015 0010 Ammonia as N. 20 15 facilities.—EPA has not yet developed stand- Sulfide . 0066 0042 ards of performance for oil shale facilities. Total chromium 015 0.13 Hexavalent chromium, 0.0033 0.0021 However, standards have been established pH Must be within the range of 6.0 to 9.0 for petroleum refining, which has several SOURCE E R Bales and T L Thoem {eds I f%luton Coofro/ Gwddnce Pm 0// 5?M/e Deve/op- similarities. The BPT standards shown for pe- rnenf Appendix Enwronmental Protect(on Agency Cincinnati Ohio July 1979 p troleum refining in table 54 were based on c1 11 300 An Assessment o/Oil Shale Technologies methods now practiced by some petroleum for interstate waters. FWPCA required State refineries. These methods include: standards for intrastate waters as well. EPA will develop the standards if a State fails to ● use of air cooling rather than wet cooling towers; do SO. ● reuse of sour water stripper wastes; The ambient standards are the basis for ● reuse of cooling water in the water preventing the degradation of presently clean treatment plant; waterways. The regulations provide, without ● using treated wastewater as coolant qualification, that “No further water quality water, scrubber water, and in the water degradation which would interfere with or treatment plant; become injurious to existing instream water ● reuse of boiler blowdown as boiler feed- uses is allowable. ” Thus, if a stream is suit- water; able for the propagation of wildlife; for swim- ● use of closed cooling water systems, ming; or for drinking water, then it must re- compressors, and pumps; main suitable for these uses. Because small ● use of rain runoff as cooling tower make- increases in pollutant loads may not be incon- up or water treatment plant feed; and sistent with protecting a possible present use, ● recycling of untreated wastewaters the States are allowed to decide whether “to wherever practical. allow lower water quality as a result of NSPS for petroleum refineries, based on a necessary and justifiable economic or social combination of BPT and BAT standards, are development. ” Such decisions cannot be ap- shown in table 56. New sources must meet plied to waters that constitute an outstanding discharge standards that reflect the greatest national resource (e.g., national parks, wil- degree of effluent reduction which the EPA derness areas), and they cannot allow water Administrator determines to be achievable quality to fall below the levels needed to pro- through application of the best available dem- tect fish, wildlife, and recreation. onstrated control technology, process alterations, or other methods including, where Before a State can issue a discharge per- practicable, zero discharge systems. mit it must have a program for reviewing and revising its water quality standards. EPA es- Federal ambient water quality stand- tablished the following guidelines for State ards.—The Water Quality Act of 1965 re- review and revision: quired the States to adopt ambient standards ● standards must be reviewed every 3 Table 56.–New Source Performance Standards for Petroleum years and revised where appropriate; Refineries (pounds per 1,000 bbl of feedstock) ● standards must protect the public health Effluent Imitations and welfare, and not interfere with Average of daily values downstream water quality standards; Maximum for for 30 consecutive existing standards must be upgraded Effluent characteristic any 1 day days shall not exceed where current water quality could sup- Biochemical oxygen demand port higher uses than those presently

(BOD5 ) 147 7.8 Total suspended solids. 9.9 6.3 designated; Chemical oxygen demand ~ ~ 104 54 ● existing standards must be upgraded to 011 and grease 4.5 2.4 achieve FWPCA’s 1983 goal of fishable Phenolic compounds 0.105 0.051 Ammonia as N 8.3 3.8 and swimmable waters, where attain- Sulfide 0093 0042 able. Attainability is to be determined by Total chromium ., 0220 0.13 environmental, technological, social, ec- Hexavalent chromium. 0.019 0.0084 onomic, and institutional factors; and pH ., Must be within the range of 60 to 90 ● existing water quality can degrade in SOURCE E R Bales and T L Thoem (eds I Po//uOofl CofMro/ Gwdance for Od Sha/e L7eve/op only specific instances, for example, if menl Append/x Environmental Protection Agency Clnclnnatl Oh[o July 197[1 p 012 existing standards are not attainable Ch. 8–Environmental Considerations . 301

because of natural conditions such as raw water uses (except contact recreation) leaching. without treatment, but with coagulation, sedimentation, filtration, and disinfection prior to Once an ambient standard is established, a use as domestic water supply. Temperature State must identify stream reaches for which limitations are also imposed. The water quali- the 1977 effluent limitations are not suffi- ty criteria for class CW are shown in table ciently stringent. For such areas, the State 58. In addition, Utah, like Colorado, has an must determine the total maximum pollutant antidegradation policy. loads that will allow the ambient standard to be met, This information is used to set more Table 58.–Utah Water Quality Standards stringent effluent standards. for Stream Classification CW Current State standards for Colorado and Parameters Criteria for CW streams Utah. —In Colorado, streams may be assigned Radioactive and chemical Drinklng water standards to one of four categories. Drainage from lease Settleable solids. 011, floating solids, Free from taste, odor, color, and toxic tracts C-a and C-b would discharge to the por- materials, turbidity, etc tion of the White River from the mouth of the Total coliform bacteria Less than 5,000 units per 100 Piceance Creek to the Colorado/Utah State milliliters Fecal conform bacteria Less than 2,000 units per 100 line. This area is in Colorado’s water cate- milliliters gory B2. These waters are suitable, or are to pH 65 to 85, no Increase >0.5 Biochemical oxygen demand (BOD ) Less than 5 milligrams per Iiter become suitable, for customary raw water 5 Dissolved oxygen >6.0milligrams per liter purposes (e.g., irrigation, livestock watering) Temperature Maximum 680 F except for primary contact recreation, * The SOURCE E R Bates and T L Thoem (eds I Polluf(on ComroI Gufdafice to{ Oh Shd,e Oeve/oj water quality criteria for category B2 are ment Appendtx Enwronmental Pro fecllon Aqenc~ Clncnnaf Ohio JIJY 1979 p listed in table 57. Colorado also has an anti- 021 degradation policy applicable to all streams. Proposed State standards.—FWPCA re- Utah has 11 stream classifications, Two quired the States to designate areawide pol- streams in and around oil shale tracts U-a lution control planning agencies. The Colora- and U-b, Evacuation Creek, and the White do West Area Council of Governments and River, are classified as CW (i.e., warm water the Uinta Basin Council of Governments have fisheries). Their waters are suitable for all been designated for the oil shale region. These agencies are to plan, promulgate, and *Prim:~rV ronttirl rerrc:)tifjn includes sw imrnin~, water ski- ing. and diving. implement a program designed to protect surface water quality. Stream classifications Table 57.–Colorado Water Quality and water quality standards are to be devel- Standards for Stream Classification B2 oped. The multiple-use classifications proposed for streams, which may supersede ex- Parameter Criteria for B2 streams isting classifications previously discussed, in- Settleable solids floating solids Free from clude: taste, odor, color and toxic materials ● Class I—aquatic life, water supply, Oil and grease Cannot cause a film or other discoloration recreation, and agriculture: Radioactive material Drinking water standards ● Class II—water supply, recreation, and Fecal conform bacteria Geometric mean less than 1,000 agriculture; units per 100 milliliters ● Turbidity Cannot increase more than 10 Class III—recreation and agriculture; units and pH 60 to 90 ● Class IV—agriculture. Temperature Maximum 900 F Change Streams 50 F The respective water quality criteria are Lakes 30 F shown in table 59. The classifications and the SOURCE E R Bates and T L Thoem (eds I Po/JufIorI ConfroI Go(dance for 01/ Sbd/e De,e)op quality criteria will apply to all streams in the rnenl Append/x Environmental Prolecl(on Agenc j Clnc(nnatl Ohio JuIy 1979 p D 20 oil shale region. 302 ● An Assessment of 011 Shale Technologies

Table 59.–Proposed Water Quality Criteria for Designated Uses

Parameter Water supply Aquatic life/ wildlife Recreation Irrigation Livestock a — — Alkalinity as Ca CO 3 ., ., . – 30-130 mg/l Aluminum-total ...... – 0.1 mg/l . 5.0 mg/lb, 20.0 mg/la C 5.0 mg/la Aluminum-dissolved ... ., – 0.1 mg/la — — Total ammonia as N, ., ., ., ., 0.5 mg/la — — — — Unionized ammonia as N . – 0,02 mg/l — — — Arsenic-total ., ., 0.01 mg/l 0.05 mg/l — 0.1 mg/l 0.2 mg/ld Barium-total, . 1,0 mg/l — — — Beryllium-total ., ... – 1,1 mg/l — 0.1 mg/lb, 0.5 mg/lC d — Boron ., ., . . ~ ~ ~ ., 1.0 mg/la — — 0,75 mg/le 5.0 mg/ld Cadmium-total ... ., ., ., ,0,01 mg/l 0.003 mg/l — O.O1b, 0.05 mg/lC 0.05 mg/ld Chloride-total. 250 mg/l — — — Chromium-total . . . 005 mg/l 0.3 mg/lf — 0.1 mg/lb, 1.0 mg/lC d 0.1 mgll Fecal coliform ., ., 2,000/100 ml f 2,000/100 mla 200/100 ml 1 ,000/100 ml 1 ,000/100 ml Color, ., ... ., ., .75 color unitsa — — — Copper-total. . ., ., .1.0 mg/l 0.030 mg/l — 0.2 mg/lb, 5.0 mg/lC 0.5 mg/ld Cyanide...... , . ., .020 mg/l 0.005 mg/l — 0.2 mg/l 0.2 mg/1 Hardness ., ., ., ., ., – — — — — Iron-total. ., ., . – 1.0 mg/l — 5 mg/lb, 20 mg/la C — Iron-dissolved ., ... ..03 mg/l 0.3 mg/la — — — Lead-total ., 0.05 mg/l 0.03 mg/l — 5 mg/lb, 10 mg/lC f 0.1 mg/1 Manganese-total ...... 0,05 mg/l 1,0 mg/l — 0.2 mg/lb, 10 mg/lC d — Manganese-dissolved ., 0,05 mg/l — — — Mercury-total. ., ...... 0,002 mg/l 0,00005 mg/l — 0.00005 mg/la Molybdenum-total — — — 0.01 mg/lb, 0.05 mg/lC 0.5 mg/1 Nickel-total ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ – 0.1 mg/l — 0.1 mg/lf — Nitrate-tl, 10 mg/l — — 100 mg/l NO, + NO, 100 mg/1 Dissolved oxygen .. ~ ~ ~ ~ ~ ~ ~ ~ 40 mg/lf 5.0-6.0 mg/l min. 2,0 mg/l min. 2.0 mg/l 2.0 mg/1 pH ...... 5.0-9.0 6.5-9.0 6.5-9.0 4.5-9.0 a — Phenols ~ ~ 0.001 mg/l 0.001 mg/l — — a — — Total PO4 -P ., ~ ~ ~ ~ ., – 0.025 mg/l - Iakes Phthalate esters – 0.003 mg/l — — — PCB ., ., – 0.000001 mg/l — — — Selenium-total ., . 0.01 mg/l 0.05 mg/l — — O 5 mg/1 Silver-total. ., ., . . 0.05 mg/l 0,0001-0,0025 mg/lg — Silver-dissolved – 0.0001 mg/l — Sodium ., ., ~ ~ .270 mg/la h — — — Sulfate-total. ., . ., ., ., 250 mg/l — — — — TDS ., ., 500 mg/la — — (1) 3,000 mg/la TSS ... ., ., ., – 25 mg/l-medianj — — — H 2 S (undissociated) ., ., ., 0.05 mg/l 0.002 mg/l Temperature ...... , – (k) — — Zinc-total. ... . 5.0 mg/l 0.03 mg/l — 2,0 mg/l 25 mg/ld

Unless otherwise mdtcaled the recommended cr!tena correspond with proposed State standards hMaxlmum concentration for a moderately restricted sodwm diet aCWA 208 recommendation only (no proposed State standard) Iwaler from which no detrimental effects WIII usually be nohced 500 mg/1 bCon11nuou5 Irrlgatlon, atl sods (match WOCC proPosed State standards) Water which can have detrimental effects on sensdwe crops 500-1000 mg/1 cshofl.~erm {rrlgatlon, neutral to alkaline fme Iexlured soils Waler that may have adverse effects on many crops and requires careful management dFor agrlcultura[ uses the WOCC except In a few Instances dld not dlshngulsh between lrrl9a- prachces f ,000-2000 mg/1 tion and hvestock uses The CWA 208 attempted 10 distinguish the differences Therefore, under Water fhat can be used for folerant plants on permeable SOIIS wlfh careful management hvestock there are numerous differences between 208 and WOCC numbers Under Irrlgatlon The prachces 2,000-5000 mg/1 lower recommended crlterla match Wf3CC numbers IValue represents maxtmum Increase In amblenf concentraflon due 10 discharge eLong.term Irrlgatlon on sensltwe crops kC,old water maximum IS 200 C, warm water maximum IS 30° C, and both Categories hmlt temper- fDlffers from proposed State standards ature changes to 3° C gLlmitlng concentration dependent on hardness

SOURCE E R Bates and T L Thoem (eds I Po//uf/orI Cmrfro/ Gu/darrce for 01/ Sfra/e Oeve/oprrrerrl Append/x, Enwronmental Protection Agency, Clncmnal{, Ohio. July 1979 pp D-29-D-30

The Safe Drinking Water Act of 1974 gram for ground water protection. It is administered by EPA and by the States. This Act protects drinking water systems through primary and secondary ambient The primary standards are intended to standards, monitoring programs, and a pro- protect health to the extent feasible, given the Ch 8–Environmental Considerations ● 303 restraints of existing treatment techniques Table 61 .–Proposed Secondary Drinking Water Regulations and their costs. Interim standards were is- Pollutant Proposed level Principal effects sued by EPA during 1975 and 1976 and were Chloride 250 mg/l Taste put into effect in June 1977 (see table 60). Color 15 color units Appearance These standards established both maximum Copper 1 mg/l Taste, fixture staining Corrosivity (Noncorrosive) Deterioration of pipes, unwanted contaminant levels and monitoring require- metals in drinking water ments for 10 inorganic and 6 organic chemi- Foaming agents O 5 mg/l Foaming, adverse appearance cals, radionuclides, microbiological contami- Hydrogen sulfide O 05 mg/l Taste, brown stains on laundry nants, and turbidity. A study by the National and fixtures Manganese .005 mg/l Taste, brown stains, black Academy of Sciences of the health effects of precipitates drinking water contaminants is to be the basis Odor 3 threshold Odor for revised primary standards. The study was odor number pH ., .. 65-8.5 mg/l Corrosion below 65. incrusta- completed in June 1977, but the revised tions, bitter taste, lowered standards have not yet been issued. germicidal activity of chlorine over 8.5 Secondary standards, published in 1977, Sulfate 250 mg/l Taste, Iaxative effects deal with contaminants that affect the odor Total dissolved solids 500 mg/l Taste, reduction in Iife of hot water and appearance of water but do not directly heaters, precipitation in cooking affect health (see table 61). They are not fed- utensils erally enforceable and are only guidelines to Zinc 5 mg/l Taste the States. The States may include monitoring SOURCE E R Bales and T L Thoem teds I Po//ufIorI Conlrol Gwdance for 0/1 S/We Uevekm rr?er?f Append/x Enwronmen[al ProtectIon Agency Clnclnnafl Ohio July 1979 0 requirements in their laws and regulations. D 33

Ground Water Quality Standards Table 60,–Primary Drinking Water Standards (mg/l) Federal.—The Safe Drinking Water Act Maximum concentration Inorganic chemicals (except fluoride) applies to deep-well injection of waste into Arsenic 005 aquifers with less than 10,000 mg/l TDS that Barium 10 are, or could become, sources of public drink- Cadmium 001 ing water. Seepage from pits, ponds, and la- Chromium 005 Lead 005 goons is not regulated at this time. Mercury 0002 Nitrate (as N), 100 Colorado. -No specific standards have Selenlum 001 been promulgated for ground water quality. Silver. ., 005 However, the basic standards applicable to Fluoride (degrees Fahrenheit) all other State waters do apply. Regulations 537 and below 24 are being developed that will limit the dis- 53.8to 583 ., 22 charge or injection of some contaminants. 584 to 63.8 20 63.9 to 70,6 1.8 Permits are now required for injection wells, 70.7 to 792 16 and they will be required in the future for 79 3 to 90.5 14 wastewater disposal in pits, ponds, and la- Chlorinated hydrocarbons Endrln 0.0002 goons if there is a possibility of discharge to a Lindane 0.004 ground water system. Methoxychlor 0.1 Toxaphene 0.005 Utah.—Utah also has no special standards Chlorophenoxys for ground water. However, ground water is 2, 4-D (2, 4-dichlorophenoxyacetic acid). 0.1 2, 4, 5-TP (Silvex) 0.01 considered part of the State waters, so general water quality standards do apply. Dis- SOURCE E R Bates and T L Thoem (eds ) Po//u1/on Comrol Gwdaoce for 011 Shale Develop menf Append/x Enwronmental Protecllon Agency Clnclnnall Ohio July 1979 pp D- charges to sources of potable water must not 32-D-33 cause the water quality to exceed drinking water standards. 304 ● An Assessment of 0il Shale Technologies

Implications of Water Pollution Control Standards mosis, electrodialysis, thickening, and evap- and Regulations for Oil Shale Development oration. As indicated above, the primary objective Chemical treatment devices use chemical of the Clean Water Act is to eliminate the properties or chemical reactions to remove discharge of pollutants into navigable waters contaminants. Such systems can destroy haz- by the late 1980’s. In order to accomplish this ardous substances that are not amenable to objective all potential polluters, including oil conventional physical and biological systems. shale developers, will be required to apply For oil shale wastewaters, the most impor- BAT, BPT, and NSPS. Point source discharge tant devices are those that could oxidize or- is well-regulated under the Act, and it is ex- ganic compounds or reduce salt concentra- pected that oil shale developers would comply tions. Included are ion exchange, wet air oxi- with the stipulations promulgated in regard dation, photolytic oxidation, electrolytic oxi- to NPDES. As will be discussed in the follow- dation, and direct chemical oxidation. ing section, the pollution control technologies that are being applied to oil shale wastewater Biological treatment devices contact a effluents are designed for zero discharge. waste with a population of micro-organisms However, in some instances (e.g., excess wa- that digest its organic contaminants. By con- ter from mine dewatering) it will need to be trolling the size of the population, and by ad- discharged back into surface waters or rein- justing oxygen and nutrient levels and equal- fected into underground aquifers. In this izing the conditions of the entering stream, it case, water will have to be treated to meet is possible to develop and acclimate micro-or- the standards stipulated under the NPDES ganisms that can nearly eliminate many haz- permit system or by the Safe Drinking Water ardous organic compounds. Biological treat- Act for reinfection—that is surface and ment systems can be divided into two groups: ground water quality criteria and water use classifications will have to be maintained as ● aerobic processes (such as activated stipulated by the States and EPA. In addition, sludge, trickling filters, rotating biologi- it is expected that oil shale facilities will have cal contractors, aerated lagoons, com- to meet NSPS comparable to those developed porting, and stabilization ponds) in for petroleum refining facilities. which the population is maintained under oxygen-rich conditions and the or-

ganic compounds are decomposed to CO2 Technologies for Control of Oil Shale and water; and

Water Pollution ● anaerobic processes (such as digestion) in which oxygen levels are relatively low Treatment of Point Sources* and the organic compounds are de- Contaminants may be removed from waste- graded to CO and methane gas. water by physical, chemical, or biological Treatment systems.—Most devices can re- means. For complex wastes, a series of de- move some but not all contaminants. In a vices using each of these principles will be treatment system, different wastewaters are necessary. sent to different devices, each of which re- Physical treatment devices apply gravity, moves a specific type of pollutant, The rela- electrical charge, and other physical forces tionships among contaminants, the streams in to contaminants to remove them from waste- which they are likely to occur, and the treat- water. Typical operations are gravity separa- ment processes of choice are shown in table tion, air flotation, clarification, filtration, 62. Although all contaminants may be found stripping, adsorption, distillation, reverse os- in nearly all streams, the streams associated with each contaminant have been limited to *De!ails of the various technologies are described in app. D. those in which concentrations will be high Ch. 8–Environmental Considerations 305

Table 62.–The Types of Contaminants in Oil Shale Wastewater ments. Mine drainage water may contain only Streams and Some Potential Processes for Removing Them dissolved solids. . . , Contaminant Stream Potential process The removal efficiencies, reliabilities, Suspended solids Mine drainage Clarification adaptabilities, and relative costs of some Retort condensate Filtration Cooling tower blowdown point source control devices are summarized Oil and grease Retort condensate Gravity separation in table 63. This information comes almost en- Gas condensate Emulsion breaking tirely from experience in other industries. Coking condensate Few of the technologies have been tested with Dissolved gases Retort condensate Steam stripping Gas condensate oil shale wastewaters, and none has been Coking condensate tested in the complex treatment trains that Dissolved inorganics Mine drainage Chemical oxidation will be necessary to deal with the wastes that Retort condensate Ion exchange will be encountered in commercial-scale oil Gas condensate Reverse osmosis Cooling tower blowdown Adsorption shale plants. The degree of adaptability of Ion exchange regenerants Evaporation each technology is particularly important Dissolved organics Retort condensate Solvent extraction because it indicates the likelihood that the Gas condensate Adsorption technique will transfer without difficulty to Coking condensate Biological oxidation Hydrotreating condensate Ultrafiltration the oil shale situation. Reverse osmosis Wet air oxidation Most suitable technologies.—The follow- Trace elements and Retort condensate Chemical oxidation ing technologies appear most suitable: metals Gas condensate Ion exchange Adsorption ● for oil and grease: dissolved air flotation Trace organics Retort condensate Ultrafiltration or coalescing filters; Gas condensate Reverse osmosis ● for dissolved gases: air or steam strip- Upgrading condensate Adsorption ping; TOXiCS Retort condensate Chemical oxidation Gas condensate Incineration ● for dissolved organics: rotating biologi- Upgrading condensate cal contractors or trickling filters for Sanitary wastes Domestic service Biological treatment first-stage removal, carbon adsorption,

SOURCE R F Probsleln H Gold and R E Hicks Wafer Reauwernertfs Po/kJ//on Effects and or wet air oxidation for polishing; Costs of Wafer Supp/y and Trealrnen( for the 0// Sha/e /ndusfry prepared for OTA by ● or Water Purlflcatlon Associates October 1979 for suspended solids: pressure multimedia filtration; ● for dissolved solids: reverse osmosis for first-stage removal, clarification for sec- enough to require removal prior to discharge ond-stage, and ion exchange for polish- or reuse. 37 38 ing; and ● for sludges: filtration and evaporation. Many of the devices listed in table 62 have been tested individually on oil shale wastewa- Costs.—Control costs depend on the oper- ters and have been found to provide some de- ating characteristics of the oil shale facility gree of control. 39-50 Of great importance is the and on the treatment methods selected. The performance of these units when combined to only published cost estimates were prepared form a “treatment train” for a specific for the Department of Energy (DOE). These wastewater. A separate train—consisting of estimates, upgraded for OTA to include the several individual treatment devices in cost of treating excess mine drainage water, series—will be needed for each stream be- appear in table 64. Total treatment costs cause, in general, each will contain different range from about $0,25 to $1 .25/bbl of shale types of contaminants, Each contaminant will oil syncrude. The low estimate applies to require a different type of removal process. aboveground retorting plants; the high to MIS For example, retort condensates may contain facilities in ground water areas. Although suspended solids, oil and grease, dissolved sizable, the control costs should not them- gases, organics, inorganic, and trace ele- selves preclude profitable operations. 306 ● An Assessment of Oil Shale Technologies

Table 63.–Relative Rankings of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost 011 and grease Dissolved air flotation 90 Very high Very high Medium Coalescing filter 99 High High Medium Clarification 80 Very high Very high High Dissolved gases Air stripping 80 High High Medium Steam stripping 95 Very high High Medium Flue gas stripping 95 High Medium Medium Biological oxidation High Medium Medium Low Dissolved organics Activated sludge 95 BOD/40 COD High Medium Low Trickling filter 85 BOD High Medium Low Aerated lagoon 80 BOD Medium Medium Low Rotating contactor 90 BOD/20-50 COD High Medium Low Anaerobic digestion 60-95 BOD High Medium Medium Wet air oxidation 64 BOD/74 COD Medium High Very high Photolytic oxidation 99 BOD Medium Very high Very high Carbon adsorption 99 BOD Medium High Medium Chemical oxidation 90 BOD/90 COD Very high Very high High Electrolytic oxidation 95 BOD/61 COD Medium Very high High Suspended solids Clarification 50 High High Medium Pressure filtration 95 High High Medium Multimedia filtration 95 Very high High Low Dissolved solids Clarification Low except for metals High Medium Medium Distillation 99 Medium Low Very high Reverse osmosis 60-95 Medium Medium Medium Ion exchange High High Low High Electrodialysis 10-40 Medium Medium Very high Sludges Thickening Product 6-8% solids Very high High Medium Anaerobic digestion Low High Medium Medium Vacuum filtration Product 20-35% solids High High High Sludge drying beds Product 90% solids Medium Low Medium Evaporation basins Product 95% solids Very high Low Low Filter press Product 35% solids Very high High High Aerobic digestion Low Low Low High

SOURCE Adapted from 4ssessrnerU of 0// Sfra/e Rerorf Wasfewa(er Trealrneru and ConVo~ Tec/rno/ogy, Hamllfon Standard Owlslon of Uruled Technologies July 1978 pp 2-12 to 2-24

Table 64.–Estimated Costs of Water Pollution Control in torts. For an aboveground retorting facility, Oil Shale Plants ($/bbl of shale oil syncrude)a the leaching problem may be reduced by dis- Above- Above- posal of the solid wastes in canyons, and cap- -ground ground MIS/ turing and treating any leachate that does oc- Wastewater stream direct indirect MIS aboveground cur. (See figure 61. ) It is hoped that the Gas condensate $0.11 $0.13 $0.45 $0.31 Retort condensate – — 0.13 0.09 moistened and compacted spent shale will be Upgrading impermeable to the flow of water. The top of condensate 0,12 0.12 012 0.12 the pile will be covered with topsoil or Excess mine drainage ., . – — 0-0.55 0-0.55 another growth medium that will be perme- Total . . ., $0.23 $0.25 $0.70-1.25 $0.52-1.07 able but that will not contain substantial aplants produce 50,1NI btjltd Of syncrude Aboveground plants are assumed to be not located In quantities of soluble contaminants. Any ground water areas Cost estimates include operating expenditures and capital amorhzatlon They also include nonwastewater costs such as botler feedwater treatment costs leachates that reach the catchment basin SOURCE R F Probste!n, H Gold and R E Hicks, Wafer Requwernerrk, Po//u(/on Effecls and would be treated. This method may be effec- Cosk O( Waler Supp/y and rreatrnerrl for the 00 Sha/e /ndus/ry, prepared for OTA by tive Waler Purlflcatlon Associates, October 1979 during the lifetime of the facility.

Control of Nonpoint Sources Tests of these control strategies have not simulated conditions of commercial-scale dis- The major potential nonpoint sources are posal piles, and past research investigations leachates from aboveground storage of raw are limited in their applicability. Questions or spent shale and from abandoned in situ re- persist concerning shale pile permeability, Ch 8–Environmental Considerations ● 307

Figure 61 .—An Aboveground Spent Shale ations, they might serve as a primary method Disposal Area for reducing leaching. Several uncertainties prevent assessing the feasibility of this ap- ‘+\ proach. For example, the mineral complexes \’ -- produced in the field would have to remain in- 1 soluble for long periods of time even if the Processed Shale = retorts were backflooded. Also, to eliminate -— Disposal Pile \’ leaching, all of the spent shale in the retorts Leachate Ditch -- $ would have to be insoluble. Because control ; + \\ of MIS retorting is difficult, portions of the

\\ retorts may not become hot enough to pro- Drainage~~ D!tch , q%// . , ,\ duce the insoluble complexes. Control of re-

/’ torting temperatures in TIS processing is y{//)’)’y”Leachate Ditch even less certain. Since there would be mas- ‘/ ‘/ sive amounts of waste, increased percolation ‘ / //;/ / / / /’ by ground water, and thus greater leaching .— - ‘ /,$? ///’.?-#/ // )/ ,/ / Q potential, these uncertainties may mandate /// -—— Leachate Catch Basin ;:::~&4/////7T~/ the adoption of retort abandonment strate- — Retention Dam gies. —-.:”&/ il ---–– l\ \ Retorted shale can form a cement-like ma- \\, Emergency Spillway terial if it is properly prepared, and water ‘\ \ ‘~. slurries of finely crushed retorted shale could \ / ‘\ be injected into burned-out retorts to fill void :&b‘\( \\ \ areas and to make the spent shale imper- SOURCE: Surface Mining of Non-Coal Minerals, National Academy of meable to water flow. To prevent leaching, Sciences, Washington, D C., 1979, p. 126, the cement formed from the injected slurry would have to have very low permeability; erosion potential, reclamation effectiveness, otherwise, the cement itself might produce a and the balance between erosion and soil pro- troublesome leachate, thereby compounding duction rates. Water and leachates may per- ground water pollution, Distributing the slur- colate into underlying alluvial aquifers. * ry uniformly within the retort may also prove These effects need careful monitoring at difficult. pioneer commercial facilities. Another approach would be to pump fresh- The efficacies of these control strategies water through the retort to intentionally after site abandonment are even less certain. leach out the soluble components. The leach- Long-term monitoring and custodial care may ates could be treated and then reinfected on a be required to assure that contaminants are downgradient from the retorts. It is possible not released from the catchment basin as a that leaching could be accelerated in this result of dam failure or extraordinarily heavy way, but the process might be costly and time- rainfall or snowfall, consuming and the technology has yet to be For in situ processing, laboratory experi- developed. ments indicate that high temperatures con- “Hydrologic barriers” might be used to vert soluble solids in spent shale into insolu- prevent or control the flow of water into the ble mineral complexes. If such temperatures retort area, thereby preventing the disper- could be achieved in commercial-scale oper- sion of leachates. One possibility is drilling a continuous series of holes around the retort *rI’here are other techniques as well, For example, preleach- area and filling them with a cementitious ing of spent shale, capillarv brakes, and covering spent shale with open pit overburden, See the section on land reclamation slurry. By itself, this technique may not be ful- in this rhapter for more detail. ly effective since the retorts may be in aqui- 308 . An Assessment of Oil Shale Technologies fers in which water moves vertically. The ef- Treated cooling tower wastewater could fectiveness could be increased by cementing be reused after dilution with other treated (grouting) the retorts to seal their more per- streams. Treated gas condensates are also meable zones and fractures. suitable for cooling water because they should have low concentrations of inorganic Another possibility would be to divert a contaminants and volatile organics. Retort major portion of the ground water flow condensates could also be used after their around the retort area. In this “hydraulic by- dissolved substances are removed. pass” option, artificial channels or barriers would capture most of the ground water flow- Water quality criteria have not been estab- ing toward the retort area, direct it around lished for dust control, shale disposal, or the area, and then return it to the ground wa- revegetation, but water similar to river water ter system. would probably be acceptable. It should be possible and practical to treat gas conden- Ultimate Disposition of Wastewater sates to this level. Treated retort condensates should also be acceptable, although success- At present, no developer plans to discharge ful treatment has yet to be demonstrated. wastewaters to surface streams; rather, the Steam raising, for example, with the thermal final wastes will be disposed of by recycling, sludge system, is at present a more reliable evaporation, and reinfection. In the future, option. These condensates (either treated or consideration may be given to treating and untreated) could also be used as a slurry discharging all surplus process waters. This medium for grouting in situ retorts. Tests would be much more expensive than treat- would be needed to determine if the waste- ment to industrial standards, but it would re- water contaminants were truly immobilized duce the impacts of development by augment- so that they could not be leached by ground ing stream flows in a water-short region. If water. this option is adopted, water treatment needs will increase significantly and highly efficient Evaporation treatment methods will be necessary. Most of the wastewaters will be disposed Recycling of in dust control and in the waste disposal piles. The sludges and concentrates from Present developer plans call for treating wastewater treatment will also be added to and recycling wastewaters whenever practi- the disposal piles. In essence, this converts a cal. This depends only on the ability of waste point source of pollution, which would be treatment systems to purify the wastewaters highly regulated under existing laws, to a so that they could be reused in other portions nonpoint discharge, which is not well-regu- of the process. Nearly all of the wastewaters lated at present. However, the treated waste- could be reused after appropriate treatment waters would be quite different from the raw for cooling tower makeup, for dust control, streams described in table 51. For example, for shale disposal, for leaching, for revegeta- most of the NH3 and H2S will have been re- tion, and for generating steam that could be moved from the gas condensates and recov- injected into either aboveground or in situ re- ered as byproducts. The CO2 will also have torts. As discussed previously, efficient, reli- been removed and vented to the atmosphere. able, adaptable, and cost-effective methods The concentration of NH3 could be further re- appear to be available for the major contami- duced by biological treatment and by using nated streams. Their capability of treating the treated condensates as cooling water. the wastes to discharge or reinfection stand- The small quantity remaining may be useful ards is not relevant as long as the streams are as fertilizer for reclaiming the waste disposal to be recycled. areas. Most of the potentially harmful organ- Ch. 8–Environmental Considerations 309

ic compounds could be removed by biological Monitoring Water Quality treatment and the more resistant ones by adsorption. However, some organic matter is Because much surface water comes from likely to reach the shale disposal area. It is ground water discharge, it is necessary to not known whether the organics will remain monitor both surface and ground water to locked within the shale pile or will be help prevent environmental damage. Moni- leached. toring provides a continuous check on compliance with regulations, a record of changes re- Similar treatment could be used for the resulting from development, and a measure of torting and upgrading condensates, although the effectiveness of pollution control proce- the chemicals in the retort condensate could dures. pose some special treatment problems. If thermal sludge systems were used, both the inorganic and the nonvolatile organic contam- Surface Water Monitoring inants would be reduced to a stable sludge Surface water monitoring should include: suitable for disposal in a sanitary landfill or in a hazardous-waste disposal area. The vola- ● instream sampling and chemical anal- tile organics would be entrained in the steam ysis to detect and characterize pollut- and subsequently incinerated in the retorts. ants of point and nonpoint origin: ● detection of spills and faulty contain- Reinfection ment structures that could result in accidental discharges; Reinfection may be legally allowed if the ● measurement of streamflows to assess quality of the injected water is at least as effects of dewatering operations and high as that in the affected aquifer. Injection consumptive uses; and of condensates or other highly contaminated ● measurement of aquatic biota to deter- wastes would not be permitted without a high mine the changes resulting from develop- degree of treatment, However, mine drainage ment, water might be reinfected if it had not been degraded by evaporation or chemical change A monitoring program is defined by the while on the surface. Otherwise, it first number and location of sampling stations, the would have to be treated or diluted. parameters measured, the sampling frequency and collection methods, the accuracy and Until commercial-scale oil production be- precision of the analytical techniques, and gins, essentially all mine drainage water will the quality assurance safeguards. Tradition- require disposal, probably by reinfection. It is al monitoring methods may not be well-suited generally assumed that the chemicals in the for the oil shale situation. The uncertain drainage water would not cause significant pollutant release rates and pathways and the changes in the quality of the source aquifers. wide variations in regional water quality, However, water quality could be degraded complicate the development of a suitable pro- because of the increased ground water flow, gram and limit the use of conventional tech- the exposure of new mineral surfaces by niques. fracturing, and the changes in underground microbial populations. If such changes oc- The number and location of sampling sta- curred, the treatment or disposal conditions tions depend on the objective of the monitor- would have to be adjusted to compensate for ing program. For example, if the objective is them. 51 This might include treating the drain- to detect changes over an entire basin, the age to a purity higher than that of the source stations would be located in the lower aquifer. reaches of major tributaries. They could de- 310 An Assessment of Oil Shale Technologies tect major changes but would be unable to Ground Water Monitoring pinpoint their cause. In contrast, stations near pollution sources could both measure Observation wells are used to detect the local effects of pollutant discharge and trends in water quality and to measure the ef- identify the source. An oil shale program fects of operations such as wastewater rein- could include stations on major streams, as fection. The locations of the monitoring sta- well as on the minor tributaries that drain tions should be selected according to: each development site. Special stations are ● the locations of the potential pollutant also needed near solid waste disposal areas sources; to detect leaching. ● the geology and hydrology of the site to The selection of chemical, physical, and be monitored; biological parameters to be measured will be ● the probable movement and dispersion based on the types and concentrations of pol- of pollutants underground; and lutants that might be discharged, the ease of ● the potential for hydrologic disturbances analysis, and the characteristics of the water of, for example, dewatering wells. in the affected streams and aquifers. The EPA has developed a monitoring methodology possible parameters include the concentra- for the oil shale area.52 The important con- tions of the pollutants themselves as well as siderations are: the levels of “indicator” parameters that provide a measure of the potential environmental ● the identification of potential pollutants; ● disturbance. These include pH, dissolved ox- the definition of hydrogeology, ground ygen, hardness, temperature, flow rate, and water use, and existing quality; ● the characteristics of the aquatic biota. the evaluation of the potential for infiltration of wastes by seepage; Biological parameters are especially useful ● the evaluation of pollutant mobility in because they reflect the stability and re- the affected aquifers; sponse of the ecosystem. Aquatic organisms ● the priority ranking of pollution sources are natural monitors of water quality since based on the mass, persistence, toxicity, they respond in a predictable manner to the and concentration of the wastes; their presence of most types of pollutants. Changes mobility; and their potential for harm to may indicate problems that are not easily water users; and detected by direct measurements of water ● the design and implementation of pro- quality. For example, heavy metals and some grams for near-surface aquifers, deep organic compounds tend to concentrate in the aquifers, and injection wells. biota. Their levels in the tissues of certain fish could help predict pollution concentra- The siting of wells for near-surface aquifers tions that are not readily measurable in the is extremely important. They should be water itself. Communities that could be moni- placed down the ground water hydraulic gra- tored include invertebrates, fish, algae, and dient (i.e., “downstream”) from possible pol- bacteria. lution sources such as reinfection wells, reservoirs, and disposal piles. The wells should The sampling frequency can also vary. allow sampling from different depths, and the Ephemeral tributaries, for example, could be chemical and physical parameters should be monitored only during periods of heavy rain- selected according to hydrological character- fall or snowmelt; mainstream tributaries istics as well as the properties of potential could be monitored continuously. Frequent pollutants. Deep aquifers should be moni- monitoring of all possible parameters would tored near dewatering wells, in situ retorts, be very expensive and time-consuming. and reinfection wells. Monitoring of salinity, Therefore, priorities must be established on TDS, and water level should be emphasized. the basis of cost, utility of the data, and the Monitoring deep aquifers in the Piceance potential for severe environmental impacts. basin is especially difficult because the — —

Ch, 8–Environmental Considerations ● 311 ground water flows through fractures and Need for Reliable Data on Wastewater Quality faults and not through the more common uniformly porous media, A further complication Reliable data are lacking on the charac- is the different permeability of adjacent teristics of the gas, retort, and upgrading strata. Even flow rates are hard to measure condensates from all of the proposed de- in a fractured-rock system, and it is difficult velopment technologies. The data should be to properly site the monitoring stations. obtained with pilot plants that integrate several streams and several control devices and The monitoring of surface and ground wa- that simulate commercial-scale conditions. ter quality is exemplified by the program on In commercial plants, wastewaters may be Federal lease tract C-b that has been under- mixed and the interactions of contaminants way since 1974. The sampling schedule and from the different streams will affect treat- water quality parameters are listed in table ability. Therefore, analyses of separate 65. Thirteen surface water gauging stations streams are not sufficient. have been constructed: nine on ephemeral More reliable estimates are needed of the streams and four on perennial drainages. quality and quantity of the mine drainage Nine springs and seeps are also monitored. water that will be encountered in specific Temperature and conductivity are measured areas. This information would help determine continuously at all stations on the perennial how the water would have to be treated for streams. Dissolved oxygen, pH, and turbidity surface discharge, and would allow a com- are measured continuously at several of parison to be made between surface dis- these stations; other parameters are meas- charge and other disposal methods. ured monthly, quarterly, or semiannually. Studies of leachates are also needed; in Water levels in alluvial aquifers are meas- particular, on their ability to penetrate the ured continuously at 18 test wells. Conduct- linings of disposal ponds and catchment ba- ance, pH, temperature, and dissolved oxygen sins. will be measured monthly. The quantity and quality of water in the deeper bedrock aqui- Need for Assessing Control Technologies fers are measured at 17 wells in the upper aquifer and 14 in the lower aquifer. Samples Although individual methods have been are obtained for water quality twice a year, tested successfully on a small scale, the per- and water levels are measured monthly. Wa- formance of an integrated treatment system ter quality is also measured in reservoirs, has yet to be evaluated with actual effluent waste disposal piles, and mine sumps. streams. This could be done, for example, by testing relatively inexpensive pilot-scale systems as part of a retort demonstration pro- Information Needs and R&D Programs gram. These tests would help determine, for example, if the dissolved organics in retort Insights into the water quality impacts of condensates can be adequately controlled oil shale development have been obtained with a series of conventional treatment proc- from laboratory and pilot plant studies, from esses. The distribution and control of trace a few field tests in the Piceance basin, and elements could also be assessed. from experience in related industries. Addi- tional measurements and R&D programs are Need for Cost Information needed to help reduce the level of uncertainty. Uncertainties will remain, however, until According to present estimates, wastewa- experience has accumulated from commer- ter treatment costs are expected to be only a cial-sized modules and plants. small fraction of the total cost of shale oil pro- —— —— — -.. —

312 An Assessment of Oil Shale Technologies

Table 65.–Sampling Schedule Summary for Surface and Ground Water Monitoring Program at Tract C-b During Development Phase Surface water Seeps and springs Ground water Alkalinity ., ... M(Z), Q(O,PC) o Q(Al), SA(Aq) Ammonia ., ., ~ ., M(Z)Q(o,PC) Q Q(Al), SA(Aq) Arsenic. ... ., ., . ., ., M(Z)O(o,PC) Q Q(Al), SA(Aq) Barium . ., ... ., — — (Lisa Beryllium ... Q — A(AI) Bicarbonate ...... ,. .,, ,,, ,., M(Z) Q(o,PC) — — BAD. , .,.,.,,...... ,,.. . . . — Q SA(Al), SA(Aq) Boron ., ., ., . M(Z~Q(o,PC) Q Q(Al), SA(Aq) Cobalt. .,..,.,,, .,, ,, ..,,.,,..,,. — — SA(Aq) Color ., .,, .,, ,, .,, ..,.... .,,,,,, — — — COD...... Q Q Q(Al), SA(Aq) Coliform, total and fecal ., .,,.,,,,,. ., o s — Conductivity, specific, ,,. ,, . M Q(AI) Copper. , .,, .,... ,.,.,, . . Q Q Q(Al), SA(Aq Cyanide ..,.,,. .,, ,,, ..,.,, ,,,., Q — — Dissolved oxygen .,,.,. M(Z)Q(o,PC) M M(AI) Fluoride ., ., ., . M(Z), Q(o,PC) Q Q(Al), SA(Aq Hardness ,. .,.,, ,’,”’”. — Q Q(Al), SA(Aq Iron — Q Q(Al), SA(Aq Lead. ...’.., , .,,,, ‘, Q Q Q(Al), SA(Aq) Lithium. ,.,, ,.,, ,,..,,. Q Q Q(Al), SA(Aq) Magnesium, ,.,’...... M(Z), Q(o,PC) Q O(Al), SA(Aq) Manganese, ,,, M(Z) Q(o,PC) Q Q(Al), SA(Aq) Mercury. ., . . . . ., ., Q Q Q(Al), SA(Aq) Molybdenum .,.., ...... ,,, Q Q Q(Al), SA(Aq) Nickel. , ,,. ,., ..., ,. — Q Q(Al), SA(Aq) Nitrate ...... ,,. M(Z~Q(o.PC) Q Q(Al), SA(Aq) Nitrogen (Kjeldahl), ,.,,. M(Z), Q(o,PC) Q Q(Al), SA(Aq) Odor .,,, — — — Oil and grease, , , .,,, ,,. Q Q Q(Al), SA(Aq) Phosphate, , ...,, ,,. M(Z~Q(o,PC) — — Pesticides. .,... ,.., ,,. — . SA(Aq) Phenol ,.. ,,,. .,,. .,,, Q Q A(Al), SA(Aq) Potassium, ., ., ., ..., ., ., M(Z), Q(o,PC) Q Q(Al), SA(Aq) Radiation, alpha .,, ,,, ,,, Q s SA(Al), SA(Aq Radiation, beta ., ., Q s SA(Al), SA(Aq Sediment ,.. ,. ,“. M(Z), Q(o,PC) — — Silica ..,,, ,,. ,.., .,,,, M(Z), Q(o,PC) — — Sulfate ,. ,, ....,, M(Z), Q(o,PC) o Q(Al), SA(Aq) Sulfide o — — Suspended solids — — — Turbidity. . . . ,. .,.,,,, ,,, ,,,,.., — — — PA, ,, ., ..,.,.,, ..., ,,, M(Z), Q(o,PC) M,Q M,Q(AI) Total dissolved solids. . ,, ,. M(Z), Q(o,PC) Q Q(AI) Water level ., — — MESA Stream flow. ,, ...... ,’ M(Z) Q(o,PC) Q,SA,A — Water temperature .,.. M(Z) Q(o,PC) M,Q M, Q(Al), SA(Aq) Dissolved organic carbon ., ., M(Z) Q(o,PC) s SA(Al), SA(Aq) KEY A =AnnUa~y (Z) =Maorgaglng slationson~ SA = Semiannually (o) =Aflgagmg stations except major stahons S= Semimonthly (PC) =F?ceance Creek gaging stations O =Ouarferiy (Al) =Alluwal wells M =Monlhly (Aqj =Oeepaquders SOURCE E R Bales andT L Thoem(eds ) Pollution Con/ro/Gu/dancelor Oti Sha/e Deve/oprnerrl Apperrd/ces /o the l?ewsed L%a/(Reporl, comptiedby Jacobs Envwonmental Orw~onfor Envvonmental Protection Agency C{nclnnah Ohio July 1979 pp C-84-C-85 duction. However, inadequate attention to Lower cost treatment options should also water management could seriously impede a be explored. For example, the thermal sludge project’s construction and operation. Thus, system could significantly reduce treatment water treatment although not costly by itself costs by raising steam directly from process could ultimately cause substantial cost esca- condensates. Another promising procedure lations. is the removal of dissolved organics from Ch. 8–Environmental Considerations ● 313 treated condensates in the cooling water cir- development of reliable models and test- cuit. ing them under simulated worst case conditions, such as massive failure of a Discharging suitably treated wastewaters (especially excess mine water) to surface containment structure; and streams should be investigated as a mecha- research on the restoration of aquifers nism for supplementing the region’s scarce disturbed by in situ processing, water resources. Some of the contaminants in the treated wastes may require special atten- Current R&D Programs tion, and means to remove them should be ex- Below is a partial listing of the ongoing and plored. proposed R&D programs by the Federal Gov- ernment and the private sector: Need for Evaluating the Potential Impacts Under EPA grants, Colorado State Uni- of Effluent Streams versity is studying the water quality Information is needed on the impacts of the within the oil shale areas, the leaching pollutants on the environment. In particular, characteristics of raw and retorted oil research is needed on the effect of the leach- shale, and the surface stability and wa- ing of spent shale and other solid wastes on ter movement in and through disposal salinity, sediment loading, temperature, nu- piles. Specific objectives include devel- trient loading, and microbial populations of oping procedures for assessing the quan- surface waters. This work should address the tity and quality of surface and subsur- impacts that might occur both during the face runoff from solid waste piles. operation of a facility and after the facility’s Under an EPA contract, TRW and DRI useful lifetime. are studying the environmental impact of oil shale development, including an evaluation of technologies for waste- Specific R&D Needs water control. DOE’s Office of the Environment is as- Research is needed in the following speci- sessing water quality aspects of the fic areas: Paraho process. ● characterization of the wastewaters, es- DOE and the State of Colorado are devel- pecially for the presence of trace metals oping a program related to water pollu- and organic chemicals produced by each tion from MIS retorting. retorting process; Under EPA contracts, the Monsanto Re- ● determination of the applicability of con- search Corp. is investigating the treat- ventional treatment methods to oil shale ment of retort wastewaters and is study- wastewater and development of new ing the potential of in situ retorting for treatment methods if necessary; air and water pollution. ● determination of the changes in ground The National Bureau of Standards, in co- water quality and flows resulting from operation with EPA and other agencies, mine dewatering; is developing methods for measuring the ● development and demonstration of meth- environmental effects of increased ener- ods to prevent leaching of MIS retorts by gy production. ground water; In its oil shale program management ● studies to simulate and test the percola- plan, DOE has proposed to: tion of rainfall and snowmelt through —assess the effect of mine and retort spent and raw shales and native soils backfilling on ground water quality; and to assess resulting leachates; —study the leachability of raw and ● standardization of leachate sampling spent shale and the effect of disposal techniques; on surface and ground water quality;

6 3-89B ‘ - 80 - ? : 314 An Assessment of Oil Shale Technologies

—investigate the need for long-term should be well-suited to oil shale processes. It care of surface disposal areas; and is less certain that the conventional methods —design a solid waste disposal plan for would be able to treat wastewaters to dis- a commercial MIS facility. charge standards because they have not been ● The National Science Foundation is tested with actual oil shale wastes under con- sponsoring work to characterize the conditions that approximate commercial produc- taminants in spent shale and to develop tion. Furthermore, no technique has been techniques for managing them. demonstrated for managing ground water ● EPA is preparing a pollution control leaching of in situ retorts, nor has the ef- guidance document for an oil shale in- ficacy of methods for protecting surface dis- dustry, that will consider all aspects of posal piles from leaching been proven. It is surface and ground water quality. not known to what extent leaching will occur, but if it did, it would degrade the region’s Findings on Water Quality Aspects of water quality. Oil Shale Development Although control of major water pollutants from point sources is not expected to be a Water quality is of major concern in the oil severe problem, less is known about control shale region, especially in regard to the of trace metals and toxic organic substances. salinity and sediment levels in the Colorado Research is needed to assess the hazards River system. Oil shale development has the posed by these pollutants and to develop potential for water pollution, the extent of methods for their management. Other labora- which will depend on the processing technol- tory-scale and pilot plant R&D should be fo- ogies employed, the scale of operation, the cused on characterizing the waste streams, types and efficiencies of the pollution control determining the suitability of conventional strategies used, and the regulations that are control technologies, and assessing the fates imposed. of pollutants in the water system. Such work Surface discharge from point sources is is underway; its continuation is essential to regulated under the Clean Water Act, and protecting water quality, both during the op- ground water reinfection standards are being eration of a plant and after site abandon- promulgated under the Safe Drinking Water ment. Act. Solid waste disposal methods may be subject to the Toxic Substances Control Act Policy Options for and the Resource Conservation and Recovery Water Quality Management Act. The general regulatory framework is therefore in place, although no technology- For Increasing Available Information based effluent standards have been promulgated for the industry under the Clean Water Options for increasing the overall level of Act. information regarding pollutants, their effects, or their control include the evolution of Developers are currently planning for zero existing R&D programs, the improved coordi- discharge to surface streams and to reinject nation of R&D work by Federal agencies, in- only excess mine water. Most wastewater creasing or redistributing appropriations to will be treated for reuse within the facility; agencies to accelerate their surface and untreatable wastes will be discarded in spent ground water quality studies, and the pas- shale piles. The costs of this strategy are low sage of new legislation specifically tied to to moderate, and development should not be evaluating water quality impacts. For exam- impeded by existing regulations if it is imple- ple, pioneer plants receiving Federal assist- mented. ance could be required to monitor water qual- A variety of treatment devices are avail- ity effects, with particular emphasis on non- able for the above strategy, and many of them point discharges. Procedures for implementa- Ch. 8–Environmental Considerations . 315 tion could be similar to those for the existing ty about environmental regulations that is Federal Prototype Leasing Program. Mecha- now deterring developer participation. How- nisms for implementing these options are sim- ever, the standards would have to be careful- ilar to those discussed in the air quality sec- ly established to assure that they were both tion of this chapter. attainable at reasonable cost and adequate to protect the environment. Mechanisms for im- For Developing and Evaluating plementing improved regulation of nonpoint Control Technologies discharges include extension and modification of the Surface Mining Control and Recla- The Government could expedite the avail- mation Act for oil shale, special controls reg- ability of proven controls by accelerating its ulating nonpoint discharges under the Clean efforts to design, develop, and test treatment Water Act, or applying the Resource Conser- technologies for oil shale wastewaters. To be vation and Recovery Act waste disposal most effective, this work would have to be standards to low-grade/high-volume mate- coordinated with private efforts to develop rials. the oil shale processing methods. This could be done under cost-sharing arrangements, in- For Ensuring the Long-Term Management of cluding tests at the sites of retort demonstra- Waste Disposal Sites and Underground Retorts tion projects. (EPA is presently conducting a program for retorting wastewaters under a These areas may require monitoring for contract with Monsanto Research Corp. ) many years after the projects are completed. Long-term management could be regulated For Developing Regulatory Procedures under the Resource Conservation and Recov- ery Act, which allows EPA to set standards The present approach could be followed in for the management of hazardous materials, which regulations evolve as the industry and including mining and processing wastes. No its control technologies develop, An approach such action has yet been taken by EPA, but could also be used in which standards would Congress could direct it to do so. Congress be set that would not change for a period of could also require the developers to guaran- say, 10 years, after which they could be ad- tee such management by incorporating ap- justed to reflect the experience of the indus- propriate provisions in any bill encouraging try. This would remove most of the uncertain- oil shale development.

Safety and Health Introduction ● the health and safety hazards associated with oil shale operations; Anticipating occupational and environmen- ● the environmental risks if contaminated tal health and safety hazards is an important air and water are released; consideration in the development of an oil ● the applicable Federal health and safety shale industry. Anticipation and planning, es- laws, standards, and regulations; pecially in the early phases of the industry, ● the control and mitigation methods that should guide efforts to reduce health and could be applied to these risks; safety risks and costs to society. To bring at- ● the issues regarding the coordination of tention to known hazards, and to point out po- monitoring and education efforts; tential ones, this section covers the following ● the R&D needs; and subjects: ● the policy options. 316 “An Assessment of Oil Shale Technologies

Safety and Health Hazards may expose miners to risks that are not experienced in other underground mining ac- Occupational Hazards tivities. The hazard of mine flooding is not unique to oil shale, nor would it be encoun- Workers will be exposed to a number of oc- tered in all oil shale mines. However, it could cupational safety and health hazards during be severe in mines that are developed within the construction and operation of an oil shale ground water areas. While the mining zones facility. Many of these hazards—such as would be dewatered before mining could be- rockfalls, explosions and fires, dust, noise, gin, there could be flooding if the pumps and contact with organic feedstocks and re- failed. fined products —will be similar to those associated with hard-rock mining, mineral proc- Retorting and refining.—Potential hazards essing, and the refining of conventional petro- associated with the retorting and upgrading leum. However, due to the physical and chem- of shale oil include explosions, fire and heat, ical characteristics of shale and shale oil, the bumps and falls, electrocution, and handling types of development technologies to be em- hot liquids. However, the degree of risk for ployed, and the scale of operations, oil shale workers involved in the processing of oil workers might be exposed to unique hazards. shale and its derivatives would not be ex- They will be discussed as follows: safety haz- pected to be so high as in mining. ards that might result in disabling or fatal ac- The processes involved in retorting and up- cidents; and health hazards stemming from grading (e.g., materials handling, crushing, high noise levels, contact with irritant and solids heating and cooling, waste disposal, asphyxiant gases and liquids, contact with and the handling of hot and hazardous liq- likely carcinogens and mutagens, and the in- uids) are generally similar to those used in halation of fibrogenic dust. other operations such as mineral processing (e.g., limestone calcining, roasting of taconite SAFETY HAZARDS and copper ores, and leaching) and conven- Mining.-The similarity of hard-rock min- tional petroleum refining. Although no coming to underground or open pit oil shale min- parative study has been undertaken, there ing makes it possible to project likely occupa- are few unique features associated with re- tional safety risks. During mining, accidents torting, upgrading, and refining that would result from rock and roof falls, explosions justify expecting higher worker safety risks and fires, bumps and falls, electrocution, than those in similar industries. heavy mining equipment, and vehicular traffic. Hard-rock mining is a high-risk occupa- HEALTH HAZARDS tion; fatalities are five times more frequent in Mining. —During oil shale mining, as dis- the mining and quarrying industry than in cussed in the section of this chapter on air manufacturing. The frequency of disabling quality, hazardous substances including sili- injuries from underground mining (excluding ca dust will be generated by blasting and the coal industry) is two and a half times 53 drilling. In addition, blasting, raw shale han- higher than from manufacturing. Mining dling and disposal, and other activities at the coal is even more dangerous. minesite will produce fugitive dust. Silica- While most hazards to oil shale miners containing dusts are noteworthy because would be similar to those experienced by they have been the single greatest health haz- hard-rock workers, some are unique to oil ard throughout the history of underground shale. A number of the oil shale facilities are mining. Silica is highly toxic to alveolar planning to use MIS processes in which part macrophages—’’scavenger” cells that move of the deposit is mined out and the remainder about on the inside of the lung and engulf and is then rubbled and burned underground. The remove foreign particles that might damage high temperatures and fires involved in MIS the lung. Silicosis, “shalosis,” and chronic Ch. 8–Environmental Considerations ● 317 bronchitis* are among the diseases that may United States and England,58 and in gold result from the inhalation of oil shale dust. miners in South Africa. 59) A survey conducted by the U.S. Public In another study, postmortem examination Health Service (USPHS) between 1958 and of 30 Estonian oil shale workers who died of 1961 found excessive dust levels in 6 out of 67 accidents and various other diseases60 found inspected mines. 54 The chest X-rays of 14,076 that all had pulmonary fibrosis and one- miners employed in 50 hard-rock mines indi- fourth displayed classic silicotic nodules. * An cated that 3.4 percent had silicosis. ss ** examination of 1,000 Estonian oil shale These measurements were made before mod- workers failed to reveal any cases of pneumo- ern mine hygiene practices were required by coniosis, a pulmonary disease caused by in- the relatively recent occupational safety and haled dusts. However, the workers had been health regulations and a more recent study involved in the industry for only 5 to 14 years. undertaken by the Mining Safety and Health Twenty years of exposure are usually re- Administration showed marked improve- quired for the symptoms of the disease to be ments in mine dust levels. This study exam- detected by a chest X-ray. Because Estonian ined 22 hard-rock mines, 8 of which were in- industrial hygiene standards are not known, cluded in the USPHS study, and found none of the Estonian studies can only suggest an asso- them in violation of the dust standards, 56)** * ciation between oil shale mining and lung disease. The Estonian studies provide no infor- Although few studies have been under- mation about the risk levels to be expected in taken on the direct association between oil mines maintained under U.S. health and safe- shale mining in the United States and the in- ty standards. cidence of lung disease, there are studies on the prevalence of lung disease in oil shale Studies of occupational diseases among oil miners in Estonia. Estonia mined 25 million shale miners in the United States have been tons of oil shale in 1973, and has had oil shale limited because relatively few people have operations for several decades. While the re- worked in the industry. A study was under- sults of the Estonian studies are more intrigu- taken involving miners from the oil shale re- ing than convincing, they do suggest an asso- search center at Anvil Points, Colo., which ciation between oil shale mining and pulmo- has operated intermittently since 1946. nary fibrosis—an increase in the amount of Eighty-six workers were identified, but only fibrous material in the lung. One study also 39 of them had been exposed to oil shale for indicated that chronic bronchitis was 2 to 2-1/2 one or more years. Those 39 were compared times more prevalent in 189 Estonian oil shale with 26 other workers from the facility (e.g., miners than in a similarly aged control popu- office workers, administrators) who had not lation.” (A similar degree of excess bronchitis been directly involved in the mining opera- has been observed in coal miners in the tions. Results showed a twofold higher incidence of pneumoconiosis in the oil-shale exposed population. However, the interpreta- *Sili~osis is a ~is~blin~ fibrotic disease of the lungs caused by inhalation of silica dust and marked by shortness of breath. tion of these results is complicated by the fact “Shalosis” is a disease of the lungs and is related to specific ex- that most of the oil shale miners had previous- posures of oil shale mine dust. It resembles silicosis: its ex- ly worked in uranium-vanadium mines or mill- istence as a specific disease remains to be proved. Inflammation of the bronchial tubes, or anv part of them, is known as bron- ing operations which are known to be causes chitis. of pneumoconiosis.61 Further evaluation of **The 3.4 percent is probably a low estimate; generally sick these populations was not performed because individuals who have left the work force or moved for health and other reasons are under-represented in such surveys. If of the age of the workers, their varying levels such individuals had been examined the incidence of silicosis of exposure, and their limited experience in might have been higher. oil shale mining. ***This study is expected to be released in the near future along with a companion study undertaken by the National Insti- tute of Occupational Health and Safety which examines the *Silicotic nodules are small lumps on the surface of the lung health status of miners from 22 hardrock mines. formed as a response to deposition of silica specks. 318 ● An Assessment of Oil Shale Technologies

A separate study of employees at the same ratory cancers was greater than the percent- facility between 1974 and 1978 found no ad- age in the white male populations of Colorado verse health effects.62 An examination of the and Utah.68 Whether oil shale exposure con- death certificates of 167 oil shale workers un- tributed to the higher incidence is unclear, dertaken by the National Institute for Occu- and the incidence rate among miners was not pational Safety and Health (NIOSH) failed to higher than that of the white male population reveal any association between oil shale ex- in the United States. posure and respiratory diseases.63 Because of the limited number of workers studied, their A cancer morbidity study undertaken by relatively short exposures to oil shale mining, the Rocky Mountain Center for Occupational and Environmental Health found more cyto- and in some cases their exposures to other logical atypia* in the sputum and urine of oil kinds of mining, no firm conclusions can be drawn from these studies. shale miners than among controls, but no association was found between exposure and Some animal studies have demonstrated skin diseases. These data will be further relationships between oil shale exposure and studied to identify any associations between respiratory diseases, but the results conflict such abnormalities and occupational ex- with those of other experiments, making it posures. Animal studies undertaken to date difficult to draw conclusions. One study indi- have not demonstrated that oil shale dust is cated that Estonian oil shale had a weak fi- carcinogenic. brogenic* action in rats; both oil shale and spent shale ash produced pulmonary fibrosis A third potential health hazard to oil shale in white rats after the dusts were deposited miners is exposure to excessive noise levels, into the trachea.64 Another study reported particularly in underground operations car- pulmonary effects when Syrian hamsters ried out in relatively confined spaces. Noise were exposed via intratracheal administra- arises from numerous sources such as boost- tion or inhalation to finely ground oil shale er fans, pneumatic drills, blasting, conveyors, dust and retorted shales.65 66 Increased alveo- and mining machines. The Bureau of Mines lar microphage activity was also noted. The studied 19 pieces of diesel-powered mining same study found that retorted shale dust equipment and found only 2 had noise levels was associated with inflammation, and fre- below the current standards (90 decibels), quently caused increases in the fibrous mate- and one of these exceeded the standard in an rial in the lung (fibrosis] and excessive underground environment. One study esti- growth of cells that line the lung cavities (epi- mated that of the 37,000 workers employed in thelial hyperplasia). However, a 2-year study 650 metal and nonmetal mines, approximate- with rats, which evaluated the effects of raw ly 14,000 (38 percent) were exposed to diesel- or spent shale dust instilled intratracheally in powered equipment noise levels greater than multiple exposures over an 8-month period, the standard.** Of these, 2,430 (17 percent) were overexposed on a time-weighted-aver- found essentially no pulmonary fibrosis. The 69 investigator considered the results to be neg- age basis. Evidence indicates exposure to ative. 67 noise from a large number of mining machines would produce hearing loss if the ex- Another area of concern is the possible exposures exceeded 8 hours per day.70 Higher posure to carcinogens (e.g., polycyclic aro- short-term noise exposures may occur during matic hydrocarbons—PAHs) and trace elements that might be produced during mining. *Cytological atypia are premalignant cell types observed in The NIOSH mortality study mentioned earli- the examination of the body fluids. er found that the percentage of oil shale **A major health issue is the long-term effect of diesel smoke workers who had died from colon and respi- exposure in underground mining environments. The National Academy of Sciences is conducting a study in this area which will be released in the near future. The health implications of *A fibrogenic substance is conducive to the generation of diesel equipment used in underground oil shale mines is un- fibrous materials in the respiratory tract. known at this time. Ch. 8–Environmental Considerations 319

blasting. High noise levels are a potential haz- Refined Scottish shale oils were known to ard not only to hearing, but to the cardiovas- be carcinogenic, but the disease was largely cular and nervous systems as well, and pose preventable by personal cleanliness. It is be- a safety hazard. lieved that the disease occurred because the Retorting and refining.—Retorting oil workers wore the same clothes on the job day shale at high temperatures forms PAH-con- after day. The clothing was rarely, if ever, taining carcinogens of which 3,4-benzo(a)py- laundered, and eventually it became impreg- rene (BaP) is the most studied. PAHs are a nated with shale oil. Contact between the major potential health hazard for retorting soaked clothing and the areas where cancers and refining workers in the oil shale industry occurred was nearly continuous during each because of their carcinogenicity. The prob- working day. This factor, coupled with the lems that might be encountered in oil shale re- fact that daily bathing was rare, undoubtedly fining are similar to those of conventional oil contributed to the high incidence of cancer. refineries, where liquids and gases are trans- Two Estonian studies have shown an asso- ported in airtight pipes under strict mainte- ciation between oil shale processing and nance to detect and repair leaks. cancer. A study of 2,003 Estonian oil shale Crude oil contains an enormous variety of workers with a total of 21,495 person-years potentially hazardous compounds, Even more exposure during the period between 1959 are produced during refining. Work crews in- and 1975 found a significant excess of skin cancer (fivefold for females and threefold for volved in inspection, repair, and maintenance 73 are the most likely to be exposed to PAHs. males). An unusually high incidence of Other hazardous substances found in crude stomach and lung cancer was found among oil include chlorine, sulfur, nitrogen, and persons in the rural areas of Estonia where heavy metals (e.g., vanadium, arsenic, nickel, the oil shale industry is located. ” There is no and cobalt). Toxic contaminants evolved dur- information on the working conditions in Esto- ing the refining process include H S, hydro- nian oil shale operations; nor are data 2 available on the ambient concentrations of gen chloride, hydrochloric acid, SO2, sulfuric acid, methane, ethane, methanol, nitric acid, shale-derived pollutants in the vicinity of the NO , mercaptans, CO, and benzene. plants. It is therefore impossible to relate the X Estonian experience to problems that might The high rate of cancer of the scrotum be encountered in the United States. found in 19th century chimney sweeps and mulespinners* is of historical interest be- Evaluating chemical carcinogenicity in ani- cause it indicates that long exposure of scro- mal experiments is an accepted method for tal skin to PAH-containing oils and soots can predicting carcinogenicity in humans. Inves- cause cancer. In addition to scrotal cancer, tigations that tested the carcinogenicity of oil cancers of the skin, lung, and stomach have shale and shale oil in laboratory animals are also been observed after latent periods of up shown in table 66. A conclusion that can be to 20 years following exposure to PAH-con- drawn from these studies is that shale oil is a taining substances. While the known carcino- carcinogen when painted on animal skins. gen BaP was identified in Scottish shale oil,71 The experiment conducted by Biology Re- a study found only a low incidence rate (less search Consultants (ref. 80 in table 66), in than 0.1 percent per year) of skin cancer for which hairless mice were bedded in raw or 5,000 Scottish oil shale workers between spent oil shale, found no carcinogenic hazard. 1900 and 1922.72 However, this study did not examine the oil shale extracts (e.g., shale oil tar and coke) with which carcinogenicity has been associated. *Mulespinners were workers who lubricated the “mules” (spindles) in the Scottish spinning and weaving industry. Shale- Both the Kettering Laboratory (ref. 79) and derived lubricants were commonly used in this industry. Eppley Institute (ref. 81) studies conclusively 320 ● An Assessment of Oil Shale Technologies

Table 66.–Animal Studies on the Carcinogenicity of Oil Shale and Shale Oil

Organs Nature of study Ref a Materials tested examined Tumerous animals/animals exposed Skin painting study of mice, rats, and rabbits 75 Scottish shale OilS “green 011’ skin 9/100 ‘‘blue oil’ skin 1 2/100 ‘‘unfinished gas oil’ skin 1/50 ‘‘Iubricatmg oil skin 3/50

Skin painting of mice 76 CHCI 3 extract of Scottish oil shale skin 0/20 Scottish shale oil skin 6/10 Skin painting of mice 77 Shale oil skin 1,284/10,000 Skin painting of mice 78 Shale oil skin (35%-90% tumerous) Composite petroleum control skin (0%-8% tumerous) Skin painting of mice (Kettering study) 79 Crude shale oil skin 39/40 Hydrotreated oil skin 5/37 BaP control skin 27/27 Exposure to shale dust (Biology Research 79 Oil shale powder skin 0/12 Consultants) Oil shale powder lungs 2/24 Spent shale powder skin 0/12 Spent shale powder lungs 1 /24 Powdered corn cobs (control) skin 0/1 2 Powdered corn cobs (control) lungs 6/24 Skin painting of mice (Eppley study) 79 Benzene extract of shale oil coke skin 48/50 TOSCO II effluent skin 1 /50 Benzene extract of raw shale oil skin 0/50 Benzene extract of spent shale skin 6/50 Benzene control skin 0/50 None (control) skin 0/100 Intratrachael Instillation in hamsters (Eppley 79 Raw oil shale (b) 0/100 study) Spent shale (b) 0/100 Shale 011 coke (b) 0/100 TOSCO II effluent (b) 0/ 100 BaP control (b) 27/1OO Saline control (b) 0/ 100 None (control) (b) 0/200 aSee reference list bResplratory system SOURCE Wllham Rom et al OcCuPdllOflallEflVlfOflmeflldl Healfh and .SaletY Aspecfs of a CO~rrJerCW 0// Wale lmlWy prePared for OTA by Rocky Mountain Center for Occupational and Enwronmental Health Unwerslty of Utah Oecember 1979

show that crude shale oil, shale oil tars, and Table 67.–Benzo(a)pyrene Content of Oil Shale and shale coke have carcinogenic properties, Its Products and of Other Energy Materials which may be related to their BaP content. Substance BaP concentration, p/ba The second Eppley study (ref. 82), which in- Raw oil shale ., . ., . . . 14 vestigated respiratory system carcinogeni- TOSCO II retorted shale, ., ., 28 city, found no effect. This contrasts to the TOSCO II atmospheric effluent . . ., 140 TOSCO II retort coke. 129 skin exposure experiments. Whether or not Raw shale oil from Colorado, ., ., ., 3,200 oil shale and its derivatives are less of a Hydrotreated shale 011 (0.25% N2) ., 800 Hydrotreated shale 011 (0,05% N ) ., threat to the respiratory system than to the 2 690 Coal ., ., ., 4,000 skin deserves further study. Libyan crude 011 ., 1,320 Although BaP may not be the only carcino- Asphalt from conventional crude 10,000-100,000 gen in shale oil and its products, it is probably aParis per bllllon SOURCE R M Coomes Carcmogenlc Tesflng of 011 Shale Materials TweMh 0// Sha/e Syrr- the most potent. The study summarized in poswm Proceedings Golden Colo The Colorado School o! Mines Press November table 67 shows that hydrotreating shale oil 1979 Ch 8–Environmental Considerations . 321

significantly reduces its BaP content,’{ Such a refinery workers was attributed to the reduction should be reflected in a lessening of “healthy worker effect;” i.e., employed work- its carcinogenicity, This predicted effect of ers are healthier on the average than the gen- hydrotreating was confirmed by the animal eral population. Respiratory cancer in- tests of the Kettering experiment (ref. 79, creased with increasing exposure to aro- table 66). matic HC, but was still lower than found in the general population (SMR of 79.9). The Estonian epidemiological studies and the animal studies show that crude shale oil, On the other hand, two epidemiological shale oil tars, and shale coke are all car- studies published by Canadian investigators cinogenic. Most of the studies to date suggest showed an increased cancer risk for refinery that carcinogenicity is restricted to the skin. workers. In a group of 15,032 male employees Occupational skin diseases from exposure to who worked for the Imperial Oil Co. between certain industrial oils have long been a prob- 1964 and 1973, there were 1,511 deaths. lem, as was seen in the case of the scrotal Eighty percent were ascribed to circulatory cancer among chimney sweeps, One study system disease and to malignant abnormal showed that the effects of oil contact with the growths (neoplasm). Mortality from all ma- skin range from acute inflammation to kera- lignant neoplasms in the exposed group was tosis (pitch warts which are regarded as a greater than in the nonexposed group. Can- premalignant skin change.)84 Studies of oil cers of the digestive and the respiratory sys- shale retorting workers in the United States tems increased with duration of employ- in the early 1950’s did not reveal any prob- ment. 87 lems with occupational skin disease, but 85 A further study examined 1,205 men who workers were exposed for a short time only. had been employed for over 5 years by Shell 88 A synergistic relationship has been found Oil Canada in East Montreal, { Their mortali- between the ultraviolet radiation in sunlight ty rate was compared with death rates for and coal-tar pitch volatiles in causing skin the Province of Quebec. The study group was diseases. A similar synergism might cause oc- relatively small, and only 108 deaths were cupational skin diseases in oil shale workers observed. An increased incidence of cancer on the Colorado plateau, where ultraviolet of the digestive system (SMR of 117) was not radiation levels are higher than at lower ele- statistically significant, and there was no vations. evidence of excessive lung cancer (SMR of 35.4). An excess of brain cancer was found Refining shale oil will be similar to other among those who had been exposed less than refining operations. Available epidemiologi- 20 years, but it caused only three of the cal studies do not lead to clear-cut conclu- deaths. sions about relationships between working in refineries and cancer. A retrospective mor- Societal Hazards tality study sponsored by the American Petro- leum Institute that covered 17 U.S. oil refin- Air pollutants include particulate, gases, eries and over 20,000 workers was reported and trace-metal vapors. Particulate which in 1974,86) The study group included every contain absorbed PAH can be carcinogenic. worker employed in the refineries for at least The sulfur and nitrogen-containing emissions one year between January 1, 1962, and De- are respiratory irritants. Among the sulfur- cember 31, 1971. A 94-percent followup was containing pollutants, the effects of acid obtained. There were 1,165 deaths; 1,145 sulfates, sulfuric acid, and S02 dissolved in death certificates were obtained. The stand- aerosols are the best documented. All three ardized mortality ratio (SMR) for all causes of are irritants and can make breathing diffi- death among refinery workers was 69.1 com- cult. In addition, some epidemiological evi- pared with the base rate of 100 for the U.S. dence relates chronic bronchitis and respira- male population. The lower death rate among tory diseases to SO2 and to particulate con- . — —— —— ————. .

322 ● An Assessment of Oil Shale Technologies

centrations in the air. Oxides of sulfur and ni- The severity of these hazards will depend trogen, transported from industrial areas, on many factors. Many of the risks could be may cause acidic rainfall that may reduce the very small if they are anticipated, and if ap- productivity of forest vegetation and kill fish propriate control strategies are designed and by increasing the acidity of lakes and followed. If caution is not employed, or if

streams. NOX oxides can react with HC in the there are catastrophic failures in the control

atmosphere to produce O3, photochemical systems during or after plant operation, dam-

smog, and acid rain. Airborne NH3 may cause age could be severe and long lasting. headaches, sore throats, eye irritations, coughing, and nausea in humans. Summary of Hazards and Their Severity Among the trace elements that may be emitted, mercury, lead, cadmium, arsenic, The safety and health hazards that might and selenium are considered to be potential be associated with oil shale mining, retorting, air and water pollutants. Arsenic is a car- and refining are identified in figure 62. They cinogen, which when inhaled or ingested in are ranked according to their known poten- large amounts, may also cause peripheral tial to cause injury or death. As shown, min- vascular disease and neuropathy. * Mercury ing has the highest potential for accidents, is a special problem because its vapors can due to risks from rockfalls, explosions, mov- pollute the air and earth many miles from the ing equipment, and general working condi- plantsite. It can also contaminate surface tions. There were two fatalities during the streams and ground water aquifers. It can mining of over 2 million tons of shale and the enter the food chain through the actions of production of over 500,000 bbl of shale oil. micro-organisms, and can also pose a risk of The accident rate has been one-fifth that for irreversible neurological damage to humans all mining, and much lower than that for coal who eat fish that have been contaminated by mining. However, this record was achieved in mercury in streams. small-scale experimental mines that employed, for the most part, experienced hard- Leachates from aboveground disposal rock miners. Whether safety risks will in- areas and burned-out in situ retorts also pose crease or decrease as mining activities are potential problems. PAHs, salts, and metals expanded cannot be predicted. Risks might may dissolve in surface streams and ground increase as the work force expands to include water and infiltrate public drinking water inexperienced miners and as large, rapidly supplies. Water-soluble salts in spent shale moving mining equipment is used. On the contain as much as 40 percent of the total other hand, the large mines proposed for oil benzene-soluble organic matter. All of these shale plants may reduce risks because of the materials can be dissolved in water and dis- additional room in which to maneuver ma- persed through soils. The exact nature of the chines. threat posed by these materials to human health is unknown since, for example, PAHs Fires and explosions are also identified as are found throughout nature. However, the a hazard in mining. Although no severe fires PAH content of spent shale leachates (up to have occurred to date, laboratory studies in- 100 to 1,000 times higher than is found in nor- dicate that airborne shale dust can propagate mal ground or surface water) is a matter for a methane explosion. Methane has been concern. Fluoride, if released in excessive found in low concentrations in some oil shale amounts in contaminated water, may cause deposits, especially those in the saline zone of fluorosis (reduced bone strength and debilita- the Piceance basin. Oil shale dust is, how- tion) and mottle tooth enamel. ever, far less explosive than coal dust. Dust is a major health hazard. Its effect on *Neuropathy refers to pathological changes in the the respiratory system is well-known. Exces- peripheral nervous system. sive noise is also a recognized hazard. Cancer Ch. 8–Environmental Considerations ● 323

Figure 62.—Summary of Occupational Hazards Associated With Oil Shale Development

Relative Ranking

Occupational Risks Potential Effect Mining Retorting Refining

Accidents Injury or death A

Fires and Injury or death explosions mnn

Hearing loss or Noise neurological damage

Dust Lung disease

Dust Dermatitis

v Chemical Cancer Exposure

Chemical Dermatitis Exposure [ 1 I I I

Chemical Poisoning Exposure I I I

Chemical Irritant gases Exposure 4.

KEY:

- Higher level of risk D Medium level of nsk

a Lower level of nsk

SOURCE Off Ice of Technology Assessment 324 An Assessment of Oil Shale Technologies from oil shale mining has not been identified and Health Administration (OSHA) under the as a major hazard. Although the carcinoge- Department of Labor. Most OSHA standards nicity of oil shale dusts and crude shale oil promulgated under the Act pertain to safety, has been demonstrated by some invesigators, e.g., walking and working surfaces, fire pro- insufficient information and the conflicting tection, and personal protective equipment. results of other studies prevent a determina- In addition, health standards have been pro- tion of the severity of the risk. However, the mulgated to limit worker exposure to hazard- incidence of diseases in other industries in- ous chemicals and physical hazards, such as dicates that exposure to these materials noise and crystalline silica. could be hazardous. Worker health should be carefully monitored if health damage is to be OSHA recently published a policy for the avoided, and prevention techniques im- identification, classification, and regulation proved, as the oil shale industry develops. of toxic substances posing occupational carcinogenic risks. Under this policy, a sub- Retorting is regarded as having medium stance shown to cause cancer in two animal risks in all areas. This ranking primarily studies can be classified as a “category I“ reflects the low level of knowledge about carcinogen and regulated to control worker retorting and its health and safety effects. exposure to the lowest feasible levels. However, the large variety of substances that Whether any two of the positive carcinoge- will be encountered in retorting (from raw nicity results mentioned in table 66 are suffi- shale dust to trace-element emissions) may cient to cause a category I classification pose as yet undetected health hazards. Of awaits NIOSH review. special concern is the possibility of carcinogens in shale oil and its derivatives. The Federal Mine Safety and Health Possible synergisms in MIS operations (which combine mining with retorting) could in- Amendments of 1977 (FMSHA) crease the level of risk. These amendments apply to all metal and In contrast, shale oil refining is regarded nonmetal mines. They prescribe health and as posing no special hazards in many areas safety standards “for the purpose of the pro- and only moderate risks in the others. This is tection of life, the promotion of health and because most of the problems that will be safety, and the prevention of accidents. ” associated with shale oil processing should FMSHA established the Mine Safety and be similar to those experienced in convention- Health Administration (MSHA) in the Depart- al petroleum refining. ment of Labor, and directed the Secretary of Labor to develop, promulgate, revise, and enforce health and safety standards for work- Federal Laws, Standards, ers engaged in underground and surface min- and Regulations eral mining, related operations, and preparation and milling. In addition, each mine oper- This section discusses the Federal laws ator is to have a mandatory health and safety and standards applicable to oil shale occupa- training program. FMSHA also authorized tional health and safety, and some aspects of the Secretary of Labor to require frequent in- environmental health. Other laws which gov- spections and investigations of mines: at least ern specific impacts on air, water, and land four times a year in the case of underground are discussed elsewhere in this chapter. mines, and at least twice a year in surface mines. Records of mine accidents and expo- Occupational Safety and Health Act of 1970 sures to toxic substances are to be maintained by mine operators. This Act was passed to assure every working person “safe and healthful working condi- Section 101(a) of FMSHA requires that tions;” it established the Occupational Safety standards on toxic material or harmful physi- Ch. 8–Environmental Considerations ● 325 cal agents be set to “most adequately assure should be noted that if specific operations are . . . (on the basis of the best available regulated by other laws (e.g., Clean Air Act, evidence) that no miner will suffer material Clean Water Act) their authority would prob- impairment of health or functional capacity ably take precedence over regulations pro- (even if such miner has regular exposure to mulgated under TSCA. TSCA regulations the hazards dealt with by such standard for would be promulgated only when regulations the period of his working life). ” NIOSH has under the other Acts failed to remove a haz- the responsibility to determine when the ma- ard. Also, chemicals that are not sold in com- terial or agents are toxic at the concentra- merce are considered “R&D substances” and tions found in the mine. are exempt from some of the requirements Warning labels, protective equipment, and under the Act. control procedures are to be employed “to Under TSCA, EPA must require industry to assure the maximum protection of miners. ” give notice 90 days prior to beginning the Medical examinations and tests, where ap- manufacture of any new substance that is not propriate, are to be provided at the opera- listed on EPA’s Inventory of Existing Chem- tor’s expense to determine whether a miner’s icals. EPA can also require industry to test health is adversely affected by exposures. the toxicity of chemicals already in commerce that may pose an unreasonable risk to human Memorandum of Understanding Between health or the environment. Shale oil and its OSHA and MSHA refined products are included in the inventory list and therefore are not subject to pre- Because of the overlapping jurisdiction be- market regulations, but testing can be re- tween OSHA and MSHA, an interagency quired under other sections of TSCA if the agreement was executed on March 29, 1979, Administrator of EPA determines such sub- to allocate the responsibilities for mining stances may pose an “unreasonable risk” to safety between the two agencies. The agree- health or the environment. ment established that as a general policy, un- safe and unhealthful working conditions on Control and Mitigation Methods minesites and in milling operations would come under the jurisdiction of MSHA. Where Some of the oil shale’s health and safety these do not apply, or where no MSHA stand- hazards can be reduced by using the pollution ards exist for particular working conditions, control technologies described elsewhere in OSHA and its regulations would apply. this chapter. Others will require specific in- Where uncertainties arise about jurisdiction, dustrial hygiene controls. The three major the appropriate MSHA District Manager and control methods are: OSHA Regional Administrator (or the respec- ● tive State designees in those States with ap- worker training programs, including an proved mine-safety plans) shall attempt to intensive training program for new work- resolve the matter. If they cannot do so, the ers and refresher courses for workers issue will be referred to the national offices throughout their careers; of the two agencies. If the issue cannot be ● the design and maintenance of safe resolved at that level, it will be referred to the working environments; and Secretary of Labor for a final ruling. ● health monitoring programs, including examinations and recordkeeping. The Toxic Substances Control Act Initial training programs and refresher of 1976 (TSCA) courses are required by OSHA and MSHA. These agencies also promulgate standards TSCA covers the manufacturing, process- for working environments. Health inspections ing, distribution, use, and disposal of chemi- are sometimes included in OSHA/MSHA rou- cal substances in commerce. However, it tine inspections, and special health inspec- 326 ● An Assessment of Oil Shale Technologies tions can be made if the agencies determine physical agents such as ionizing radia- that a serious health hazard exists. At pres- tion, heat, and noise stress; ent, exchange of worker-health information ● evaluation of devices for controlling among companies is not required, although worker exposure, such as hermetic some companies, especially in the coal mining seals, ventilation equipment, and per- industry, have organized such programs to sonal protective equipment; provide data regarding occurrences of black ● environmental monitoring to determine lung among miners who change jobs within ambient levels of PAHs, trace elements, the industry. and other potentially harmful substances; Summary of Issues and R&D Needs ● determination of the pathways followed by PAHs, salts, toxic trace elements, and Issues other substances; and ● additional controlled animal experi- The effect of the scale of operation of fu- ments to determine the toxicity, muta- ture oil shale facilities on worker safety is genicity, and other characteristics of the still unknown. As indicated previously, the oil raw materials and products encoun- shale industry to date has a good safety rec- tered in oil shale processing, and evalua- ord. It is not clear whether or not this record tion of their synergistic interrelation- can be maintained in large facilities and in a ships. large industry. A mechanism that would aid in all of these The protection of worker health and safety studies, and in other ones that evolve as the in an industry that is developing with great industry is created, would be an oil shale speed is also a major concern. To prevent un- health registry or central repository for the due risks, it is important that the health haz- health records of oil shale workers. These ards of oil shale and its related materials be data would aid in the statistical work needed identified, and that appropriate measures be to detect extraordinary health trends among employed for their control. the workers. These, in turn, could be related to working conditions and used to improve R&D Needs preventive and protective measures. Research is needed in the following areas in order to improve the understanding of the Current R&D Programs potential effects of oil shale development on the workers and on the public: The following is a partial listing of the health and safety R&D projects now under- ● additional data gathering and analysis way both in the private sector and by Govern- are needed on the health effects of par- ment agencies. ticulate generated during oil shale mining and processing. Studies should in- ● Tosco is studying the fire and explosion clude: a) identification of absorbed potential of oil shale mining and process- PAHs; b) determination of particulate ing. size distributions; c) evaluation of the ● The American Petroleum Institute is risk of fibrogenicity and carcinogenicity; studying the effects of oil shale on fe- d) ranking of the unit operations in terms tuses by exposing pregnant rats to raw of their degree of risk; and e) determina- and spent shale dust and shale oil. tion of their health effects on nearby ● EPA is performing or contracting work communities with respect to, for exam- through 10 of its laboratories to support ple, chronic bronchitis; the regulatory goals of the agency and to ● characterization of worker exposure to ensure that an oil shale industry will be PAHs, other chemical hazards, and developed in an environmentally accept- Ch 8–Environmental Considerations ● 327

able manner. The EPA Cincinnati labo- Policy Considerations ratory is studying the handling of raw shale and the disposal of spent shale. Air The major issue surrounding the health pollution, wastewater characteristics, and safety aspects of oil shale development is and water treatment methods are also the paucity of information on the nature and being studied and evaluated. The Las severity of the health effects of oil shale, its Vegas laboratory is attempting to design derivatives, waste products, and emissions. and implement an optimal wastewater The effect of the scale of operation of oil treatment system. The Athens, Ga., labo- shale facilities on worker safety is also un- ratory is characterizing retort effluents known. Policy options for addressing these and developing instrumentation and con- issues follow, trol systems. Biological and health effects studies are being conducted at the Inadequate Information Gulf Breeze and Duluth laboratories; these are designed to determine path- Additional study is needed to determine the ways by which HC enters the food chain, effects on human health of the various chemi- to characterize the aquatic life in the oil cal substances and particulate encountered shale region before oil shale develop- during the mining and processing of oil shale ment occurs, and to determine the car- and its products and wastes. Such informa- cinogenic, mutagenic, and fetal effects tion would be useful in identifying and miti- of oil shale and its derivatives and gating long-term health effects on workers wastes. EPA is also preparing pollution and the public. It would also be useful in set- control guidance documents for the oil ting new standards for worker health and shale industry. safety. Options for increasing the amount of DOE is conducting source characteriza- information include expanding existing R&D tion studies to determine emissions prop- programs; coordinating R&D work by Federal erties and their health effects. Included agencies; increasing appropriations to agen- is an extensive program for sampling re- cies to accelerate their health effects studies: tort liquids, solid products, and wastes. and passing new legislation specifically call- Streams to be sampled include mine vent ing for study of the health and safety aspects gases, mine air, retort water, raw and of oil shale development. Methods for imple- retorted shale, process water, and par- menting these options are similar to those de- ticulate, Biological testing will be con- scribed in the air quality section of this ducted to include short- and long-term chapter. animal exposure tests and medical and epidemiological studies of oil shale work- Health Surveillance ers. ● The U.S. Department of Agriculture is Collection and maintenance of oil shale sponsoring work related to the social workers’ health records in a health registry consequences of oil shale development would facilitate hazard identification and and the revegetation of solid waste dis- planning to reduce risks. The registry might posal areas. be located in a regional medical center, with ● The National Science Foundation is or without Federal agency input. Funding sponsoring projects to characterize the could be provided by Government, labor, or contaminants in spent shale and to de- the oil shale developers, or by a cost-sharing velop techniques for managing them. arrangement between these groups. The reg- ...

328 ● An Assessment of Oil Shale Technologies istry location could be the focus of regular standards are necessary to protect worker meetings to exchange health and safety in- health and safety. In addition, sampling meth- formation and to disseminate basic scientific ods should he in place to monitor exposures. findings that apply to the oil shale industry. Worker-Education Campaigns Exposure Standards Worker education is already a part of the As information about chemical health haz- mining industry. Information about newly ards is developed and analyzed, NIOSH and identified risks should be conveyed to work- MSHA should determine whether exposure ers as soon as possible.

Land Reclamation Introduction tion from underground mining and in situ development could affect aboveground condi- An oil shale industry will use land for actions through subsidence in the mined-out cess to sites, for facilities, for mining, for re- areas. But this might not happen until long torting, for oil upgrading, and for waste dis- after operations at the site have ceased. posal. The extent to which development will affect the land on and near a given tract will Oil shale plants must be built to comply be determined by the location of the tract; the with the laws and regulations that govern scale, type, and combination of mining and land reclamation and waste disposal, Never- processing technologies used; and the dura- theless, there will still be effects on the topog- tion of the operations. Comparatively little raphy (ultimately the terrain could be modi- land will be disturbed by the retorts and up- fied to a landscape unlike the original) and on grading facilities themselves, but much larger wildlife (through changes in forage plants areas will be disrupted by mining activities and habitats). In addition, unless appropriate and waste disposal operations, particularly if control methods are developed and applied, the deposits are developed by open pit mining as required by law, the large quantities of in conjunction with aboveground retorting, raw and retorted shale could pollute the air which produces retorted shale as a process with fugitive dust and the water with both waste. runoff and the effluent that has percolated through raw shale storage piles and waste It has been estimated that a l-million-bbl/d disposal areas. Solid wastes such as cata- industry using aboveground retorts would lysts, water treatment sludges, and refinery process approximately 600 million tons of coke, will be produced in relatively small raw oil shale per year, and would require the 3 amounts, but will contain toxic components disposal of approximately 10 billion ft of that could degrade water quality unless prop- compacted spent shale. Less of the surface erly controlled. Similar care will be needed to would be disturbed by in situ retorting, al- remove, store, dispose, and revegetate the though the surface would nevertheless be dis- large amounts of overburden that will be turbed by drill pads. However, the disturb- handled in open pit mining operations. ance would be different and less drastic than from an open pit operation. At the same time, Several avoidance and mitigation strate- the amount of subsurface disturbance for a gies have been proposed to minimize the over- given level of oil production would be in- all land impacts of oil shale development. Oil creased because, although with an in situ shale plants, access corridors, and disposal process relatively little oil shale is mined, oil areas could be sited to avoid esthetic deteri- recovery rates are lower and some leaner oil oration and improve the feasibility of land shales would be retorted. Subsurface disrup- reclamation and revegetation programs; and Ch 8–Environmental Considerations ● 329 mining and in situ retorting could be designed gated governing oil shale mining, processing, to decrease surface subsidence or reduce its and waste disposal, rate. In addition, most development plans Each State in the oil shale region has rec- propose to protect existing wildlife habitats lamation laws that apply to all mining opera- and migration routes, where possible, and to tions. USGS has regulations that control oil enhance the characteristics of adjacent shale operations only on Federal lands. In ad- areas to promote wildlife readjustment. Rec- dition, the Department of the Interior (DOI) lamation and revegetation techniques have established environmental stipulations gov- been developed and tested on a small scale erning lands under the Prototype Oil Shale over limited periods of time for aboveground Leasing Program that include additional spe- solid waste disposal, and backfilling mines cific reclamation standards. The Surface has been suggested to reduce the quantity of Mining Control and Reclamation Act solid material that must be disposed of on the (SMCRA), passed in 1977, provides a system surface. of comprehensive planning and decisionmak- As with air and water control methods, a ing needed to manage land disturbed by de- number of uncertainties surround the feasi- velopment. However, the Act applies only to bility of methods for minimizing land disturb- coal, and the detailed reclamation standards ance and its effects on wildlife. At issue are promulgated under it may not be appropriate the feasibility of land restoration and revege- to oil shale in all cases. However, it provides tation techniques, and the adequacy of strat- a guide to measure the strictness of other egies to control the leaching of solid waste laws applicable to oil shale for matters that and raw shale piles. The methods for dispos- are not specific to coal. ing of solid wastes by backfilling mines and for controlling leachates from solid waste dis- The Colorado Mined Land Reclamation Act posal piles and underground retorts were dis- is administered by a board and division with- cussed previously in the water quality sec- in the Department of Natural Resources. It tion. In this section the reclamation and re- requires permits for each mine operation, vegetation of processed shales on the surface stipulates application procedures and crite- are examined. ria for permit approval, requires surety (e.g., performance bonds), and sets procedures for enforcement and administration. The Act’s Reasons for Reclamation performance standards are similar in concept to those established by the Federal Coal The primary purpose of reclaiming the sol- Act. They are not, however, as detailed since id wastes is to reduce their detrimental ef- they must apply to all minerals from oil shale fects. These include: changes in the land- to sand and gravel (except for coal, which has scape, the disruption of existing land uses, been amended to correspond to the new Fed- the loss of the biological productivity on a eral requirements); and, in some cases, they given land surface, and the degradation of air are not so strict. For example, an operator and water quality by erosion and leaching. In may choose the postmining use of affected addition, secondary impacts such as fugitive land; whereas, the Federal standard requires dust would affect not only the immediate area approval of such use by the permitting au- but adjacent areas as well. thority according to strict criteria. Also, an operator may substitute other lands to be re- Regulations Governing Land Reclamation vegetated if toxic or acid-forming materials will prevent their successful vegetation, and In order to ensure that mining operations the mitigation of such conditions is not feasi- will incorporate reclamation concepts and ble. Mining would probably be prohibited minimize adverse effects, legislation has been under similar conditions by Federal stand- passed and regulations have been promul- ards, if they were applicable to oil shale.

63-898 L - 80 - 22 330 ● An Assessment of Oil Shale Technologies

The Utah Mined Land Reclamation Act is quired “best available control technologies” administered by the Board of Oil, Gas, and to minimize all environmental damage. Mining. It provides for various powers of the board, administrative procedures, surety, In summary, while reclamation is required and enforcement. However, the Utah law only under State laws, there are no performance establishes general reclamation goals and standards specific to oil shale. Regulations does not set detailed environmental perform- vary and are not so strict as the general re- ance standards as do SMCRA and the Colora- quirements of the Federal coal law. There are do law. These goals include minimizing envi- additional requirements that pertain to Fed- ronmental degradation or “future hazards to eral leases. public safety and welfare” and establishing “a stable ecological condition comparable Reclamation Approaches with . . . land uses. ” They are open to broad discretionary interpretation by the Oil, Gas, Several reclamation approaches can be and Mining Board. used to reduce the deleterious effects asso ciated with the disposal of spent oil shale. The Federal standards that do apply to oil These include returning surface wastes to shale are limited to Federal lands;* they do mined-out areas; the chemical, physical, or not govern operations on private land, and vegetative stabilization of processed shale; are in no way comparable to the detailed and combinations of these approaches. standards that apply to coal under SMCRA. For example, 30 CFR 231.4 establishes very general goals requiring reclamation to Reducing Surface Wastes “avoid, minimize or repair” environmental Mine backfilling was discussed in the sec- damage. Specific details must be set by site- tion on water quality. As was indicated, the specific leases. It is not applicable to true in disposal of wastes underground will be more situ oil shale methods using boreholes and expensive than surface disposal, but there wells, thus will not govern spent shale leach- could be less surface subsidence caused by ing for this technology. Part 23 of title 43 the collapse of overburden materials above authorizes, but does not require, the Bureau the mined-out rooms. of Land Management (BLM) District Manag- ers to formulate reclamation requirements and USGS Mining Supervisors to set stand- Chemical or Physical Stabilization ards for mine plans. One approach that can be used to reduce More important are specific lease stipula- erosion on disposal sites is to use chemical or tions. Environmental stipulations have been physical methods to stabilize the processed included in the Prototype Oil Shale Leases shale. Chemical stabilization may be short governing operations on current Federal term—from a few months to a couple of lease tracts. The reclamation and revegeta- years—or longer term. Short-term methods tion performance standards that are included consist of spraying biodegradable chemicals take into account the experimental nature of on the surface; these reduce wind and water the program. For example, lessees are given erosion by binding particles together. Such 10 years to demonstrate a necessary revege- chemicals have been used along with revegetation technology; however, operations must tation to achieve temporary stability.89 The cease if such technology is not developed. The chemicals do not appear to inhibit seed germi- lease and the environmental stipulations are nation; however, they are expensive and, at administered under the broad discretion of best, temporary. the Area Oil Shale Supervisor, who has re- Longer term stabilization consists of add- *About 70 percent of the oil shale land, containing about 80 ing materials such as emulsified asphalt or percent of the resources, is federally owned. processed limestone to induce chemical reac- Ch. 8–Environmental Considerations ● 331 tions that harden the mixtures. Hardening ically pleasing, and restrict the future uses of can be accomplished by wetting of shales the land. processed at high temperatures, followed by compaction. The hardened products have the Vegetative Stabilization advantages of relatively high resistance to Vegetation offers the most esthetically erosion and reduced leaching of soluble salts pleasing and productive means of stabilizing into the ground water. Their disadvantages waste materials. It also allows for multiple are that they are esthetically unattractive land use. In addition, vegetation theoretically and cannot support vegetation unless covered offers a means of continually adapting to the by a suitable plant growth medium. The long- changing environmental conditions that are term effects of chemical stabilization are at likely to occur on the disposal site over time. present unknown. Vegetation will also reduce the overland Erosion can be reduced physically by cov- flow of water and sedimentation during in- ering the processed shale with a layer of tense storms by increasing the permeability rocky material. Like the chemical ap- of the soil. This will increase the infiltration proaches, physical methods inhibit the estab- of water, thus reducing surface water and lishment of a vegetative cover, are not esthet- pollution and flood hazards. Vegetative cover

Photo credit OTA staff

A variety of plant life will be required for revegetation of spent shale areas 332 ● An Assessment of Oil Shale Technologies will tend to ameliorate micro-climatic condi- The characteristics of processed shales tions and also reduce wind erosion and ex- that make them undesirable as a plant tremes in soil temperatures. growth media are:

● small particle size (texture), which encourages erosion; and compaction or ce- Combinations of Stabilization Methods mentation, which results in low permea- Perhaps the most effective means of stability to water and poor root penetration; bilizing waste piles will be combinations of ● high pH (i. e., high alkalinity), which discourages plant growth by making essen- approaches such as hardening the processed tial nutrients insoluble and therefore un- shales by chemical means and then establishing vegetation on a friable soilcover atop the available; ● high quantities of soluble salts, including solidified wastes. The vegetative stabilization elements toxic to plant growth that in- of soil-covered spent shale appears to be the hibit water and nutrient uptake; and preferred reclamation approach because the ● the dark colors of some spent shales, chemical and physical properties of proc- which absorb solar radiation thus pro- essed shale make it much less amenable to ducing high temperatures that inhibit supporting plant growth that resembles the seed germination and dry the soil diversity and density of the present natural vegetation ecosystems. through evapotranspiration. The characteristics of spent shale from several processes are summarized in table 68 and discussed below. The Physical and Chemical Characteristics of Processed Shale Texture The physical and chemical characteristics Raw shale that is finely crushed, as in the of the processed shale are determined by the TOSCO II process, produces a fine silty spent source of the raw shale; its particle size after shale that is highly susceptible to erosion. crushing; and the retorting parameters such However, if the shale is coarsely crushed as as temperature, flow rate, and carbonate de- in the gas combustion processes, a coarse- composition, which vary with different retort- textured spent shale is produced that is less ing processes. susceptible to erosion. The resistance to wet-

Table 68.–The Chemical and Physical Properties of Processed Shales

Processing Process temperature Color Texture a Salinity b pH TOSCO II ., . . . ., . . . . LOW Black Fine 18 9.1 Gas Combustion . . ., ., ., . . High Gray Coarse 14 8.7 Paraho Directly heated. ., ., ., ., High Gray Coarse 7 12,2 Indirectly heated . . . . ., . . . Low Black Coarse 10 12,3 Union “A” retort ...... High Gray Coarse 3-4 11,4 ‘‘B’ retort ., ... ., Low Black Coarse 13 8.5 Lurgl-Ruhrgas ., ., ., . . Low/high Gray Fine/coarse 3-7 11-12 aFl”~.[~Xlu~@ processed Shales are predornlrranlly smaller Ihiln 2 mm while coarse-[ extured processed shales are r)redomlnantly larger than 2 Inrn bThe electrical ~OfrdUCtlVltY (rnrnhO/Crn) of a safuraled extract preparedfrOrn spent shale Partlclw sfnaller than p mm SOURCE Planf Resources Inshwie The free/arrrallorI oJProcessed O// Shale, prepared for OTA, January 1980 Ch 8–Environmental Considerations ● 333 ting of the spent shale originally produced in 3:1 was found to be the maximum allowable the TOSCO process90 91 has been overcome by for slope stability.” introducing steam in the last step of the proc- Water diversion and sediment and drain- ess. Spent shales produced by retorting at age catchments are proposed to collect mate- higher temperatures have not been reported rials washing off site in order to prevent their as resistant to wetting, entering the aquatic ecosystem. It is likely The capacity of spent shales to retain that sediment basins will require long-term water is moderate. Infiltration rates on fine- maintenance to prevent their filling up and textured spent shale (TOSCO II) range from releasing toxic substances. 92 93 near zero to as high as 3 to 4 cm/hr. Those Furrowing, pitting, and gouging are other for uncompacted coarse-textured spent shale 94 useful methods of surface manipulation. Shal- are higher. Rates of from 2 to 4 cm/hr will be low furrowing on the contour cuts down on sufficient for the surface runoff to be ab- erosion losses. Pitting and gouging not only sorbed from most low-intensity storms but not control erosion but also act as a moisture col- from high-intensity ones that occasionally oc- lector.’” They are particularly useful in dry cur during the summer. Moistening and com- areas and where vegetation is dependent on pacting the spent shales may achieve close to snowmelt. A variation of gouging is accom- zero infiltration rates which could be impor- plished by using a land imprinting machine.’” tant for reducing the leaching of salts into the On soil-covered processed shales, the depth ground water. Compaction is more desirable of the depressions will be determined by the for spent shales deep in the pile, beyond the thickness of the soil cover necessary to pre- plant rooting zone; uncompacted materials vent the processed shale from being exposed. may be preferable near the surface directly under the topsoil layer. Mulches of various types have been used both to establish vegetation and to reduce the 99 Erosion Control temperature of the soil surface. Hydro- mulch, applied at a rate of 1,500 lb/acre is Because small particle size encourages one that is preferred in some studies. 10’) How- erosion, erosion control is needed to prevent ever, it is expensive and, in some cases, has sediments and toxic elements from entering been reported to provide little beneficial ef- the aquatic ecosystems downstream, or the fect on already established stands. ’()’ A increase of dust in the air. Additionally, ero- cheaper natural mulch applied at a rate of sion removes the surface layers that encour- 3,000 lb/acre,102 such as native hay or straw, age plant growth, which take time to develop. is more likely to be used, but it must be taken from a certified weed-free field to prevent in- The steepness of the slopes, their length, troducing weedy species. It is uncertain that the drainage provided, control structures, the sufficient mulch will be available, especially density of vegetation on the slopes, and the weed-free hay, for an oil shale industry of 1 types of spoils and soil materials on the site million bbl/d within 10 years. will affect the extent of erosion. Mulching, surface manipulation, and the timing of top- Straw or hay mulches often need to be sta- soil placement, followed by the immediate es- bilized by the addition of emulsified asphalt tablishment of vegetation, will usually reduce (300 gal/acre), ’03 or by crimping into the soil. erosion rates.95 Flatter or shorter slopes will Rock mulches have been found to be superior also aid in erosion control. The recommended to barley straw with respect to plant survival design slope of 4: I (horizontal: vertical) with and growth. 104 Excelsior type materials, are 20-ft benches every 50 ft of vertical rise is also very effective, but they are costly and at- considered prudent and necessary. A slope of tract rodents. ’05 . .

334 ● An Assessment of Oil Shale Technologies

Cementation Another means of assisting plants to survive in nutrient-deficient soils is by inocu- Processed shales retorted at high temper- lating them with selected strains of fungi that atures and then moistened harden within produce mycorrhizae. Mycorrhizae are struc- about 3 days in a reaction similar to that tures that combine the plant root and a fun- which takes place in cement. 106 The product of gus to increase the survival and growth of spent shale cementation is still susceptible to plants in nutrient-deficient soils by increasing weathering, and the reaction generally takes nutrient uptake and resistance to a variety of place deeper in the waste pile where the stresses. process is accelerated by compaction, heat, and high pressure. If shale hardened by this Free-living soil microbes are expected to process were to be exposed by erosion, it begin recolonization of the disturbed area. might prove to be impenetrable to moisture They will be valuable in fixing nitrogen from and plant roots. the atmosphere and recycling organic forms. How soon this will begin is not known. It is Alkalinity known, however, that wetting and drying stored topsoil deteriorates the conditions fa- Processed shales retorted at temperatures vorable to such microbes. For this reason, 0 0 of about 500 C (900 F) are less alkaline (pHs prior to use topsoil should be deeply buried to ranging from 8 to 9*), than those retorted at prevent the wetting and drying that occurs 11 1 750° to 800° C (1,400° to 1,500° F) (pHs of 11 near the surface. to 12). In general, the higher the alkinity of its Plant species used to reclaim spent shales leachates, the lower the concentrations of possibly will require inoculation with mycor- soluble salts in the processed shale. At higher rhizal fungi to enhance their growth and sur- pHs many plant nutrients are insoluble, and vival. 112 Colonizing species on disturbed lands plants will generally not grow in a strongly al- are often nonmycorrhizal. 113 It has also been kaline soil medium. found that with increasing soil disturbance or If processed shales are to be used directly the addition of processed shale, the ability of as a growth medium, their alkalinity must be the soil to be infected with mycorrhizal fungi reduced. This can be done by leaching follow- decreases. The most successful revegetation ing deposition and proper compaction, or by species become mychorrhizal only late in adding costly acids or acid-formers. 107 Expo- their establishment. There appears to be no sure to the atmosphere over a period of sever- significant effect of the seed mixture, the fer-, al months to several years will reduce it natu- tilizer, the mulch, or irrigation on a soil’s po- rally. tential for mycorrhizal infection following its disturbance. 114 Nutrient Deficiencies Salinity Spent shales have been shown to be highly deficient in the forms of nitrogen and phos- Because spent shales are often quite salty, phorous available to plants. 108 Therefore ni- they present major problems for establishing trogen and phosphorus fertilizers need to be vegetation, and for the water quality from added. These can be applied at any time of surface runoff or drainage through them. 115-120 year but spring fertilization has been recom- High concentrations of salt in the soil media mended to prevent burning and to reduce fer- restrict water and nutrient uptake. * These tilizing weedy species. 109 It will probably be can only be lowered by leaching with supple- necessary to fertilize with nitrogen for sev- mental water. eral years until the ecosystem begins to fix 110 and recycle its own nitrogen. *Electrical conductivity is a measure of a soil’s salinity. A *PH is a means of expressing acidily or basicity. It ranges conductivity of 4 mmho/cm is considered saline, and above 12 from 1, highly acidic through 7, neutral, to 14, highly alkaline. mmho/cm, highly saline. Ch. 8–Environmental Considerations ● 335

Leaching essed shale leachates, selenium and arsenic are not cause for concern, but fluorine, Depending on the characteristics of the boron, and molybdenum are more serious. ’z] spent shales, about 5 acre-ft of water per Plants grown on processed oil shales and soil- acre will be needed for leaching and plant 122 covered processed shales in northwestern growth. This is based on a net requirement Colorado have been found higher in molyb- of 48 inches of leaching water and an 80-per- denum and boron than plants grown in ordi- cent irrigation efficiency. The actual supple- nary soil, although their selenium, arsenic, mental water needed will vary with annual and fluorine contents were moderate. 124 precipitation, evaluation, and aspect, To ensure adequate infiltration and to prevent erosion, it should be continually applied at low Excessive Heat rates (e. g., 2 to 3 cm/hr) and in a spray form. The color of the processed shale reflects Leaching will probably not be uniform over the amount of residual carbon on the retorted the entire surface, therefore surface monitor- particles. Black and gray processed shales ing and additional localized leaching may be are produced by low- and high-temperature needed. processes, respectively. The color influences the surface temperatures of the plant growth Toxicity media which, in turn, affects seed germina- High concentrations of boron in spent shale tion and the plant-water relationship. The can be toxic to plants. On the other hand, the dark-colored material warms up earlier in elements molybdenum, selenium, arsenic, the spring, inhibits seed germination more, and fluorine (also found in shale) are general- and creates drier soils than does lighter col- ly not toxic to plants. However, when these ored processed shale. Temperatures of up to 78° C (196° F) have been reported for the elements are taken up by plants, they can be- 125 126 come toxic to grazing animals. Susceptibility TOSCO II material. The color can be to such toxicity varies among animal species modified to a certain extent by the use of sur- as well as within a species. It is dependent on face mulches or a covering of topsoil-like ma- the concentration of the elements within the terial, which reduces many of the salinity and plant, the size of the animal, its daily diet, and alkalinity problems as well as the need for its general physiological condition. The condi- supplemental water. tions that encourage the uptake of these ele- Another temperature problem encountered ments by plants, and their resulting toxicity in the massive disposal of spent shales is that in animals are complicated and poorly under- the processed shales will probably go into the stood. Proper management should help to disposal pile at temperatures in excess of 40” avoid or alleviate the problems with livestock. C (98° F). This will create a heat reservoir, It This can be achieved by restricting livestock is not known how long it will take to cool, If a grazing to seasons when the elements are spent shale pile is warmer than normal soils present at low concentration in the plants, by within the area, the site would be drier than varying the mix of plant species to be used in expected because of the increased potential the grazing areas, and by feeding seques- for evapotranspiration. tering supplements to reduce the toxicity of the elements. The management of wildlife, however, is very difficult and problems will Use of Topsoil as a Spent Shale Cover persist in this realm. An alternative to revegetating directly on The dominant soluble ions in spent shale spent shale is the establishment of vegetation are sodium and sulfate, with abundant calci- on a cover of topsoil or topsoil-like over- um, magnesium, and bicarbonate also pres- burden material placed over the spent shale. ent. Of the trace elements identified in proc- Such a soil cover offers several advantages. — —

336 ● An Assessment of 0il Shale Technologies

Because it does not have the problems of high basins will also be useful in deciding what salinity and alkalinity, no supplemental water materials to use. It is doubtful that the capil- is required for leaching. The material is a lary rise of salts will be a problem unless soils more suitable medium for plant growth be- are continually exposed to saturated condi- cause it has greater water-holding capacity, tions. This might happen if improper engi- more nutrients, and promotes a more intimate neering of the disposal site created seeps or relation with plant roots. allowed pending. Economics and a possible lack of longevity are the primary disadvantages of using a soil Species Selection and Plant Materials cover. Additional costs would be incurred for segregating suitable materials from those The selection of plant materials to be used with undesirable properties, for transporting in reclaiming processed shale is determined and storing materials, and for surfacing over by several factors, the most important of the spent shales. In time, the natural geologi- which is species adaptability. Adaptability cal process of erosion may eventually cut (suitability) is intimately tied to the ability of a through the soil cover and expose the spent plant to complete its entire lifecycle, and to shale. An artificial soil profile using over- reproduce itself from year to year over a long burden materials between the topsoil and the period. The plant’s growth form, drought re- spent shale would greatly reduce, if not elimi- sistance or tolerance to stress, mineral nutri- nate, the problem. With proper management tion requirement, and reproduction charac- most erosion should be localized. However, teristics must all be considered. In addition to with improper management such as overgraz- being adapted to the growth medium, plants ing, reductions in vegetative cover could oc- must also be adapted to local temperatures, cur that would allow larger areas to be ex- elevation, slope, aspect, and wind conditions. posed. If erosion were gradual over a few They should be able to survive the weeds and hundred years, the vegetation possibly would animals that may invade the site. Palatability adapt to the thinning soil cover, and natural to livestock and wildlife as well as availabili- leaching and weathering could render the ty of seed and competition among species spent shale a more suitable growth medium. being planted are also important factors. Despite these disadvantages, the use of a soil cover will provide for the more rapid estab- In addition to the results of actual revege- lishment of a vegetative cover that will per- tation test plots, several information sources sist longer than would vegetation established and guides are available to assist in the selec- directly on spent shale. tion of species adapted to conditions likely to The depth of the soil cover needed will vary be encountered in oil shale reclamation.130-134 from site to site, but will generally range from These include the Plant Information Network 1 to several ft in thickness. 127 128 Soil surveys computerized data bank located at Colorado 135 of the Piceance basin indicate that sufficient State University. soil and soil-like material exists in the disposal sites, particularly those with deep alluvial In general, mixtures of various grasses, deposits, and this should provide adequate forbs, shrubs, and in some cases trees, are desirable because they offer a greater range cover material. 136 of adaptation. Mixtures may include spe- The selection of topsoil or topsoil-like over- cies adapted to each of the different microcli- burdens will have to be based on chemical mates, moisture levels, and soils. The results and physical analyses. This is important be- of using a well-planned mixture can be a fast- cause the soil types and their toxicities vary. establishing, long-term cover that is less vul- The treatment of the soil cover will be similar nerable to pests, disease, drought, and frost. to the treatments of soil used for the reclamation of surface-mined coal areas, about which Recommended mixtures used in test plots there is more knowledge.129 Soil surveys of the may include both indigenous (native) and in- Ch. 8–Environmental Considerations ● 337

troduced perennial species. In one study, a Seeding is best done in late fall or early mixture of native and introduced species dis- spring when soil moisture is high, although played the highest productivity and allowed the operation of seeding equipment in the the least amount of invasions by weeds.’}’ Al- spring may be hampered by wet soil condi- though a mixture of non-native species had a tions.’” Seeding rates may vary from 10 to 30 higher plant density, it also allowed the great- lb of pure live seed per acre depending on est invasion of weeds. 138 Weeds are undesir- slope and whether the seed is broadcast or able in that most are annuals (complete their drilled. Drier exposures and broadcast tech- lifecycle in 1 year) dependent on precipita- niques require more seed. tion; they are therefore an unreliable erosion control. They also compete with the more de- Another problem in propagating plants sirable perennial species (species that persist from seed is dormancy of seed. Extensive for several years) for water and nutrients. treatment of the seed may be required in These annuals are expected to disappear order to overcome it. For these reasons, vege- with natural succession over a few years. tative propagation is a necessary alternative to seed propagation for producing planting Species selection is complex and involves, stock of native species. in addition to considerations of the species itself, a tradeoff among many interacting fac- Containerized Plants 139 tors. These include: Federal, State, and lo- Container-grown plants have been success- cal reclamation requirements; rehabilitation fully used in several oil shale revegetation and land use objectives; the nature of the site; studies. 142-144 They offer several advantages the timing of the program; species compatibil- over seed: 145 ity; mechanical limitations in planting; seed and seedling availability; maintenance after they make efficient use of scarce seed or planting; and cost, seeds especially adapted for harsh sites, plant survival and growth are optimized by rapid root growth into the surround- Seeds ing soil, Planting seed by drilling or broadcasting is well-developed plants are generally able to withstand grazing or other stresses, a common way of establishing vegetation in a and reclamation plan. Seed is available commer- they can be inoculated with fungi just be- cially from collectors and seed companies. ’40 fore seeding to ensure the development While many commonly used seeds are availa- of mycorrhizae. ble from dealers under contract, procedures for cultivating wildland plants for seed pro- Container-grown plants can be hardened to duction have generally not been developed. the fluctuating and more extreme environ- Also, certain varieties of the native plant mental conditions they will encounter at the species may not be available from commer- revegetation site by gradually exposing them cial sources. Until reliable seed production to drier conditions and greater temperature techniques are developed (which may require extremes. The higher cost of container-grown up to 10 years), seeds for propagating native stocks is offset by their better survival rate. 146 plants will generally have to be collected They are recommended for fall or early from wildland populations. This may be a spring planting on harsh sites where estab- problem for a large oil shale industry, since lishment of seeds may be difficult or impossi- seed production from wildland populations ble due to erratic or low precipitation or can be unpredictable from year to year; some other environmental stresses. Bare root stock native species produce abundant seed crops is another alternative, but can only be used only in years when conditions are especially with sufficient soil moisture to ensure good favorable. root penetration into the growth medium. 147 ——

338 ● An Assessment of Oil Shale Technologies

Timing of Reclamation Cost of Reclamation Initiation of revegetation efforts will be Estimates of average reclamation costs delayed during the first 3 to 10 years of range from $4,000 to $l0,000/acre depending operation until sufficient waste materials on the site conditions and the land use to be have been compacted and require further achieved. If disposal is completely on the sur- stabilization. Disposal will likely begin at one face, this represents only about 1.4 to 4.4 end of a canyon and fill up in strips rather cents/bbl of shale oil for a 50,000-bbl/d oper- than gradually filling the entire canyon. This ation. will allow early stabilization of narrow strips of land thereby minimizing the size of active disturbance. Protection of the Reclaimed Site Once revegetation begins, reclamation The reclaimed areas should be protected needs will gradually increase as portions of by proper management and monitoring to en- disposal sites are prepared for planting. At sure that stability is maintained. Protection full production, reclamation needs would de- will be needed whenever the vegetation on pend on processing rates and method of dis- the site may be threatened by livestock posal. (See table 69.) (including feral horses), wildlife, invading weeds, or human activity. This can be done Complete filling of canyon disposal sites largely by controlling the degree of use. may take up to 30 years or more depending on processing rates and the sites’ disposal ca- The impact of livestock use on the erosion pacities. Early revegetation of narrow strips of revegetated spent shale is unknown; it is will permit the evaluation of reclamation possible that erosion of the finer processed techniques, and allow for any modifications shales on steep slopes could be substantial. that may be needed during subsequent reveg- Erosion from livestock use on soil-covered etation efforts. shales would be less of a problem. This as-

Table 69.–Estimates of Reclamation Needs Under Various Levels of Shale Oil Production

Production level (bbl/day)

50,000 50,000 b 100,000 250,000 1,000,000 Required annual disposal area (acres)c

— . 698-796 279-318 138-159 344-398 1,378-1,592 Water requirements (5 acre-ft/acre) 349-398 acre-ft/yr 140-159 acre-ft/yr 690-795 acre-ft/yr 1,720-1,990 acre-ft/yr 6,890-7,960 acre-ftlyr Fertilizer Nitrogen (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr t 1,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yr Phosphorus (80 lb/acre) 5,584-6,368 lb/yr 2,232-2,544 lb/yr 11,040-12,720 lb/yr 27,520-31,840 lb/yr 110,240-127,360 lb/yr Seed (30 lb pure Iive seed/acre) 2,094-2,388 lb 837-954 lb 4,140-4,770 lb 10,320-11,940 lb 41,340-47,760 lb Containerized plants (300/acre) 20,940-23,880 pits/yr 8,370-9.540 pits/yr 41,400-47,700 pits/yr 103,200-119,400 pits/yr 413,400-477,600 pits/yr Mulch Wood fiber ( 1,500 lb/acre) 104,700-119,400 lb/yr 41,850-47,700 lb/yr 207,000-238,500 lb/yr 516,000-597,000 lb/yr 2,067,000-2,388,000 lb/yr straw (3,000 lb/acre) 209,400-238,800 lb/yr 83,700-95,400 414,000-477,000 lb/yr 1,032,000-1,194,000 lb/yr 4,134,000-4,776,000 lb/yr w/asphalt binder (300 gal/acre) 20,940-23,880 gal/yr 8,370-9,540 gal/yr 41,400-47,700 gal/yr 103,200-119,400 gal/yr 413,400-477,600 gal/yr aAll numbers are approximate Actual needs will vary with aridity of the she (elevallon, slope, and aspecl) adapled planl Sr)ecles selected and SJrl arnertdrnenls rewed bASSumeS bo.percen! Cllsposal In underground rnlne Worklws CASSUMeS disposal ~lle 451 meters 11 so ft) deep Acreage esflrnales Were based on Po//uIIorI Conlro/ Gu(darrce for 0// S/ra/e Deve/oprnenl Environmental protection Agency. Clnclnnatl Ohio. JUIY 1978 P 3-68 SOURCE Plant Resources lnshtute The Rec/arna//orr ofl?ocessed 0(/ S/ra/e prepared for OTA January 1980 Ch. 8–Environmenlal Considerations ● 339 pect of postmining land use will require care- ● baseline studies that describe the eco- ful monitoring. Indirect methods for protect- logical characteristics of the existing en- ing a site against livestock include adding less vironment in the oil shale basins, and palatable species to the seed mixture, pro- ● characterization studies of processed viding salt blocks and permanent water sup- shale and the testing of reclamation plies away from the seeded areas, controlling methods. livestock numbers, herding, fencing, and, if necessary, repellents. l48 Data from both types of research are needed in designing, directing, and assessing past and future reclamation studies.

Baseline Studies A general description of the vegetation of the oil shale basins can be found in chapter 4. Additional descriptions that contribute to the baseline data are available for Federal lands from BLM’s Unit Resource Analysis151 and Management Framework Plans. 152 More specific vegetation inventories have also been made for site-specific areas within these basins such as transmission and pipeline corridors, Land classification systems have also been developed for the piceance basin,153 154 Eighteen phyto-edaphic units (plant-soil units) were identified. 155 The description of each Photo credit OTA staff unit provides information on soil, vegetation, Reclaimed sites will have to be protected from wildlife climate, aspect, and landform interpretations and hazards of land use. A section on reclamation considerations is provided to iden- Protection against wildlife will also be re- tify the most hazardous characteristics of the quired. This includes large herbivores as well unit (e. g., the potential for erosion and slump- as small burrowing animals such as pocket ing) that need special attention and care, par- gophers that can be expected to move into the ticularly after disturbance as a result of oil revegetated area. If not controlled, over- shale development. Management recommen- utilization of vegetation may occur and toxic dations and alternatives are supplied to over- compounds may be brought to the surface by come the identified limitations. burrowing animals. 149 Monitoring and subsequent management Other information on plant community re- must also ensure that refertilization, seeding, lationships (phytosociology) is currently being and additional control of erosion or weeds, gathered by Colorado State University for the are provided if necessary, Similarly, monitor- Piceance basin. This will help the land man- ing plant succession, productivity, and uti- agers and reclamation specialists to select lization should all be included in the reclama- the proper species to be used in reclamation. tion management plan. 150 Such studies are lacking for the basins in Wyoming and Utah, and few physiological studies have been conducted with existing Review of Selected Research to Date plant species at the proposed disposal sites or with plant materials to be used in reclama- Research undertaken on the topic of oil tion to determine their tolerance limits to the shale reclamation falls into two categories: various adverse conditions likely to be en- 340 ● An Assessment of 011 Shale Technologies countered. Little is known about the natural process. 163 During these studies the basic genetic differences that exist in native plant chemical data needed to design a reclamation communities. These might make the plants program were incorporated into greenhouse more or less adaptable to adverse environ- and small field plots (100 ft2). Revegetation mental conditions encountered in oil shale work on other processed shales, all of which reclamation. are coarser, had been confined to Union Oil plots planted in 1966 and Colorado State Uni- Reclamation Studies versity plots planted in 1973. In the late 1960’s and early 1970’s, larger field plots Investigations to determine the manage- (41,000 ft2) were built using many of the results ment needed to produce conditions favorable of the earlier experiments, including the ef- to the establishment and growth of plants on fects of soil supplements such as fertilizer processed shales were initiated by private in- and organic matter. dustry in the mid-1960 ’s. ’5’ These were based on previous knowledge developed by range Since the early 1970’s, studies have been managers, biologists, and numerous arid and conducted on disturbed soils without proc- semiarid studies, as well as other baseline in- essed shales to determine the establishment formation from the oil shale basins. of plant species, microbial activity, and long- Where possible, the sites for reclamation term successional trends. These studies were tests have been selected to simulate, as close- encouraged by the finding that the revegeta- ly as possible, the environmental conditions tion of soil-covered processed shales was to be encountered during the reclamation of more successful than revegetation directly on disposal sites used for large-scale production. processed shales. This was because the soil Sites have been selected in high- and low- cover does not have the adverse chemical and rainfall areas, with various combinations of physical properties of processed shale that slope, aspect, and processed shale materials. inhibit plant growth. However, most revegetation experiments have been hampered by a lack of processed Supplemental water has been used to es- shale. This shortage, coupled with the high tablish plants in most of the processed shale costs of transporting retorted shales to field revegetation studies. The addition of 10 to sites (in some cases from as far away as 13 inches of water during the first growing California), have restricted both the size of season with no subsequent irrigation has the test plots (2 to 5,000 ft2), and the type of resulted in the establishment of a vegeta- processed shale evaluated. tive stand and the persistence of adapted species for several years. The salt leaching To date, field studies using spent oil shales requirement (5 acre-ft of water per acre) is in as plant growth media have centered on the addition to this supplemental water. Only TOSCO II, Union “A” and “B,” and Paraho 157-162 limited success in seeding and transplanting materials. These studies show that with into spent shale without supplementary wa- intensive treatments plant growth can be es- 164 ter has been reported. However, establish- tablished directly on spent shales, although ment without supplemental water might be use of a soil cover is more successful. achieved by mulching with straw or hay and It is difficult to compare the results of allowing salts to be leached by natural pre- revegetation studies with the various proc- cipitation prior to seeding or planting, al- essed shales because the experimental de- though the time period required for this could signs varied so widely. Different plant spe- be unreasonable. Micro-watersheds consist- cies were used, and fertilizer, mulch, slope, ing of low-level diversion barriers or aspect, and soil cover also varied. Most of the mounded spent shale have also been pro- early (1965 to 1973) revegetation studies for posed and initiated to concentrate water for Colony used spent shale from the TOSCO II plant growth.165 Ch. 8–Environmental Considerations ● 341

Several researchers have worked on the Summary of Issues and R&D Needs problems of leaching soluble salts from the processed shales and the surface stability of Research to date has shown that with in- several retorted shales including TOSCO tensive management vegetation can be estab- II.166-172 It appears unlikely that salts will lished directly on processed oil shales. The migrate to the surface by capillary rise in primary requirements are the leaching of most areas of low precipitation. Only in areas high levels of soluble salts with supplemental where soils were saturated by supplemental water, the addition of nitrogen and phos- water was there temporary desalinization of phorus fertilizers, and the use of adapted surface layers. When the supplemental wa- plant species. However, the establishment of ter was discontinued, surface salinity began vegetation on spent shales covered with at to drop due to leaching from natural precip- least 1 ft of soil is preferred because it is less itation. From these studies a better under- susceptible to erosion and does not require as standing has developed of solutions to the much supplemental water and fertilizer. problem of establishing a self-sustaining Adapted plant species are required for either vegetative cover. soil-covered or spent shales. Several studies are continuing, and a new The long-term stability and the self-sus- 173 successional study has been initiated to taining character of the vegetation is un- evaluate the long-term feasibility of using known, but if sufficient topsoil is applied the processed shales directly as plant growth results of research on small plots indicates media and the influence of various depths of that short-term stability of a few decades ap- soil cover over spent shale. It has been set up pears likely. Monitoring and subsequent man- in the Piceance basin to obtain information agement must ensure that any necessary re- related to the reseeding of disturbed areas in fertilization, seeding, and erosion and weed order to reestablish a diverse, functional control be provided. The reclamation man- ecosystem in as short a time as possible. agement plan must also include monitoring Various seed mixtures, ecotypic varieties of plant succession, productivity utilization, and native species, microbial activities, seeding the presence of high concentrations of ele- techniques, fertilizer levels, irrigation, and ments toxic to plants and animals. mulching treatments are being evaluated. In addition, the rate and direction of plant suc- Whether or not the revegetation of spent cession is being monitored to identify signifi- shales is considered successful depends on cant trends in vegetation changes, and to de- the desired land use and the performance termine how these trends are influenced by standards applied to measure the success. the various treatments and practices, 174 For example, the reestablishment of vegetation that reduces erosion and is productive, Few studies have been conducted on raw self-sustaining, and compatible with sur- shale. This is because in the past it has been rounding vegetation might be considered suc- assumed that most raw shale of commercial cessful for livestock but not for wildlife use. quality will be retorted. Additionally, the raw The minimum requirements for vegetation oil shales are hard and resilient. When should be to stabilize the disposal sites so that mined, the shale fractures into coarse frag- the detrimental effects caused by erosion can ments that have extremely low water-holding be minimized. Where ecologically feasible, capacities, which renders them undesirable multiple land use of disposal sites should be growth media. For these reasons, it is likely encouraged. that raw shale of noncommercial quality would be buried deeper in the disposal piles Reclamation plans will have to be site spe- and not used as a growth medium, cific since environmental conditions vary 342 ● An Assessment of 011 Shale Technologies from site to site. Proper management will be be encountered in the reclamation of the required in all instances, if only to protect spent shales. This should include the plant communities in surrounding areas from identification of ecotypic variations, harm. Proper management is even more im- seed production by cultivating adapted portant in the reclaimed areas. If the vege- wildland plants, and research to deter- tative cover were completely lost, the nega- mine species performance under abnor- tive effects would increase. The conditions mal conditions (e.g., drought, salinity, would not be as severe as those without any and high temperatures); reclamation because they would be reduced ● the role and use of soil microbes and by restrictions in slope, catchment and diver- mycorrhizal fungi in soil building and sion dams, and other mitigation completed in plant growth. Successful reclamation the early stages of reclamation. will depend on developing a protocol to If revegetation completely failed, produc- select and/or maintain the essential tive land use would be severely reduced or mycorrhizal fungi in disturbed habitats eliminated. It is doubtful that, after once or to develop methods to reinoculate being reclaimed, conditions would deterio- these fungi in habitats where they are absent; rate to the point of eliminating all vegetation ● from a disposal site, although a natural suc- the plant succession for large areas of a cession of species would occur that would few hundred acres in size under natural favor those that had superior adaptability to and disturbed conditions, including the the harsh conditions. Weedy or unpalatable influence of animals on revegetated surfaces; species of less use to livestock and wildlife ● would undoubtedly invade the sites. the toxicity of elements such as fluorine, boron, molybdenum, selenium, and arse- The types of reclamation needs for a large- nic to plants and grazing animals. A pro- scale industry (1 million bbl/d) are similar to gram to monitor these elements should those generated for a small industry (50,000 be established on newly reclaimed areas bbl/d), but differ in the amounts of materials at least for the first few years; that will be required and the rates at which ● the probable heat retention within the they must be supplied. It is probable that disposal pile and its effect on reclama- shortages of adapted plant materials and as- tion timing and revegetation; sociated support materials (such as mulches ● the rates of erosion on large, reclaimed and greenhouse facilities) would occur at the areas of a few hundred acres in size. In- higher production rates. The problem is com- formation is needed on how much water pounded by the fact that demands for plant runs off the area following snowmelt in materials are increasing from other mining the spring and after high-intensity sum- operations such as coal and uranium. The mer storms, including how much sedi- severity of the shortages will depend on ment and soluble salts will be contained whether the oil shales are processed in situ or in the water; and surface retorted, and whether the processed ● the viability of vegetation on raw shale, shales are disposed of underground or on the surface. Surface reclamation needs will be somewhat less demanding with MIS process- Policy Options for the Reclamation of ing or with underground disposal of surface- retorted shales. Processed Oil Shales Research on the reclamation of processed For Increasing Available Information shales is continuing. Areas of major concern More information is desirable on reclama- requiring additional study include: tion methods and the selection of proper plant ● the selection and propagation of species species for revegetation programs. Options especially adapted to conditions likely to for obtaining this information include the Ch. 8–Environmental Considerations 343 evolution of existing R&D programs by the tivating specific wildland plants for seed pro- U.S. Department of Agriculture (USDA), EPA, duction have generally not been developed. and other agencies; the improved coordina- Also, seeds of certain native plant species are tion of R&D work by these agencies; increas- not commercially available. ing or redistributing appropriations to accel- A shortage of seeds could be a problem for erate reclamation and revegetation studies; a large oil shale industry. For example, the and the passage of new legislation specifi- USDA’s plant materials centers often require cally for evaluating the impacts of land dis- up to 15 years to identify and develop turbance. Mechanisms are similar to those adapted species for release to commercial discussed in the air quality section of this suppliers or to industry for trial plantings. chapter. Furthermore, the centers intentionally limit their activities so that they will not compete To Develop Reclamation Guidelines for Oil Shale with commercial producers. Thus, they have SMCRA provides for comprehensive plan- not developed mass production capabilities, ning and decisionmaking to manage disturbed nor have they adopted some of the more re- land. However, in general, the reclamation cent propagation technologies (such as micro- standards promulgated under the act are propagation, cutting, and fungal and bacteri- only appropriate for coal, but not necessarily al inoculation) that are used commercially. In for oil shale. Thus, new reclamation guide- order to meet the future demands of a large lines specifically for oil shale may be desir- oil shale industry, it may be necessary for the able, with standards for postmining land uses centers to expand their facilities and prop- that are ecologically and economically feasi- agation capabilities. This could be costly in ble and consistent with public goals. If the terms of facilities, technologies, and person- Act were amended to encompass oil shale, nel. Policy mechanisms for expanding cooper- Congress could direct that reclamation guide- ative agreements between the centers and lines be developed by DOI’s Office of Surface commercial producers need to be developed. Mining, either alone or in conjunction with These activities would not only benefit oil other agencies. Alternatively, Congress could shale, but also most other reclamation and pass new legislation calling for the prep- arid and semiarid revegetation projects as aration and implementation of reclamation well. guidelines for oil shale.

To Expand the Production of Seeds and Plant Materials While many common seeds are available from commercial dealers, procedures for cul-

Permitting Introduction the States to determine whether a prospective facility is able to meet specific require- During the past 10 years an increasingly ments under the law. The operation of an oil complex permitting system has been devel- shale facility requires well over 100 permits oped to assist the Federal, State, and local and other regulatory documents from Feder- governments in protecting human health and al, State, and local agencies. They include the welfare and the environment. Permits are the permits for maintaining the environment and enforcement tool established by Congress and for protecting the health and safety of work- 344 . An Assessment of 0il Shale Technologies ers, and in addition, those that would be regulations and statutes it has often been dif- needed for any industrial or commercial ac- ficult to know which agency must be con- tivity: building code permits, permits for the tacted, and which permits are required from use of temporary trailers, sewage disposal which entity. permits, and others. Of these, a few—the ma- The following discussion examines: jor environmental ones—require substantial commitments of time and resources. The ma- ● how various parties view the permitting jor environmental permits that must be ob- process; tained prior to the operation of an oil shale fa- ● the current status of oil shale developers cilit y are: in obtaining the needed permits; ● the time required for preparing and ● a PSD permit required under the Clean Air Act; processing permit applications; ● the disputes encountered so far in ob- ● an Air Contaminant Emissions permit required by the State of Colorado; taining such permits; ● the potential difficulties that might be ● a Special Primary Land Use permit— which is required for plant siting in Rio encountered by a developing oil shale industry; and Blanco County; ● ● possible policy responses to permitting a Mined Land Reclamation permit re- issues. quired by the State of Colorado; ● an NPDES permit required under the Clean Water Act; Perceptions of the Permitting Procedure ● a section 404 Dredge and Fill permit under the Clean Water Act if the operation The various parties interested in environ- affects navigable waters; mental permits for oil shale facilities have ● a Subsurface Disposal permit as re- widely divergent views concerning the effec- quired by the State of Colorado if water tiveness and problems of the permitting pro- is reinfected; cedure. Industry is concerned about the ● a permit for the disposal of solid wastes length of time it takes to obtain permits and generated by the facility required under the uncertainty of obtaining them. The envi- RCRA; ronmental community is watchful of the pro- ● testing of effects, recordkeeping, report- cedure’s effectiveness in enforcing the law; ing, and conditions for the manufacture and the regulators themselves are troubled and handling of toxic substances as stip- by their limited personnel and budgetary re- ulated under TSCA; and sources. ● an EIS as required by the National Envi- The high cost of oil shale projects makes ronmental Policy Act-if an oil shale plant unexpected delay costly, and industry is con- involves a major Federal action signifi- cerned with uncertain agency decision sched- cantly affecting the environment. ules or with unpredictable litigation that can The responsibilities for reviewing and ap- delay or prevent project construction. Fur- proving applications are distributed among thermore, some regulations and standards many Federal, State, and local agencies. Fed- have not yet been set because of a lack of suf- eral agencies include EPA, the Department of ficient knowledge about the impacts of shale the Treasury, DOI (including BLM and USGS), operations and the effectiveness of their con- the Department of Defense (e.g., the Army trol. Developers are particularly worried Corps of Engineers), and the Interstate Com- about the effects of new regulations (such as merce Commission. State entities in Colorado for visibility maintenance as part of the PSD include the Department of Health, the De- process) on process design and project eco- partment of Natural Resources, and the State nomics. They are concerned that new regula- Engineer. Because of varied and overlapping tions could necessitate costly retrofits to ex- Ch 8–Environmental Considerations . 345 isting plants or even the cessation of opera- are seldom made for public participation, and tions. For facilities under construction, the access is not provided to the information new regulatory requirements may mean rede- needed to evaluate the applications. They sign or addition of environmental control note that few agencies have an affirmative equipment or strategies. These uncertainties public involvement process. They find it is increase the risk that a project, once started, often difficult to follow and monitor agency may not be completed. Prospective develop- decisionmaking. ers also express their frustration over the The regulators feel overwhelmed by the in- lengthy and expensive procedures for prepar- creasing number of permits and by the coming permit applications (including monitoring plexity of the review. They believe that their and modeling requirements) to meet some en- personnel and financial resources are too vironmental statutes. This discontent is some- limited for the present caseloads and certain- times compounded by overlapping agency ly will be dwarfed by any rapid increase in jurisdictions and by repetitive paperwork. applications arising from an expanding energy industry, EPA’s Region VIII, for example, The environmental community asserts includes not just the oil shale region, but most that, given the complexity of oil shale opera- of the Western coal and uranium resources. tions, the extensive application and review procedures are necessary to fully assess envi- Regulatory personnel also contend that they ronmental impacts, the effectiveness of con- are handicapped by inadequate technical information about the technologies that they trol measures, and compliance with environmental law. They suggest, in fact, that agency must review and assess. enforcement of environmental laws is too often compromised by weak regulations and Status of Permits Obtained by by a lack of essential information on which Oil Shale Developers both to base permitting decisions and to enforce the conditions of the permits. Informed, The number of permits needed for a given meaningful public involvement in the process- facility depends on its site; on whether it in- ing of environmental permits is therefore pro- volves Federal land; on the scale, type, and moted by environmental groups to ensure combination of processing technologies used; that all points of view are represented in and on the duration of the operations. As agency proceedings. It is particularly impor- stated previously, the permits range from tant, these groups hold, that the technical those required for a temporary trailer to the analyses on which agency decisions depend major environmental permits required under are subjected to independent scrutiny. How- Federal and State regulations and standards. ever, they believe that adequate provisions Table 70 shows the status of the major per-

Table 70.–Status of the Environmental Permits for Five Oil Shale Projects

Regular open Project Type of tract EIS DDP approval PSD permit mining permit NPDES permit

a R IO Blanco Federal lease tract Final programmatic Yes For 1,000 bbl/d Yes 1st phase C-a Issued a Cathedral Bluffs Federal lease tract Final programmatic Yesa For 5,000 bbl/d Yes 1st phase C-b Issued a Long Ridge (Union) Private Not applicable Not applicable For 9,000 bbl/d Yes Not requiredb Colony PrivateC Not applicable Not applicable For 46,000 bbl/d Not yet applied Not requlredb Superior Private/Federald Not applicable Not applicable Not yet applied Not yet applied Not yet applied aLlllgallon proceeding over aopro JaI of the momhed DDP bThese operallofls do not plan 10 discharge 10 Surf aCe StreaMS cExchange of Federal land and plpellne rlgh[ of way otier BLM and ‘equesled ‘Land exchange requested SOURCE Office of Technology Assessment 346 ● An Assessment of 011 Shale Technologies

mits obtained by five oil shale developers. mits can take more than 2 years. The prep- These facilities are presently in different aration and review of the PSD application is stages of commercial development. The Rio perhaps the most comprehensive and time- Blanco, Cathedral Bluffs, Colony, and Superi- consuming step. Baseline air monitoring is re- or projects involve Federal land, while the quired, along with extensive dispersion mod- Union project is located on private holdings. eling to estimate the effect of the plant’s emis- DDPs for tracts C-a and C-b had to be ap- sions on the region’s air quality. Once this proved by USGS because they are part of the work is completed and an application sub- Federal Prototype Oil Shale Leasing Program. mitted to EPA, the approval process, as stipu- Four of the projects have already been lated under the law, can take as long as 1 granted PSD permits for their facilities. Note, year. However, EPA tries to rule on the appli- however, that with the exception of the Col- cation within 60 days, and to date an average ony project, only small-scale, first-phase con- of about 90 days has been required. (This instruction air emissions have been approved. cludes internal staff review and a period for All of the facilities have to obtain Mined public comment. ) Land Reclamation permits. Rio Blanco, Cathe- It should be noted that a project would not dral Bluffs, and Union have all been approved necessarily be delayed by the full length of for commercial-scale modular operations. the permitting schedule, because other prede- Colony and Superior have not yet applied. velopment activities such as detailed engi- NPDES permits are required under the Clean neering design, contracting, and equipment Water Act if a plant discharges to a surface procurement could proceed in parallel, if the stream. So far Rio Blanco and Cathedral developer were willing to accept the risk that Bluffs have received such permits for the key permits might eventually prove to be un- first phase of their commercial development. obtainable.

The Length of the Permitting Procedure Disputes Encountered in The time required for preparing and proc- the Permitting Procedure essing a permit application depends on the The principal problems encountered to type of action being reviewed, the review pro- date are related to the needs of the regulatory cedures stipulated under the law, the criteria agencies for technical information, to differ- used by agencies to judge the application, and ing interpretations of environmental law, the amount of public participation and con- and, according to developers, to a lack of re- troversy. If Federal land is involved, then an sponsibility for timely action on the part of EIS will most likely be required. This process the agencies. may take at least 9 months after the developer applies for permission to proceed with Occidental’s application for a Subsurface the project. * Then the applications for the Disposal permit for its sixth experimental necessary construction and operation per- MIS retort on its property near De Beque, mits can be prepared and filed. In the case of Colo., was delayed for several months by the the current Federal lease tracts, additional Colorado Water Quality Control Commis- time was needed to prepare the DDPs for ap- sion’s consideration. (The commission had not proval by the Area Oil Shale Supervisor of required permits for the first five retorts. ) USGS. The commission was concerned about the potential for ground water contamination by the Once the requirements for an EIS and DDP abandoned MIS retorts and was not satisfied are satisfied, obtaining all of the needed per- with the evidence presented by Occidental

*The programmatic EIS for the Prototype Leasing Program that pollution would not occur. Additional took 4 years. Preparation of the draft EIS for the proposed Su- technical information was requested, and the perior land exchange required 2 years. commission insisted on a cooperative environ- Ch. 8–Environmental Considerations ● 347 mental monitoring and research program in- proval of DDPs that were submitted by the volving DOE, the State of Colorado, and sever- lessees in 1976. This dispute has thus far not al universities. The dispute was resolved delayed construction on the tracts, It does, when Occidental agreed to the program and however, exemplify the type of uncertainty the investigators were given access to Oxy’s that, the developers maintain, discourages site for sampling and experiments. them from initiating oil shale projects. The As work began on tracts C-a and C-bin late plaintiffs claim that no statement to date has 1977, soon after DOI approved the modified adequately analyzed the effects of these DDPs, a dispute arose among several environ- plans. Defendants believe that the 1973 pro- mental groups, permitting agencies, and the grammatic EIS appropriately evaluated the lessees over the timing of required permits. 1976 plans and the alternatives to their ap- EPA initially informed the lessees that air proval. The Federal district court agreed quality and State mining and reclamation with the defendants. The case was heard by permits would not be required until the min- the 10th Circuit Court of Appeals which also ing of actual in situ retorts began, The envi- ruled in favor of the defendants. ronmental groups maintained that construc- Other than these disputes, there have been tion commenced with shaft-sinking and con- no substantial interruptions that could be struction of the surface facilities needed for directly related to permitting. The only the MIS retorts. This work had already begun lengthy application review period involved and, according to the environmental groups, Colony Development Operation’s PSD air permits should have been in hand, They fur- quality permit. EPA did not expedite its re- ther contended that the interpretation of view of this permit because the applicant in- “commencement of construction” used by the dicated it was still inactive, awaiting more agencies evolved during meetings that were favorable project economics. In addition, 1- not open to public participation, year suspensions were requested in 1976 by EPA’s recently appointed Regional Admin- the lessees of the Federal tracts partially istrator subsequently redefined “commence- because the baseline air quality conditions on ment of construction” to mean collaring of the tracts exceeded the primary NAAQS for the shaft, an early activity in shaft-sinking particulate and the guideline for HC. How- operations, However, the State reclamation ever, the suspensions were granted for rea- agency maintained that the developers were sons not related to the permitting process. not responsible for the previous interpretation of the law, Therefore, operations could proceed, The State air pollution division post- Unresolved Issues poned the deadline for application submis- Although many precedents have been es- sion until the developers could submit the de- tablished, there remain unresolved issues tailed engineering plans required for an emis- that sustain a level of uncertainty that may sions permit, but did not delay the construc- discourage some developers from proceeding, tion. EPA issued the permit in an expeditious whether on private or Federal land. These un- manner and work was not significantly de- certainties may be more critical than those layed. Because a clear precedent was established, it is unlikely that this dispute will arise encountered thus far. Several regulations are still pending that may increase costs or force again. It took several months to resolve, but changes in the design of process facilities or activities on the tracts continued during this control technologies. They may also add to period. the control requirements. The pending regu- Finally, there has been protracted legal ac- lations include: tion between three environmental plaintiffs and DOI and the lessees of tracts C-a and C-b ● recordkeeping, reporting, and stipula- over the need for an EIS prior to DOI’s ap- tions governing the manufacture and 348 ● An Assessment of 01/ Shale Technologies

handling of toxic substances as required Attempts at Regulatory Simplification under TSCA; disposal practices and standards for sol- Several attempts are being made to simpli- id waste under RCRA; fy regulatory procedures. A case in point is emission and ambient air standards for the action of EPA’s Region VIII office to hazardous air pollutants under the streamline the PSD permit application pro- Clean Air Act as amended; cess. The office evaluated its experience with visibility protection requirements for processing such permits and found that in a mandatory Class I areas under the Clean few cases, there are long review times when Air Act as amended; the applicant was not in a hurry to obtain a possible application of the Safe Drinking permit because the future of the project was Water Act to the brackish ground wa- uncertain. An example is the application for ters of the Piceance Basin; and the Colony project, which has been sus- possible application of SMCRA, or simi- pended for several years. In other instances, lar Federal-reclamation laws, to noncoal delays resulted when the agency was deluged minerals. by permit applications prior to the enactment of new, stricter regulations. An example is Some environmental groups maintain that the situation that arose in 1978 when the the effects of development are so poorly understood that development will entail signifi- older PSD regulations, which did not require cant risks. They believe that adequate regula- extensive baseline air quality monitoring, were replaced by new regulations that re- tions cannot be promulgated because knowl- quired monitoring for a l-year period. When edge is lacking about the severity of the risks and about the methods for their control. R&D this happens, the agency’s resources are and further experience with the industry’s overwhelmed and applications are delayed. operations may result in the implementation Other delays resulted when applications of new regulations that will further reduce were incomplete (information was lacking) or the economic attractiveness of oil shale proj- when the information that was provided was ects. This, however, is an uncertainty which deemed inadequate by the agency. The first is inherent in any new industry. informational problem could be easily reduced by a quick review of the application for Another problem that may emerge is completeness. The second is more difficult, whether regulatory agencies will be able to because it involves scientific and technical handle the increasing load of permit applica- judgment. It reflects, to an extent, the fact tions and enforcement duties. Budgets and that the oil shale processes are new technolo- personnel are limited, and the States in par- gies and their effects are not totally under- ticular have experienced difficulty finding stood. Standardized procedures are not al- and keeping competent technicians and pro- ways available for determining compliance fessionals. Increased oil shale operations, with the law. This difficulty could be reduced coal mining, oil and gas development, coal- by developing standard procedures wherever fired powerplants and synthetic fuel facil- possible. This has been done already in some ities, uranium mines and mills, and other min- areas of the PSD process where, for example, eral development in the region will further the developers are required to use standard tax their resources. The dissatisfaction ex- dispersion models authorized by EPA. pressed to date may be insignificant compared to that which is likely as agencies be- The Region VIII office recently issued a pol- come more overloaded. icy statement that addresses its efforts to im- Ch 8–Environmental Considerations ● 349 prove the permitting procedures. A key ele- studies have been conducted by EPA’s Region ment is designing a standard application that VIII office for the PSD process. The National defines the specific data needs and recom- Commission on Air Quality is conducting a mends procedures for obtaining the data. more comprehensive evaluation of alterna- There is also an effort to educate developers tive means for achieving the goals of the in using the application by holding public Clean Air Act with more manageable regula- workshops on the permitting procedure. Also, tory procedures. Similar studies could be at the Federal level, one focus of the proposed made of other laws and regulations. Energy Mobilization Board is to expedite agency decisionmaking and reduce the im- Increase the Resources of the pacts of new regulatory requirements that Regulatory Agencies may emerge after construction or operations begin. Increasing the personnel and financial re- The State of Colorado, with funding from sources of the Federal regulatory agencies DOE, is designing and testing a permit review would allow them to improve their response procedure for major industrial facilities that capabilities. The agencies could also provide will coordinate the reviews by Federal, State, technical assistance to the State and local and local regulatory agencies. The procedure regulators to aid in their decisionmaking is also planned to expand the public’s oppor- processes, However, a simple increase in tunities to become involved in all phases of agency funding, without a methodology for project planning and review. It is being tested coordinating the expanded resources, would with a controversial molybdenum project not guarantee that procedures would im- near Crested Butte, Colo. A handbook will be prove. developed on completion of the test. This may aid in applying similar methods to the permit- Improve Coordination Among Agencies and ting process for oil shale plants. * Between Agencies and the Public The permitting process might be improved Policy Options if coordinated reviews were conducted by the various agencies. This strategy would help to The policy options presented here range identify and reduce jurisdictional overlaps from working to better understand complex and to reduce personnel needs and paper- regulatory processes, through using the re- work loads, A major advantage would be the sults of such work to reduce the complexities, opportunity for sharing analytical responsi- to waiving the laws or regulations. This range bilities and results. The public hearings that encompasses actions over which there is little are required for many separate permits could disagreement through those which involve ex- also be consolidated. The strategy could be treme controversy. Few would argue that reg- patterned after the voluntary joint review ulatory procedures could be improved, while processes that are being developed in Col- many would resist changes that could result orado and other States. However, unless the in weakening environmental protections. approach were mandated, it is questionable Study the Causes of Permitting Delays that interagency cooperation would be significantly improved. Further study of the permitting procedure Another approach would involve the estab- could help to identify and eliminate some of lishment of a regional environmental monitor- the causes of regulatory inefficiency. Such ing system to determine baseline conditions within all areas to be affected by oil shale

“Colorado hopes this joint review process, which provides projects. The system could better character- for concurrent rather serial review of applications, will also ize baseline conditions than could individual, reduce the time needed for review. uncoordinated monitoring programs. It might 350 ● An Assessment of O// Shale Technologies reduce the duration and the cost of the ad- developers to integrate controls for the new vance monitoring programs that are required standards into their plant designs. If it is de- of permit applicants. Site-specific measure- sired to reduce developer risks, new stand- ments would still be required to characterize ards should be firmly established and not biological communities, soils, hydrology, and subject to change for an extended period. geology for projects involving Federal land. This may not be appropriate, since early ex- Baseline surveys could be conducted by Fed- perience with the industry may indicate a eral agencies on potential lease tracts to need to modify the standards to achieve the shorten the time between a leasing decision desired level of protection. In addition, they and commercialization. The cost of the pro- may be difficult to establish. Excessively lax gram could be included in the cost of the standards would not adequately protect the lease. Individual monitoring of stack emis- environment; excessively strict ones might sions, water discharges, and reclamation ef- unnecessarily preclude development. These forts would also still be needed as the proj- hazards are particularly applicable to setting ects proceeded. NSPS. Improved coordination of public participa- Another approach would be to simplify the tion might also shorten review time by reduc- permitting procedures themselves, based on ing controversy, political confrontation, and information from the investigations suggested litigation. Procedures might include advance under the first option. This would have the public notification of the status of permit ap- advantage of retaining the protection of the plications, the dissemination of technical in- existing laws while making it easier to comply formation and R&D results, and the more di- with them. However, problems (such as the rect involvement of the public in an agency’s uncertain status of applications in progress) decisionmaking process through, for exam- might arise during the transition from the old ple, workshops and public meetings. It is pos- regulatory system to the new. It is also often sible that increasing the public’s awareness difficult to isolate the substance of environ- of the characteristics of a project might lead mental protection laws from the implementa- to perceptions of greater risk. On the other tion procedures. Any proposed changes in the hand, education could lessen nonproductive procedures would need careful examination discussions and confrontations. In any case, it may be difficult to educate the public in the by the agencies, the developers, and the public. technical aspects that determine whether an application satisfies the standards. To main- A third approach would be to establish de- tain a high level of participation, some inter- tailed, standardized specifications for permit vener groups may seek financial and techni- applications. This would reduce the problem cal assistance. This would be controversial, of insufficient data being provided with the especially from the point of view of the devel- applications and the delays that would be opers. caused when agencies request the additional information they feel is necessary for a thor- Clarify the Regulations and ough review. Fully comprehensive standard- the Permitting Procedure ized forms are probably not possible, and some interactions after an application is sub- One option would be to expedite promulga- mitted will still be needed. tion of standards for visibility and hazardous emissions under the Clean Air Act, and to set A fourth option would be to have a mora- the as yet undefined NSPS for oil shale torium on new regulations until some of the plants. Additional regulations could also be actual effects of development are determined defined under RCRA, TSCA, and other laws. on the Prototype Program lease tracts. (Moni- These actions would eliminate many of the toring of environmental effects and develop- regulatory uncertainties and would allow the ment of control techniques is one of the major Ch 8–Environmental Considerations 351 objectives of the Program. ) A disadvantage is Limit the Application of New Environmental Laws that the regulatory uncertainties would re- and Regulations main. An advantage is that the regulations could be promulgated from a better knowl- Plants already under construction, or that edge base, are operating, could be exempted from the provisions of new environmental laws and regulations. This approach—’’grandfather- Expedite the Permitting Procedure ing ” —is embodied in the legislation for the Energy Mobilization Board. It would remove The proposed Energy Mobilization Board many of the regulatory uncertainties. How- would expedite permitting by negotiating a ever, it is surrounded with controversy be- project schedule with a developer and then cause new regulations might be needed to enforcing the schedule by making regulatory deal with problems that could not be discov- decisions if the responsible agency does not ered until after operations begin. Many of the do so within a specified period. Proponents of present laws contain provisions to exempt ex- this strategy point out the advantages of a isting facilities from new requirements. central authority that could provide a single These include either automatic exemption point of contact between the developer and clauses or economic criteria against which the regulatory system. Opponents feel that the new regulatory requirements must be such an authority would add another layer of tested. bureaucracy, would increase controversy over the projects that are expedited, and Waiving Existing Environmental Laws would ultimately not have substantial effects on permitting delays. This strategy would exempt a project from the provisions of some or all existing environmental laws and regulations that might delay Another method would be to limit the peri- or prevent its construction and operation. od during which litigation can be initiated This measure would remove virtually all of against a particular permitting action, This the problems and delays associated with the mechanism could be similar to that employed permitting. However, it would have serious in the case of the Trans-Alaska oil pipeline. It political, environmental, and social ramifica- would reduce the risk of agency actions being tions since it could arbitrarily preempt envi- subjected to legal challenges that could jeop- ronmental protection under the law. Further- ardize a project’s completion schedule. It more, the waivers might give an undeserved should be noted, however, that legal mecha- competitive advantage to the developers who nisms already exist in some specific laws to received them. The allocation of the waivers limit the period of litigation, The expediting would be highly controversial, The extent to strategy could extend this protection to most, which this action would speed the deploy- if not all, of the relevant statutes, ment of the industry is unclear. —.-.

352 An Assessment of Oil Shale Technologies

Chapter 8 References

‘Environmental Protection Agency, Trace E]e- 1hJ. C. Ward, G. A. Margheim, and G, O. Lof, ments Associated With Oil S~ale and Its Process- Water Pollution Potential of Spent Oil Shale ing, EPA-908/4-78-003, prepared by TRW and DRI Residues, report for the Water Quality Office, En- under contract No. 68-02-1881, May 1977, p. 2. vironmental Protection Agency, Colorado State 2T. C. Borer and J. W. Hand, Identification and University, Fort Collins, Colo., 1971. Proposed Control o~ Air Pollutants From Oil Shale 17National Academy of Sciences, Mining and Operations, prepared by the Rocky Mountain Divi- Processing of Oil Shale and Tar Sands—A Work- sion, The Pace Co. Consultants and Engineers, ing Paper Prepared for the Committee on Surface Inc., for OTA, October 1979, p. 38. Mining and Reclamation, Washington, D. C., 1979, ‘Environmental Protection Agency, Monitoring p. 89. Environmental Impacts of the Coal and Oil Shale 1%upra No. 5, Industries: Research and Development Needs, ‘gIbid. EPA-600/7-77-015, February 1977, p. 138. 2(}Supra No. 17, at p, 91. %upra No. 2, at p. 20. 21J. P. Fox, K. K, Mason, and J. J. Duvall, “Parti- ‘Denver Research Institute, Predicted Costs of tioning of Major, Minor, and Trace Elements Dur- Environmental Controls for a Commercial Oil ing Simulated In Situ Oil Shale Retorting in a Con- Shale Industry: Volume I—An Engineering Ana]y- trolled-State Retort, ” Proceedings of the Twelfth sis, prepared for the Department of Energy under Oil Shale Symposium (J. H, Gary, cd.), Colorado contract No. EP-78-S-O2-51O7, July 1979. School of Mines Press, Golden, Colo., 1979, pp. ‘Environmental Protection Agency, A Prelimi- 58-71, nary Assessment of the Environmental Impacts 22F. C, Hass, “Analysis of TOSCO II Oil Shale From Oil Shale Development, prepared by TRW Retort Water, ” paper presented at ASTM Sym- and DRI under contract No, 68-02-1881 (EPA-600/ posium D-199.33 on Analysis of Wastes Associ- 7-77-069), July 1977, P. 104. ated With Alternative Fuel Production, Pitts- 7Battelle Northwest Laboratories and Dames burgh, Pa., June 4-5, 1979, and Moore, Environmental Impact Analysis: Ap- 21E. W. Cook, “Organic Acids in Process Water pendix 13—Air Studies, prepared for Colony De- From Green River Oil Shale, ” Chemistry & Indus- velopment Operation, October 1973. try, May 1, 1971, p, 485. ‘Rio Blanco Oil Shale Project, Detailed Develop- “G. W. Dawson and B, W. Mercer, “Analysis, ment Plan Tract C-a: Environmental Protection Screening and Evaluation of Control Technology and Monitoring, vol. 4, March 1976. for Wastewater Generated in Shale Oil Develop- ‘Rio Blanco Oil Shale Project, Detailed Develop- ment,” Quarterly Reports, Batelle Pacific North- ment Plan Tract C-a: Environmental Protection west Laboratory, Richmond, Wash., January and Monitoring, vol. 3, May 1977. 1977-March 1979. ‘[statement by Terry Thoem, Environmental 25Water Purification Associates, A Study of Protection Agency, Region VIII, as reported in the Aerobic Oxidation and Allied Treatments for Up- minutes of the 25th meeting of the Oil Shale Envi- grading In Situ Retort Waters, contract No, EW- ronmental Advisory Panel, Grand Junction, Colo., 78-C-20-0018 with Laramie Energy Technology May 2 and 3, 1979, pp. 130-131, Center, Department of Energy, Quarterly Status I INational Commission on Air Quality, Report of Report, August 1979. the Atmospheric Modeling Review Panel of the 2%upra No. 14. National Commission on Air Quality, (preliminary 27Supra No. 21, draft), to be published in February 1980. %upra No. 22. 121bid. “National Academy of Sciences, Water Quality 1‘Ibid, criteria, 1972, Environmental Protection Agency “E, F, Bates and T. L. Thoem (eds, ), Pollution publication (EPA-R-3-73-033), Washington, D, C., Control Guidance for Oil Shale Development, re- March 1973. vised draft report, Environmental Protection 1{]Ibid, Agency, Cincinnati, Ohio, July 1979, p, 4-46. ‘lSupra No. 14, at p. 3-64. 15 Colony Development Operation, An Environ- ‘21bid. mental Impact Analysis for a Shale Oil Complex at “J. B, Weeks, et al., Simulated E~~ects of Oil- Parachute Creek, Colorado, vol. I, 1974. Shale Development on the Hydrology of Piceance Ch 8–Environmental Considerations 353

Basin, Ccdoraclo, Professional Paper 908, U.S. Geo- Reprints, vol. 15, No. 1, March-April, 1971, pp. logical Survey, Washington, D, C., 1974, p. 34. 21-25. “Ibid., p. 44. “Supra No. 14, at p. 3-44, “)Ibid,, p. 39. ‘)’ Ibid., p. 5-5o. ] “]Ibid., p. 40. ‘ National Safety Council, Accident Facts, stock Wupra No. 14. No. 021.57, Chicago, 1977. %upra No. 6. “R. H. Flinn, et al., Silicosis in the Metal Mining “A. L. Hines, The Role of Spent Shale in Oil Industry: A Reevaluation, 1958-1961, Public Shale Processing and tbe Management o-f Environ- Health Service, Pub. No, 1076, 1963. mental Residues, Department of Energy, report “Ibid. TID-28586, ERDA-Laramie Energy Research “)Personal communication with George Weems, Center, Laramie, Wyo., April 1, 1978. Supervisory Physical Scientist, Industrial Health ‘“B. W. Mercer, et al., “Assessment of Control Branch, Denver Technical Support Center, Min- Technology for Shale Oil Wastewaters, ’” paper ing Safety and Health Administration, Depart- presented at Environmental Control Technology ment of Labor, Jan. 22, 1980. Symposium, Department of Energy, November “1. P. Maripuu, Puusaar, “Spirographic and 1978. Roentgenofunctional Characterization of Pulmo- “lB. L, Harding and K. D. Lindstedt, et al., Re- nary Emphysema in Bituminous Shale Miners, ” moval of Ammonia and Alkalinity From Oil Shale Gyg. Tr. Prof. Zabol., vol. 15, No. 12, 1971, pp. Retort Waters, prepared for Laramie Energy 51-53. Technology Center, Department of Energy, con- ‘{{W. K. C. Morgan and N. Zapp, “Respiratory tract No. DE-AS20-78-ET-13096, April 1979. Disease in Coal Miners, ” American Review o.f I?es - “K. D. Lindstedt and E. R. Bennett, Report on piratory Diseases, vol. 113, 1976, pp. 531-559. Characterization and Treatment of Retort Waters ‘)OL. M. Irwig and P. Rochs, “Lung Function and From In Situ Oil Shale Retorting, Civil, Environ- Respiratory Symptoms in Silicotic and Nonsilicot- mental, and Architectural Engineering Dept., Uni- ic Gold Miners, ” American Review of Respiratory versity of Colorado, August 1977. Diseases, vol. 117, 1978, pp. 429-435. “Osmonics, Inc., “Application Test Report” ‘I(’V. A. Kung, “Morphological Investigations of (Study of the Application of Reverse Osmosis to Fibrogenic Action of Estonian Oil Shale Dust, ” En- Treatment of Oil Shale Wastewaters), report in vironment tal Health Perspectives, vol. 30, 1979, preparation for Laramie Energy Technology Cen- PP. 153-156. ter, Department of Energy, 1979. “W. E. Wright and W. N, Rem, “A Preliminary ‘“Water Purification Associates, A Study of Re- Report: Investigation for Shalosis Among Oil verse Osmosis for Treating Oil Shaie Process Con- Shale Workers, ” presented at Park City Environ- densates and Excess Mine Drainage Water, quar- mental Health Conference, Park City, Utah, Apr. terly progress report, prepared for Laramie Ener- 4-7, 1979. gy Technology Center, Department of Energy, con- ‘)’J. Rudnick and G. L. Voelz, “An Occupational tract No. DE-AC2O-79LC1OO89, September 1979. Health Study of Paraho Oil Shale Workers,”’ pre- “E. A. Ossio, et al,, “Anaerobic Fermentation of sented at Park City Environmental Health Con- Simulated In Situ Oil Shale Retort Water, ” Amer- ference, Park City, Utah, Apr. 4-7, 1979. ican Chemical Society Division of Fuel Chemistry “J. Costello, “Morbidity and Mortality Study of Reprints, vol. 23, No. 2, 1978, pp. 202-213. Oil Workers in the United States, ” Environmental “R. R. Spencer, Anuero&c Treatment o-f Waste- Health Perspectives, vol. 30, 1979, pp. 205-208, water Generated During Shale Oil Production %upra No. 107. (draft report), BattelIe Pacific Northwest Labora- ‘)7L. M, Holland, D. M. Smith, and R, G. Thomas, tory, 1979. “Biological Effects of Raw and Processed Oil %upra No. 24. Shale Particles in the Lungs of Laboratory Ani- %upra No. 25. reals, ” Environmental Health Perspectives, vol. ‘“B. Harding, et al., “Study Evaluates Treat- 30, 1979, pp. 147-152. ments for Oil-Shale Retort Water, ” Industrial ‘)’)L. M. Holland, W, D. Span, and L. L. Garcia, Wastes, September/October 1978, pp. 28-33. “Inhalation Toxicology of Oil Shale-Related Mate- “lA. B. Hubbard, “Method for Reclaiming rials, presented at Park City Environmental Wastewater From Oil Shale Processing, ” Ameri- Health Conference, Park City Utah, Apr. 4-7, can Chemical Society Division of Fuel Chemistry 1979. — —

354 . An Assessment of Oil Shale Technologies

85 b7R, A. Renne, J. E. Lund, K, E. McDonald, et al,, D. J. Birmingham, Interim Report on the Shale “Morphologic Effects of Intratrachially Admin- Oil Study, Public Health Service, Cincinnati, Ohio, istered Oil Shale in Rats, ” presented at Park City 1955. Environmental Health Conference, Park City, 8bTabershaw-Cooper Associates, Inc., A Mortal- Utah, Apr. 4-7, 1979. ity Study of Petroleum Refinery Workers, project ‘8Supra No. 63. OH-1, Medical Research Report No. EA-7402, b9B. T. Scheb, “Noise in the Mining Industry: Its American Petroleum Institute, September, 1974. Effects, Measurement, and Control, ” Proceedings 87N, M. Hanis, K. M. Stavraky, and J. L. Flowler, of the Symposium on Industrial Hygiene for A4in- “Cancer Mortality in Oil Refinery Workers, ” ing and Tunneling, American Conference of Gov- Journal of Occupational Medicine, vol. 21, No. 3, ernmental Industrial Hygieniests, Cincinnati, 1979, Pp. 167-174, Ohio, 1978. 88G. Theriault and L. Goulet, “A Mortality Study ‘[’M. Blick, et al., “Noise,” Medicine in the A4in- of Oil Refinery Workers, ’’Journal of Occupational ing Industries (J. M. Rogan, cd.), published by F. A. Medicine, vol. 21, No. 5, 1979, pp. 367-370. Davis, Philadelphia, Pa,, 1974, p. 244. 89M+ B. BIOCh and D. Kilburn (editors), proc- 711. Berenblum and R. Schoental, “Carcinogenic essed Shale Revegetation Studies, 1965-1973, Col- Constituents of Shale Oil, ” British Journal of Ex- ony Development Operation, Atlantic Richfield perimental Pathology, vol. 24, 1943, pp. 232-239. co., 1973. 72A. Scott, “The Occupation Dermatoses of the ‘(’W. R, Schmehl and B, D. McCaslin, “Some Paraffin Workers of the Scottish Shale Oil Indus- Properties of Spent Oil Shale Significant to Plant try, ” British Medical Journal, vol. 1, 1922, pp. Growth,” Ecology and Reclamation of Devastated 381-385. Land, vol. I (R. J, Hutnik and G, Davis, eds.), pub- 7JM. Purde and S, Etlin, “Cancer Cases Among lished by Gordon and Breach, New York, 1973, Workers in the Oil-Shale Processing Industry, ” PP. 27-43. presented at Park City Environmental Health Con- “’J. C. Ward and S. E. Reinecke, Water Pollution ference, Park City, Utah, Apr. 4-7, 1979. Potential of Snow~all on Spent Oil Shale Residues, “M. Purde and M. Rahn, “Cancer Patterns in prepared by the Environmental Engineering Pro- the Oil Shale Area of the Estonian Soviet Socialist gram, Department of Civil Engineering, Colorado Republic, ” Environmental i+ea)t~ Perspectives, State University for the Bureau of Mines, Laramie vol. 30, 1979, pp. 209-210. Energy Research Center, under grant No. 75A, Leitch, “Paraffin Cancer and Its Experi- 0111280, 1972, mental Production, ” British Medical Journal, vol. ‘zIbid. 2, 1922, pp. 1104-1106. “James R. Meiman, Infiltration Studies in the Pi- 7bI. Berenblum and R. Schoental, “The Differ- ceance Basin, Colorado, Thorne Ecological Insti- ence in Carcinogenicity Between Shale Oil and tute, technical publication No. 12, 1975. Shale, ’’British Journal of Experimental Pat~ology, ‘AIbid, 5 vol. 25, 1944, Pp. 95-96. ‘ Forest Service, Users Guide to Soils, Mining “C. C. Twort and J. M. Twort, “Classification of and Reclamation in the West, general technical Four Thousand Experimental Oil and Tar Skin Tu- report INT-68, Intermountain Forest and Range mors of Mice, ” Lancet, vol. 1, 1930, pp. Experiment Station, U.S. Department of Agricul- 1331-1335. ture, 1979. “J, M. Holland, et al., “Skin Carcinogenicity of “W. J. Culbertson, et al., Processed Shale Synthetic and Natural Petroleums, ” Journal of Oc- Studies: Environmental Impact Analysis, Appen- cupational Medicine, vol. 21, 1979, pp. 614-618. dix 5, Colony Development Operation, Atlantic 7YR. M. Coomes, “Carcinogenic Testing of Oil Richfield Co., 1974. Shale Materials, ” Twelfth Oil Shale Symposium ‘7 Supra No, 95, Proceedings, Golden, Colo., The Colorado School “R. M. Dixon, “Soil Imprinting for Increasing of Mines Press, November 1979. Land Productivity, ” presented at the 33rd Annual “)Ibid. Meeting of Soil Conservation Society of America, “Ibid. July 30-Aug. 2, 1978, Denver, Colo, Also printed in 821bid. the Journal of Soil and Water Conservation, 1978. ‘]Ibid. ‘gSupra no. 89. ‘“J. J, Zone, “Cutaneous Effects of Shale Oil,” ‘(WRio Blanco Oil Shale Co., Revegetation Pro- presented at Park City Environmental Health Con- gram 1978 Annual Report, submitted to Rio Blanco ference, Park City, Utah, Apr. 4-7, 1979. Oil Shale Co., Denver, Colo,, by NUS Corp., Den- Ch. 8–Environmental Considerations 355 ver, Colo., March 1979. 12]L. A. Richards (cd.), Diagnosis and Improve- II)]C. Wayne Cook, Rehabilitation Potential and ment of Saline and Alkali Soils, U.S. Department of Practices of Colorado Oil Shale Lands, progress Agriculture Handbook No. 60, 1954. report for period June 1978- May 31, 1979, pre- ‘221. F. Wymore, Water Requirement for Stabili- pared for the Department of Energy by Colorado zation of Spent Shale, doctoral dissertation, Colo- State University under contract No. EY- rado State University, Fort Collins, Colo., 1974, 76-S-02-4018, 1979. ‘z’D. D. Runnells, et al., “Release, Transport, I“zC. Wayne Cook, et al., Revegetation Guide- and Fate of Some Potential Pollutants, ” in Trace lines for Surface Mined Areas, Colorado State Elements in Oil Shale, report No. COO-4Ol 7-2, Envi- University, Range Science Department Science ronmental Trace Substances Research Program, Series No. 16, 1974. University of Colorado, Denver, Colo., 1978, pp. ‘()] Ibid. 49-97. ‘(”R. R. Ericsson and P. Morgan, “The Economic ‘“M. K. Kilkelly, et al., “Trace Elements in Feasibility of Shale Oil: An Activity Analysis, ” Plants Growing on Processed Oil Shales, ” in Bell Journal of Economics, vol. 9, 1978, pp. Trace Elements in Oil Shale, report No, 457-487. COO-4017-2, University of Colorado, Denver, Colo., “]5Supra No. 1. 1978, pp. 98-134. ‘(’t) Supra No. 96. ‘25 Supra No. 16. 11]71bid, ‘2hSupra No. 117. W5upra No. 90. ‘271bid, %upra No. 100. ‘28Supra No, 100. ‘loR. C. Woodmansee, et al, “Nitrogen in Dras- ‘2%upra No. 96. tically Disturbed Lands, ” Forest Soils and Land ‘30Fish and Wildlife Service, The Plant Informa- Use (C. T. Youngberg, cd.), Department of Forest tion Network: Volumes I-W, U.S. Department of and Wood Sciences, Colorado State University, the Interior FWS/OBS-77/38-41. Supporting com- Fort Collins, 1979, pp. 376-392, puter data base located at the Department of Bot- ‘]] Supra No. 101. any and Plant Pathology, Colorado State Univer- “zIbid. sity, Fort Collins, Colo. 11 ‘F. B. Reeves, et al,, “The Role of Endomycor- 1“C. M. McKell, et al., Selection, Propagation, rhizae in Revegetation Practices in the Semi-Arid and Field Establishment of Native Plant Species on West: A Comparison of Incidence of Mycorrhizae Disturbed Arid Lands, Institute for Land Reha- in Severely Disturbed vs. Natural Environments, bilitation, Utah Agricultural Experiment Station, American Journal of Botany, vol. 66, No, 1, 1979, Utah State University, 1979. pp. 6-13. 1‘zSoil Conservation Service, Plant Materials for “’Supra No. 101. Use on Surface Mined Lands in Arid and Semi- ‘}%upra No. 16. Arid Regions, U.S. Department of Agriculture “’Supra No. 90. handbook SCS-TP 157, Lincoln, Nebr. (in press). 1l’H. P. Harbert III, et al., Vegetative Stabiliza- ‘]’ Forest Service, User Guide to Vegetation, tion of Spent Oil Shales: Vegetation, Moisture, Mining and Reclamation in the West, general tech- Salinity and Runoff 1973-1976, 1978, nical report INT-64, Intermountain Forest and I l~H. p. Harbert 111, et al., ~YSimeter study on Range Experiment Station, U.S. Department of Ag- the Disposal of Paraho Retorted Oil Shale, Indus- riculture, 1979. trial Environmental Research Laboratory, Office ‘ “A. Plummer, et al., Restoring Big-Game Range of R&D, Environmental Protection Agency, Cincin- in Utah, Utah Division of Fish and Game publica- nati, Ohio (EPA-600/7-79-188), 1979. tion No. 68-3, 1968. IIqW. A. Berg, et al,, Vegetative Stabilization of l’5Supra No. 130. Union Oil Company Process B Retorted Oil Shale ‘%upra No. 133. 2975-1978, Colorado State University Experiment ‘%upra No. 101. Station, technical bulletin No. 135, 1979, “nIbid, 121)J. T, Herron, et al., Vegetation and Lysimeter ‘Y5upra No. 133. Studies on Decarbonized Oil Shale, Colorado State 1’OK. A. Crofts and C. M. McKell, Sources of University Experiment Station, technical bulletin Seeds and Planting Materials in the Western No, 136, 1980. States for Land Rehabilitation Projects, Utah Agri- 356 ● An Assessment 01011 Shale Technologies culture Experiment Station Land Rehabilitation Shale Committee, Summary of Industry Oil Shale Series No. 4, Logan, Utah, 1977. Environmental Studies and Selected Bibliography ‘“’ Supra No. 133. of Oil Shale Environmental References, Denver, ‘“2 Supra No. 101. Colo., 1975. 1“Supra No. 100, 15%upra No. 89. ‘“’N. C. Frischknecht and R. B. Ferguson, Reveg- “HJ. M. Merino, et al., “Reclamation of Spent Oil etating Processed Oil Shale and Coal Spoils on Shale,” Mining Congress ]ournal, vol. 63, No. 10, Semi-Arid Lands, interim report, EPA-600/ 1977, pp. 31-36. 7-79-068, Environmental Protection Agency, Cin- ‘%upra No. 117. cinnati, Ohio, 1979. ‘fWupra No. 118, ‘“R. W. Tinus, et al. (eds,), Proceedings of the “)lSupra No. 119. North American Containerized Forest Tree Seed- “)2Supra No. 120. ling Symposium, Great Plains Agricultural Council ‘(]] Supra No. 89. publication No. 68, 1974, ‘[)’ Ibid. ‘%upra No. 131. ““C. M. McKell, Achieving Effective Revegeta- ‘“71bid. tion of Disposed Processed Oil Shale: A Program ““Supra No. 132. Emphasizing Natural Methods in an Arid Environ- “’Supra No. 117. ment, Utah State University, Agriculture Experi- ‘%upra No. 132. ment Station Land Rehabilitation Series No. 1, “]Bureau of Land Management, Piceance Plan- 1976. ning Unit Resource Analysis, September 1970. ‘Wupra No. 16. “’Bureau of Land Management, White River ‘t)7Supra No. 89. Management Framework P~an, January 1972. ‘%upra No. 117. ‘s’K. C. Vories, A Vegetation Inventory and “%upra No. 90. Analysis of the Piceance Basin and Adjacent ‘%. C. Lipman, “Union Oil Company Revegeta- Drainages, master’s thesis, Western State Col- tion Studies, ” Environmenta~ Oil Shale Sym- lege, Gunnison, Colo., 1974. posium, Colorado School of Mines, Oct. 9-10, ‘“J. A. Tiedeman, et al., Phyto-Edaphic C~assifi- 1975, pp. 165-180. cation of the Piceance Basin, Colorado State Uni- ‘7’ Supra No. 119. versity, Range Science Department Science Se- “2Supra No. 118. ries No. 31, 1978. “]Supra No, 101. I“Ibid. “’Ibid. “’)Rocky Mountain Oil and Gas Association Oil CHAPTER 9 Water Availability

Page Page Introduction ...... 359 Physical AvailabilityofSurfac@ Water for Summary of Findings ...... 359 Oil ShaleDevelopment...... 380 Introduction ...... 380 Analysis of Water Requirements for Oil The Availability ofSurface Waterinthe Shale Facilities ...... , .. 361 Upper Colorado RiverBasin ...... 382 Introduction ...... , ...... 361 Water Availability inHydrologic Basins Process and Facility Models Analyzed ...... 361 Affected by OiIShaie Development ...... 385 Water Requirements ...... , ...... 362 An Evaluation of Assumptions in the Estimates363 Water AcquisitionStrategi@s andTheirCosts 388 Range of Water Requirements...... 366 PerfectionofDeveloperWater Rights ...... 388 Water Resources: A Physical Description. .. .367 Purchase ofSurplusWaterFrom FederaI SurfaceWater ...... 367 Reservoirs...... ~..”.”.389 GroundWater...... ,.,.373 Purchase ofIrrigationRights ...... 389 GroundWaterDevelopment...... ,..391 AIIocationoftheColorado River InterbasinDiversions...... 392 SystemWaters ● **.**.*.***** ...... 374 IntrabasinDiversions...... 393 Compacts, Treaties,andLegal Mechanisms. .375 Summary ofSupplyCosts...... 000.394 Surface WaterAllocations...... 376 Doctrine ofPriorAppropriation ...... 377 Legal andInstitutiona~Considerations ...... 395 Introduction ...... ,,,...... 377 TheLawoftheRiver...... 395 SurfaceRights ...... ,...... 377 The Doctrine ofPrior Appropriation ...... 396 Ground WaterRights...... 379 FederalReservedRights Doctrine ...... 396 Environmental Legislation ...... 397 FederalReservedRights ...... 379 InstreamWaterFlow ...... 398 — .—

Page Table NO. Page

Intei@askTmsnsfers ● ● * * ● . . . ● ● . ● ● ● ● ● ● ● ● ● 398 78. WaterRequirements for A@iveand Salinity Standards ...... 398 Proposed 011 Shale projects ., ...... 367 77. Estimates of Surface Water Critkdllqainties.,•• . . ● ...... ● . . ● ● 388 Allocations tothe C)il Shale States . . . . 376 ● ● ● 399 Virgin Flow .*..*, ..*,.** .**.**,. .**. 78. Present and Projected Water TechnologyMix ...... ,.400 Depletions for Activities Other Than ConventionalDepletions...... 400 Oil Shale Development in Colorado, GroundWaterDevelopment .. ., ...... 4oo Utah, and Wyoming...... , . . . . 384 ThelmpactsofUsingWaterfor oil 79. Estimation of Surplus Surface Water in ShaleD8ve10pment...... 0...... 401 Colorado, Utah, and Wyoming at Introduction ...... 0...... ,...401 Present andin2~. , ...... 385 ImpactsFromtheConstruction andOperation 80. Maximum Shale Oil Production Based ofWaterSupplyFaciIities ...... 401 on Surplus %rface Water in2000 . . . . 385 ImpactsFromChangesinSurface Flows. ....4oI 81. Water Requirements by Hydrologic ImpactsonWaterQuality . ....,...... 402 Subbasin for a l-Million-bbl/d Industry hnpacXsonRiverEcology , ...... ,.402 in2000...... 386 TransferofWaterFromIrrigated Agriculture402 82. Examples of the Charges for GroundWaterDevelopment...... ,403 Purchasing Surplus Surface Water I From U.S. Bureau of Reclamation MethodsforIncreasingWaterAvailability ..405 Reservoirs ...... 388 MoreEfficientUse ...... ,...405 83. Estimated Construction Costs for WeatherModification ...... 4o7 Proposed Reservoirs Within the Col-

Polioyoptions .*,..*** ● *...... ● ***.*,,, 407 orado River Water Conservation TheDeterminationofWaterNeeds ...... 4o7 District ● **. **. O . * * . * * * * . ***..,... 389 ReservoirSitingandDirect-Flow Diversions. .4O8 84, Summary of Cost Estimates for FinancingandBuildingNewReservoirs .. ...410 Intrabasin Diversions Within the Oil Financingandhnplementing MoreEfficient Shale Area ● ● ● ● ● ● ● ● ● ● ● ● . ● ● ● ● ● ● ● ● . ● 394 PracticesandWaterAugmentation...... 410 85. Summary of Approximate Water FederalSourcesofWaterfor OilShale Supply Costs for Several Acquisition Deve~opment...... ,412 Strategies ● ● ● ● ● ● ● ● * ● ● c s c c ● ● ● Q ● ● ● ● 395 TheAlkxationofWaterResources . ....,...412 86* Projected Salinity Changes in the lnterb@nDiversions...... ,..412 Lower Colorado River Because of Oil Shale Development ...... 402 Chaptel Preferences...... 412 List of Td!M98 %IM8NO* Page List of Figures 71. Process Models fur Oil Shale Facilities 361 Figure No. Page 72. Water Requirements for Mine 63. Major‘“ ‘Hydrologic- - - Basins of the Drahag@Production for 50,000-bbl/d Colorado River System , ....,....,., 369 Oil Shale F@iities ...... 362 64* The Upper and Lower Colorado River

73. ACo~atiwnof tie Water Reqtir~ Basins .*** **. ,.4,0** **, **, *.*c G* 370 mentsofthe Various Subprocesses . . . 363 65. Annual Average Virgin Flow of the 74. BredxhwnafWate rRequirements ColoradoRiverat Lee Ferry, W. . . . . 371 and Water Production for 50,000-bbl/d 66. Ma\or Dams and Reservoirs on tha Oil Shele Facilities ...... 364 Colorado River and Its Tribu~rim, . . . 372 75, Likely Ra~esof Water Requirements 67. FIowsofthe Colorado River~t~n ~ð

adhdinelhaimge Production for Oil 1953 and 1978 ● ● . ● ● ● ● ● ● ● ● ● ● * ● ● % ● * . 373 Shale Facilities Producing 50,000 bblld 68. Bedrock Ground Water Aquifen in of Shale Oil Syncrude ...... 367 Colorado’ sPiceance Basin ,., ., ...., 374

. CHAPTER 9 Water Availability

Introduction The oil shale deposits are located within estimated water requirements for oil the Upper Colorado River Basin, which in- shale facilities and their related growth; cludes the Colorado River and its tributaries the surface water and ground water re- north of Lee Ferry, Ariz, These waters are sources of the oil shale region; critical resources in the semiarid region. the laws, compacts, treaties, and other They are used for municipal purposes, irri- documents that allocate the waters of gated agriculture, industry and mining, ener- the Colorado River system; gy development, and maintaining recreation- the appropriation doctrine of Colorado, al, scenic, and ecological values. In the past, Utah, and Wyoming for distributing natural flows within the basin along with water supplies within State boundaries; water storage and diversion projects have the Federal reserved right doctrine: generally been adequate to satisfy demand. the physical availability of surface In the future, however, water resources may water for oil shale development; be taxed by rapid population growth, by ac- strategies and costs for utilizing water celerated mineral-resource development, and supplies; by increased recreational activities. Even- the uncertainties affecting water re- tually, the availability of water may limit resource assessments; gional growth including the expansion of in- the impacts of water use; dustrial developments such as oil shale. some methods for increasing water availability; and This chapter analyzes the availability of the policy options that might be imple- water in the oil shale region. The following mented to increase the availability of subjects are discussed: water.

Summary Findings

Surplus surface water will be available to supply developed. On the other hand, if the reservoirs and an industry of at least 500,000 bbl/d through 2000 pipelines are built, flows do not decrease, and the if: region develops at a medium rate (which the States regard as more likely), there should be sufficient ● additional reservoirs and pipelines are built; and surplus water to support an industry of over 2 million bbl/d through 2000. ● demand for other uses increases no faster than the States’ high growth rate projections; and In the longer term, surface water may not be ade- ● average virgin flows of the Colorado River do not quate to sustain growth; surplus water availability is decrease below the 1930-74 average (13.8 mil- much less assured after 2000. If the river’s flows do lion acre-ft/yr). not decrease, and if a low growth rate prevails, demand will exceed supply by 2027 even without an oil Otherwise, surface water supplies would not be ade- shale industry. With a medium growth rate, the sur- quate for this level of production unless other uses plus will disappear by 2013. A high growth rate will were curtailed, interstate and international delivery consume the surplus by 2007, again without any oil obligations as presently interpreted by the Govern- shale development. This is a potentially serious prob- ment were not met, or other sources of water were lem for the region, and its implications for oil shale

359 360 ● An Assessment of 011 Shale Technologies

development are controversial. On the one hand it is ervoir and pipeline construction and the cost of argued that there is no surplus surface water and treating the water to industrial standards. De- this should preclude the establishment of an indus- velopment of high-quality ground water would try. On the other hand, it it maintained that the be least expensive but would be limited to spe- facilities in a major industry could function for much cific areas. of their economic lifetimes without significantly in- ● terfering with other users, and in any case would use All strategies that relied on surface water would relatively little water. (A 1-million-bbl/d industry require construction of new reservoirs and pipe- would accelerate the point of critical water shortage lines, principally in the White River basin in Col- by about 3 years if only surface water were used. ) orado and Utah. About 180,000 to 230,000 acre-ft of new storage would be needed for a 1- Other findings are: million-bbl/d industry. Active capacity of existing reservoirs in the Upper Basin is about 34.7 ● Depending on the process used, production of million acre-ft. New construction for oil shale 50,000 bbl/d of shale oil syncrude would con- would increase storage by less than 0,6 per- sume 4,900 to 12,300 acre-ft/yr of water, in- cent. cluding water for related municipal growth and power generation. ● If a 2-million-bbl/d industry were developed, flows of the Colorado River would be reduced, ● A million bbl/d industry would require about and its salinity could increase by approximately 170,000 acre-ft/yr. * This would be about 1 2 percent. Studies by the U.S. Water and Power percent of the virgin flow of the Colorado River Resources Service (WPRS)* and the Colorado at the boundary of the Upper Basin, about 3 Department of Natural Resources (DNR) indi- percent of the water consumed at present by all cate that the economic losses from these users in the Upper Basin, and about 2 percent changes could reach $25 million per year by the of projected consumption in 2000. year 2000–the equivalent of $0.04/bbl of oil ● Potential oil shale developers already own rights produced. to substantial quantities of surface water. In ● Sale of irrigation water to oil shale developers 1968, for example, five companies claimed would reduce farm production. At present, de- rights to enough water to produce several mil- velopers do not plan to purchase such water in lion bbl/d of shale oil. significant quantities. Therefore, effects on the ● Existing developer rights would probably not farming industry should be small, especially assure supplies because surface water is over- compared with the effects of competition for appropriated and oil shale rights could be inter- labor and the purchase of farmlands for munici- rupted during shortages. More reliable supplies pal growth. could be provided through purchase of surplus ● Studies by USBR and DNR indicate that envi- water from existing Federal reservoirs, pur- ronmental impacts of water-resource develop- chase of irrigation rights, ground water devel- ment for oil shale should be small overall on the opment, and importation of water from other hy- Upper Basin but could be large in some areas. drologic basins. Fish habitats and recreational activities along

● Costs of the most expensive water supply op- the White River are expected to be the most tion, importation from other basins, could ex- severely affected. Impacts on the Lower Basin ceed $0.80/bbl of shale oil produced. Other are not expected to be substantial. strategies would cost less than $0.50/bbl of oil. ● Regional development could be limited by water These costs include the amortized costs of res- availability after 2000. Importation of water from other basins, conservation by municipal, * I+>or comp:]rison, irrigated [agriculture along the White agricultural, and industrial users, and possibly River and the Colorado River consumes about 549,000 acre- ft/yr to produce 3 percent of Colorado’s crop production. This is equ ivn]ent to the wn ter needs of a 3. 2-mill ion-bbl/d oil shale in- *Formerly the U.S, Bureau of Recltimation (USBR), For ease (iustrv. of reference, most citations in this ch{)pter are to the USBR. Ch 9–Water Avai/ability ● 361

weather modification could make additional gies could be impeded by legal, institutional, quantities available. The extent of the increase and economic factors. cannot be predicted accurately, and the strate-

Analysis of Water Requirements for Oil Shale Facilities* Introduction would be refined in the Midwest where water is abundant. Water will be used for oil shale mining and Estimates of water consumption vary wide- retorting, for shale oil upgrading, for revege- ly. In the following section the most recent tation and spent shale disposal, and for supplying the increased population and other re- estimates for alternative technologies on specific sites are analyzed, and then compared lated activities that will accompany the es- with estimates of regional water availability tablishment of a shale oil industry. More water will be needed for final refining but in order to identify the level of shale oil pro- this operation can be carried out at other lo- duction at which water resources might limit cations. In the early years of the industry, further development. some shale oil will probably be refined in the oil shale region and nearby in Denver and Process and Facility Models Analyzed Salt Lake City. Water is also scarce in these areas. However, the refineries are presently Facilities that use six retorting processes consuming water for processing conventional are described in table 71. The processes were petroleum. Shale oil will merely displace the selected for analysis because of their advanc- conventional feedstocks, thus its refining will ed development and because data have been not add significantly to water requirements. published on their water requirements. The In the long run, the output of a major industry processes fall into three generic classes: —— . . —.. directly heated aboveground retorting (AGR), *’I’his ,in[ilysis :)ssumf:s th:it th(? qu:intlly of wtit(;r rernokfx! indirectly heated AGR, and modified in situ for il giken purpose from [I stre:]m or ;lquifcr ( the w;] ter requirement] is numcri(:allv WIUH 1 tt) the qu:]nl i tv m:ldc un:)~t~ il- (MIS) retorting. The facilities modeled are: ilt)l[~ for SUt)S[>(]U[:Ilt 11S(?S IIh[: u :]ter (consumption ].” “1’his

:) ssu mp t ion is (’onsis t en t w i t h prcscn t (ievclopcr ~)li] ns for ~,[?ro- 1. TOSCO 11 indirectly heated AGR, (Iis(’h[i r~c w.{i ter m:i n:igcmen t svs terns, 2. Paraho directly heated AGR,

Table 71 .–Process Models for Oil Shale Facilities — — Shale Byproducts, ton/d Refer- grade Am- Technology Study encea Colorado Iocation gall ton Shale 0il capacity Other major product Coke Sulfur monia TOSCO Ilb Colony 3 Davis Gulch 35 47,000 bbl/d syncrude LPG 4,330 bbl/d 800 173 135 TOSCO Ilb WPA/DRl 1 Davis Gulch 35 47,000 bbl/d syncrude LPG 4,330 bbl/d 800 173 134 Paraho direct McKee-Kunchal 4 Anvil Points 30 87,000 bbl/d syncrude Low-Btu gas 32 billion 650 136 290 Btu/d Paraho direct WPA/DRl 1 Anvil Points 29 99,170 bbl/d crude Electricity 155 mWc o 132 146 Paraho Indirect McKee-Kunchal 4 Anvil Points 30 76,000 bbl/d syncrude Low-Btu gas 6 billion 650 136 290 Btu/d Union ‘ ‘B’ b Eyring/Sutron 10 Parachute Creek 34 100,000 bbl/d syncrude (d) d Oxy MIS Oxy 5,9 Tract C-b 24 57,000 bbl/d crude Electricity 350 mWe o 92 0 Oxy MIS WPA/DRI 1 Tracts C-a or C-b 25 57,000 bbl/d crude Electricity 97mWc o 144 281 Oxy MIS + Lurgi WPA/DRl 1 Tracts C-a or C-b 25 81,000 bbl/d crude Electricity 140 mW o 172 281

‘See reference I ISI dl eod of chapter bElec:rlcify purchased ‘Open cycle qas ‘urblnes ‘Data not provioed ‘Commned cycle system

SOURCE R F Probste!n e: al W’dfer l?e~wre~eofs PO I u?mri Effects dod COSIS O( kV.a[er SIIDply Jnd Tfe~fmem for foe 011 Sha/e ,ndwfr~ reporl prepared for OTA by Water Purllcaf,on Associates Oclo~er + ~79 D 4 — —

362 An Assessment of Oil Shale Technologies

3. Paraho indirectly heated AGR, formation has been published, the Union 4. Union Oil “B” indirectly heated AGR, process is considered here because plans for 5. Occidental Oil Shale’s directly heated a plant have been announced. ’() However, the MIS retorts, and data cannot be treated with the same confi- 6. a combination of directly heated MIS dence as for other processes. retorts and Lurgi-Ruhrgas indirectly A number of other studies’ ’-” have been heated AGR. completed but are not discussed in this sec- The water requirements of these facilities tion. Although they were based on data sup- were scaled to a common basis of 50,000 plied by the developers, their conclusions did bbl/d of synthetic crude oil. Thus, units for not agree because different retorting pro- upgrading crude shale oil to a high-quality cedures, products, production rates, power synthetic crude are included. Each facility supply modes, shale grades, and disposal pro- generates sufficient electric power for its cedures were assumed. own needs, and all solid waste dumps are revegetated. Wastewater is recycled wherever Water Requirements practical, and only excess mine drainage water is discharged or reinfected. Disposing The water requirements of the six oil shale of solid wastes by slurry backfill, either to the facilities, after scaling, are summarized in mine or to the burned-out in situ retorts, is not table 72. As can be seen, even facilities that included. The effects of byproduct coke, am- use similar processes (e. g., indirect AGR) re- monia, sulfur, or gas are not evaluated. True quire different amounts of water. However, in situ processes are not analyzed because no when the requirement for each subprocess is data are available. represented as a percent of the total, there is a correlation among different plants that use With the exception of the Union “B” plant, similar kinds of technology, as shown in table each estimate discussed in this section is de- 1-9 73. It is noteworthy that: rived from a published conceptual design, either the developer’s or one that has been Mining and dust control require consid- modified to put plant material and energy bal- erably more water in AGR than in either ances on a consistent basis. Although little in- MIS or MIS/AGR. This is because about

Table 72.–Water Requirements and Mine Drainage Production for 50,000-bbl/d Oil Shale Facilities (acre-ft/yr)

Paraho Retorting technology Paraho direct TOSCO II Indirect Union ‘'B” Oxy MIS MIS/AGR Study McKee- McKee- Eyring- Kunchal WPA/DRI Colony WPA/DRl Kunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl Reference 4 1 3 1 4 9 5 9 1 1 Unit operation Mining and handling. 816 941 1,045 1,045 934 – 483 483 338 326 Power generation ., 665 (b) 1,233 1,233 761 1,233 (b) (b) (b) (b) Retorting and upgrading 2,616 2,375 5,038 3,821 3,487 1,470 9,234 2,502 3,601 3,051 Shale disposal and revegetation 1,644 1,385 3,895 3,956 4.020 3,090 2,818 1,103 1,103 1,461 Municlpal use 645 645 594 594 731 731 775 775 775 818 Net water requirements In acre-ft/yr ., 6,386 5,346 11,805 10,694 9,933 6,524 13,310 4,863 5,817 5,656 In bbl water/bbl 011. 271 2.27 5.02 4.53 4,22 277 5.66 2.06 2.47 2.40 Mine drainage water In acre-ft/yr . (b) (b) (b) (b) (b) (b) 6,440-16,1004.032-6,452 12,326 8,454 In bbl water/bbl oil, (b) (b) (b) (b) (b) (b) 2.74-6,86 1,56-2.50 5.25 3.60 a.$ee reference IISI at end of chapter bNot apPllcab[e for projector Site analyzed SOURCE R F Probslem et al Wafer Reqwrenrerrfs Po/M/on IIfecfs arm Costs of Wafer Supply and Treafcnenf (or the 0/( Shale hrdusfry reporl prepared for OTA by Water Punhcallon Assoc!ales October 1979 p 8 Ch 9–Water Availability c 363

Table 73.–A Comparison of the Water Requirements Spent shale disposal and reclamation re- of the Various Subprocesses quire large amounts of water in the TOSCO II Generic technology (in percent) and Paraho indirect designs (about 4,000 Indirect and acre-ft/yr), while the estimate for the Paraho Subprocess direct AGR MIS/AGR MIS direct process is about 60 percent lower, Mining and handling 9-18 4-1o Largely because of this difference, the over- Power generation 8-12 (a (a) all requirement for Paraho direct is only Retorting and upgrading 35-44 54 51-69 Disposal and revegetation 26-40 26 19-26 about 5,900 acre-ft/yr, while the TOSCO II Municipal use 5-12 14 6-16 and Paraho indirect designs need about 10,500 acre-ft/yr or almost twice as much. a~ot applicable ‘or project or slfe SOURCf R F Probsfeln et al Waler Ftequfremerrls PoI/ufIorI EVec[s am Costs of Waler Sup Dly and r[ewrnenl for Ihe O// Shale /ndu$vj reporl orepared for OTA by Water Purlhca The requirements for MIS retorting and IIon Associates October 1979 D 9 upgrading are similar to those for indirect AGR. However, because little water is needed four times as much shale is mined and for mining and waste disposal, overall water handled in aboveground processing. The requirements for MIS are similar to those for larger amount of material also results in direct AGR; that is, about 5,800 acre-ft/yr. high water requirements for disposal For similar reasons, the requirements for and revegetation. MIS/AGR are similar to those for MIS alone. ● No water is needed for power generation It has been assumed that none of the AGR in MIS and MIS/AGR because power will plants will produce mine drainage water. The most likely be generated by burning low- MIS and MIS/AGR facilities, however, are Btu gases in open-cycle gas turbines that assumed to produce such water in substan- do not need to be cooled. Even if com- tial quantity. This difference is not related to bined-cycle systems were used, very lit- the technologies but rather reflects the siting tle cooling water would be needed. Cool- assumptions made for the various plants. The ing water is needed for AGR because sol- MIS and MIS/AGR facilities are on tracts C-a id-fuel steam-cycle systems will prob- and C-b in the ground water areas of the cen- ably be used, tral Piceance basin, while the AGR opera- ● Municipal water needs are proportional tions are in drier areas along the southern to the number of mine and plant employ- fringe of the Piceance basin or the eastern ees. For the same output, more workers portion of the Uinta basin. Mining in ground are required for MIS (about 1,800) than water areas produces mine drainage water for AGR (about 1,400 to 1,700). It is as- that must either be used, discharged, or rein- sumed that the MIS/AGR process would fected. The amount produced varies with lo- require slightly more workers (about cation, Estimates for tract C-b range from 1,900) than either technology by itself. 4,032 to 16,100 acre-f t/yr16 and for tract C-a to at least 18,100 acre-ft/yr. 17 This water Retorting and upgrading require the most should be regarded as an alternate water re- water. All the technologies need comparable source and not as part of the process. Similar amounts of water for upgrading, therefore, operations in other locations may not produce the differences among alternate technologies comparable amounts of water. reflect differences in retorting efficiencies. The large differences between similar above- -ground technologies result from specific oper- An Evaluation of Assumptions in ating characteristics, especially the methods the Estimates for heating the retort and for disposing and reclaiming the spent shale, More water is re- Detailed breakdowns of the water required quired for indirect than for direct AGR be- and produced by each principal operation in cause indirect heating has a significantly each model facility are shown in table 74. lower overall thermal efficiency, (Table 72 was derived from these data.) 364 ● An Assessment of 011 Shale Technologies

Table 74.–Breakdown of Water Requirements and Water Production for 50,000 -bbl/d Oil Shale Facilities (acre-ft/yr)

Paraho Paraho direct TOSCO II indirect Union ‘ ‘B’ Oxy MIS MIS/AGR McKee- McKee = Eyring- Kunchal WPA/DRl Colony WPA/DRl Kunchal Sutron Oxy 1977 Oxy 1979 WPA/DRl WPA/DRl Water required Mining and ore handling 816 941 1,045 1,045 934 (a) 483 483 338 326 b d Power generation 832b (c) 1,850 1,850 952d 1,850d (c) (c) (c) (c) Retorting and upgrading Cooling tower makeup 3,849 3,854’ 3,861 3,939 4,406 – 6,875e 806 4,494’ 3,626e Retorting — o 1,884 668 — — 2,731 3,753 2,731 1,873 Upgrading — 939d 939 939 — — 939d 939d 939d 939 e b e Other boiler makeup 1,224 490 557 557 1,401 1 ,71O 985 525 551e 529’ Steam and treatment loss — 50 572 572 — — 39 587 109 75 Service and fire water — 69 60 60 — — (a) 2,111 67 60 Potable and sanitary — 39 34 34 — — 113 161 31 28 Disposal and reclamation Shale moisturizing (c) (c) 2.859 2,920 (c) – (c) (c) (c) (c) Disposal and compaction 1,664 972 428 428 — 2,870 1,208 346 346 1,239’ Revegetation 413 608 608 4,020 220 1,610 757 757 222d Municlpal demand 1,61 4b 1,614b 1.485b 1,485° 1,829b 1,829b 1 ,937b 1 ,937b 1 ,937b 2,045d Total required 9,979 9,378 16,182 15,105 13,542 8,479 16.920 12,405 12,300 10,962 Water produced Power generation 167d (c) 617a 617d 191d 617d (c) (c) (c) (c) Retorting and upgrading Cooling tower blowdown . 768 1,653e 1,240 1,319 880 (a) 625e (a) 1,038 e 907e Retort condensate 127 (a) (a) (a) 388 240 1,243 2,419 1,243 852 Gas condensate 752 542 728 728 125 – (a) 3,072 2,157 1,480 Upgrading condensates 540 l03d 103 103 618 (a) l03d 103 103 103 Boiler and treatment waste 270 487e 557 557 309 (a) 486e 384 530’ 513e Service water effluent (a) 30 27 27 (a) (a) (a) 241 26 27 Potable and sanitary effluent (a) 26 26 26 (a) (a) (a) 161 23 20 Surface runoff’ (a) 222 188 188 (a) (a) (a) (a) 201 177 Municipal effluent 969d 969d 891 891d 1.098d 1,098 d 1, 162d 1, 162d 1, 162d 1,227d Total produced 3,593 4,032 4,377 4,456 3,609 1,955 3,619 7,542 6,483 5,306 Net consumption In acre-ft/yr 6,386 5,346 11,805 10,649 9,933 6,524 13.301 4,863 5,817 5,656 In bbl water/bbl oil. 271 227 5,02 453 422 2.77 565 2.06 2.47 2,40 Mine drainage In acre-ft/yr (c) (c) (c) (c) (c) (c) 6,440-16,1004,032-6,452 12,326 8,454e In bbl water/bbl 011 (c) (c) (c) (c) (c) (c) 2.74-6.86 1.56-2,50 525 3.60 e

atiot prowded bincludes mlnlng and re10flm9 cNot apphcable ‘Esllmated by OTA ‘Modd)ed lor OTA SOURCE R F Probsteln ef al Waler Reqwrerrrenls Po//u(/orr Effects and Cosfs of VLXer Supp/y and Trearmertl for [he Od Shd/e /rrUIJs/ry reporl prepared for OTA by Waler Purlflca[lon Associates October 1979 p 14

Paraho Direct sign assumed that a water-cooled steam cycle would be used; the Water Purification Asso- The two estimates for Paraho direct are ciates/Denver Research Institute (WPA/DRI) reasonably consistent. However, the McKee/ design assumed that low-Btu gas would be Kunchal water management plan is not suffi- burned in open-cycle gas turbines that re- ciently detailed for a thorough evaluation to quire no cooling water. be made of the differences that appear. The two designs differ principally in the mode of The retorts are also operated differently. A power generation. The McKee/Kunchal de- higher retorting temperature is assumed in Ch 9–Water Availability ● 365 the WPA/DRI design, and the water produced Paraho Indirect during retorting is vaporized and exhausted, In the McKee/Kunchal design, lower tempera- It is not possible to fully evaluate the tures cause partial condensation of the retort Paraho indirect estimates because the water. Also, upgrading was not considered by McKee/Kunchal report lacks a detailed water WPA/DRI, and it was necessary to adapt esti- management scheme. Compared with TOSCO mates from the TOSCO II plant design, H, retorting and upgrading requirements appear low. Also, the requirement for revegeta- The chief uncertainty is the claim of mini- tion is much higher than for all other retorts. mal water needs for spent shale disposal. The The reason given is the high carbon content of WPA/DRI design, which was based on this the spent shale, but this conclusion is not sup- claim, uses a conservative estimate of 5 per- ported by Union’s experience with similar recent by weight of water for compaction and torted shale. The high estimates for revegeta- a separate estimate for revegetation. The tion may have been made to offset low esti- l8 McKee/Kunchal estimate is not directly com- mates for compaction. parable because it combines compaction and revegetation. However, the total values are Union Oil “B” reasonably consistent. Because only crude data are available, Paraho’s claim that proper compaction can judgment should be reserved on the low esti- be obtained with small water additions is mates for mining, retorting, and upgrading, based on evidence from disposing about 150 The Environmental Protection Agency (EPA) ton/d of spent shale. It is uncertain that suffi- recently published a considerably higher esti- cient moisture could be extracted from the at- mate for mining and processing that would mosphere to dispose of 72,000 ton/d, the out- lead to a total consumption more in line with put of a 50,000-bbl/d plant. estimates for other processes. 19 Unfortunate- ly, the higher estimate cannot be verified because no background information was sup- TOSCO II 20 plied. An older EPA document provides a Although the Colony water management value for mining and processing consistent plan is very detailed, neither Colony nor with the Eyring/Sutron estimate. The relative- WPA/DRI assumed onsite power generation. ly large requirement for spent shale disposal OTA’s analysis assumed that about 85 MW of is a consequence of Union’s method for cool- power would be generated by a steam-cycle ing the hot retorted shale by immersing it in system. water,

A principal difference between the designs Occidental (Oxy) Modified In Situ is that WPA/DRI substituted a bag filter and electrostatic precipitator for Colony’s venturi The older Oxy estimate differs significant- wet scrubbers, thereby reducing water con- ly from the WPA/DRI design in both water re- sumption. Both designs assumed that the quirements and water production. Oxy’s re- spent shale is moisturized to 14 percent by quirements are higher for cooling water, for weight of water to allow proper compaction. raw shale disposal, and for revegetation, It For revegetation, both designs assumed an appears that these uses were deemed appro- average value of 608 acre-ft/yr over the 20- priate for disposing of excess mine drainage year life of the plant. During the first 10 water. Much less water is wasted in the years, little revegetation would be done and WPA/DRI design and in the newer Oxy plan. water would be used only for compaction and Also, the production of retort condensate was dust control. In the second 10 years, revege- not estimated in the older Oxy plan. The tation programs would be expanded and WPA/DRI estimate (2,157 acre-ft/yr) was water needs would increase. based on Oxy’s estimates of the steam flows 366 ● An Assessment of 0il Shale Technologies

to the retorts. (Much more condensate would this figure, The net requirement—70 gal/per- be produced if ground water entered the re- son/d—is conservatively high. The average torts during their operation. ) WPA/DRI also requirement for all the facilities considered is assumed that the retort gases are not com- about 700 acre-ft/yr. pressed prior to gas cleaning. This reduces the cooling water requirement, although it in- Mine Drainage Water creases the cost of the gas cleaning equipment. The net difference (considering conden- Probably the largest uncertainty of all, sate production and cooling water reduction) because it is highly site dependent, is the is about 6,700 acre-ft/yr, which accounts for amount of mine drainage water produced. As most of the discrepancy between Oxy’s older noted above, estimates for the Federal lease plan and the WPA/DRI study. In general, the tracts range from 6,400 to over 18,000 acre- WPA/DRI results agree quite well with Oxy’s ft/yr. This water should satisfy the processing current water management plan. needs of the technologies proposed for tracts C-a and C-b. However, these needs could Modified In Situ/Aboveground Retorting probably not be satisified by ground water on sites along the edge of Piceance basin. The only published water management plan for a combined facility is that of the Rio Blanco project on tract C-a. Details are not Range of Water Requirements sufficient for a thorough evaluation and the plan is now obsolete because Rio Blanco has The most likely ranges of the quantities of since revised its approach. The WPA/DRI water that will be consumed by the three ge- model, which combines MIS with Lurgi-Ruhr- neric technologies and by the combined plant gas retorts, is similar to the current plans for are indicated in table 75, Also shown are the the tract. likely ranges of mine drainage water production on tracts C-a and C-b. Overall, the re- The principal difference between OTA’s quirements range from 4,900 to 12,300 acre- process model and those of Rio Blanco or ft/yr—the equivalent of from 2.1 to 5.2 bbl of WPA/DRI is that OTA has assumed surface water consumed for each barrel of oil pro- disposal of the spent shale, whereas the duced. Given this range, a l-million-bbl/d in- others assumed that the waste is returned as dustry could require from approximately a slurry to the burned-out in situ retorts. In 100,000 to 250,000 acre-ft/yr. Actual water OTA’s analysis, it is assumed that the vapor requirements would be determined by the losses during moisturizing are the same as in mix of technologies used. In table 76, these underground slurry disposal. The estimates requirements are estimated for an industry for both revegetation and upgrading were that would result if present projects, both ac- linearly scaled from the TOSCO II require- tive and proposed, were completed. Some fea- ments. The accuracy limitations noted in the tures of this industry are: MIS discussion also apply here. ● Indirect AGR, the method with the high- Municipal Use est unit water requirement, constitutes 51 percent of the total production. It is assumed that the total population ● Direct AGR and MIS, which require less growth will be 5.5 times greater than the water, constitute only 33 percent of pro- number of employees.21 Because this large duction. The balance is provided by MIS/ multiplier is applied to uncertain employment AGR, which has an intermediate re- figures, the estimates of municipal water quirement. needs are approximate. An aggregate re- ● About 43 percent of the production will quirement of 175 gal/person/d has been result from mining in ground water assumed, with consumption at 40 percent of areas in the central and northern Pice- Ch. 9–Water Availability ● 367

Table 75.–Likely Ranges of Water Requirements and Mine Drainage Production for Oil Shale Facilities Producing 50,000 bbl/d of Shale Oil Syncrude

Water requirementsa Average shale grade, Technology gal/ton Acre-ft/yr Barrels per barrel of 011 Directly heated AGR 29-32 4,900-7,800 21-33 Indirectly heated AGR 32-35 9,400-12,300 40-52 Directly heated MIS 23-27 4,900-5.900 21-25 MIS/AGR 23-25 5,700-6,700 2.4-29 Location Water production Mine drainage water C-a/ C-b 4,000-16,100 1 6-69

a~el ~a[ef ~eqUlre~enls Low end assumes higher shale grade open cycle power systems high relorl efficiency and lower waste dls Posal and ‘eclama lion needs High end assumes lower shale grade sleam cycle or comt)lned cycle systems low retorhng efficiency and higher disposal and ‘ec Iamaflon needs SOURCE R F Probsleln el al Wafer Re~wreme~fs PoI/ufIorI Ef(eck and Cos(s of Wafer SW@y and Treafrner?( for fhe 0// S/ra/e (ndus[ry re?orl pre oared for OTA by Waler Purihcahon Assoclales October 1979 p 22

Table 76.–Water Requirements for Active and Proposed Oil Shale Projects

Design capacity Water requirements acre-ft/yr Barrels Percent For 50,000 For design Weighted Project Location Deposit Technology per day of total bbl/d capacity contribution

- – RIO Blanco Central Piceance basin Wet MIS/indirect AGR 76,000 16 6,200 9,424 992- Cathedral Bluffs Central Piceance basin Wet MIS 57.000 12 5,400 6,156 648 Long Ridge Southern Piceance basin Dry Indirect AGR 75,000 16 10.850 16.275 1,736 Colony Southern Piceance basin Dry Indirect AGR 46,000 10 10,850 9,982 1 085 Sand Wash Uinta basin Dry Indirect AGR 50,000 10 10,850 10,850 1 085 EXXON Central Piceance basin Wet Indirect AGR 60,000 13 10,850 13,020 1,411 White River Uinta basin Dry Direct AGR 100,000 21 6.350 12700 1,334 Superior Northern Piceance basin Wet lndirect AGR 11,500 2 10,850 2,496 217 Total 475,500 100 80,903 8,508

SOURCE Off Ice of Technology Assessment

ance basin. These plants could obtain The following sections will use these esti- their process water from the aquifers in mates in conjunction with estimates of sur- the mining zone. Surface water would plus surface water availability and other not be needed. critical factors to identify the level of shale oil The total production from this combination production at which water scarcity might re- (475,000 bbl/d) would require 80,903 acre- strict development. The issues section of this chapter discusses the industries that might ft/yr, On this basis, a 50,000-bbl/d plant result if a different mix of technologies were would need about 8,500 acre-ft/yr; a l-mil- used or if ground water were developed, lion-bbl/d industry about 170,000 acre-ft/yr.

Water Resources: A Physical Description Surface water is obtained from rivers and Surface Water streams; ground water from underground aquifers. In some instances, these sources The Colorado River system, which includes are physically connected and should not be the Colorado River and its tributaries, sup- evaluated independently. For example, if the plies surface water to the oil shale region. ground water supplies in most Western The Colorado River flows 1,440 miles from States were fully utilized, surface flows source to mouth. Its drainage area of 244,000 would decrease. mi2 includes parts of seven States and Mex- 368 ● An Assessment of Oil Shale Technologies ice. The waters of the Colorado River system Water quality in these streams is highly are divided between the Upper Colorado variable. The quality in most of the upstream River Basin (which includes parts of Col- reaches of major tributaries is good to excel- orado, Utah, Wyoming, Arizona, and New lent although some smaller streams that re- Mexico), and the Lower Colorado River Basin ceive discharge from saline ground water (which includes parts of California, Nevada, aquifers are of very poor quality. Water qual- Arizona, New Mexico, and Utah). (See figures ity is significantly poorer in most downstream 63 and 64. ) The basins are divided at Lee areas. The gradual deterioration is caused by Ferry, Ariz., 1 mile south of the Paria River flows of naturally saline streams into the near the border between Arizona and Utah. river system and by man-related discharges from settlements, mineral development sites, Six major streams enter the Colorado River and irrigated farmlands, Water quality and in the Upper Basin, From north to south, these the problems it causes are discussed further are the Green, the Yampa, the White, the in chapters 4 and 8. Gunnison, the Dolores, and the San Juan. The drainage area of the Upper Basin has been di- The Colorado River system drains an ex- vided into a number of hydrologic subbasins, tensive area, but its flows are relatively each corresponding to the watershed of a ma- small. The average annual virgin flow* at Lee jor river. Oil shale development may directly Ferry was 13.8 million acre-ft/yr between affect three of these subbasins: the Green River basin in the southeastern corner of *Virgin flow is the flow that would occur in the absence of Wyoming; the White River basin, which in- human activitv. Most of the water availability analyses in this chapter deals with the 1930-74 average because of its common cludes parts of western Colorado and eastern use in other water resources analyses. The effects of different Utah; and the basin of the Colorado River assumptions rega rcling virgin flow are discussed in the issues mainstem in Colorado. sect ion,

Photo credit OTA staff Upper Colorado River near Rifle, Colo. Ch 9–Water Availability 369

Figure 63. —Major Hydrologic Basins of the Colorado River System

MONTANA

/ OREGON

WYOMING r L I NEVADA UTAH UPPER COLORADO L \ RIVER BASIN

SOURCE U S Bureau of Reclamation Cr/f/Ca/ Wafer PrOb/erns Facing the E/eVen western ~fafes— Wesfwlde study VO/u~e / &faln ffeporf NTIS NO PB-263 981 Den ver Colo Aprtl 1975

1930 and 1974, in contrast to about 180 mil- nicipalities, agriculture, energy production, lion acre-ft/yr for the Columbia River and 440 industry and mining, recreation, wildlife, million acre-ftlyr for the Mississippi River. Federal lands, and Indian reservations all Despite its relatively low flows, the system is compete for its waters. one of the most important in the Southwest. It Flows vary seasonally, increasing with serves approximately 15 million people. Mu- spring snowmelts and heavy rainstorms in —

370 ● An Assessment of Oil Shale Technologies

Figure 64.—The Upper and Lower Colorado River Basins

i I \ 1

. CASPER -1 /’+“ ‘ja~e t:” + Great -.. Salt .’ “L k I -1,.-. w ‘a’” /“

● DENVER

,. I ( MEXICO

t 1 100 MILES i

SOURCE: C. W. Stockton and G. C. Jacoby, “Long-Term Surface-Water Supply and Streamflow Trends In the Upper Colorado River Basin Based on Tree-fllng Anal. yses,” Lake Powell Research Pro/ect Bu/let/n No. 18, March 1976, p.2 Ch 9–Water Availability ● 371 the late summer and fall and declining during Point, and Blue Mesa Reservoirs) in Colorado. the rest of the year. They also vary from year These projects have been completed and are to year, as shown in figure 65. Flow records now being filled, When full, the existing and examination of vegetation growth cycles reservoirs will have a maximum active stor- indicate that they may also vary over a much age capacity of about 35 million acre-ft/yr. longer period, spanning decades or even cen- Lake Powell is by far the largest, and will turies. The fact that virgin flows at Lee Ferry have an active capacity of about 25 million between 1906 and 1974 averaged about 15.2 acre-ft. Other reservoirs have been author- million acre-ft/yr while between 1930 and ized by Congress but funds have not yet been 1974 they averaged only 13.8 million acre- appropriated for their construction. These in- ft/yr is evidence of this long-term variability y. clude the Savery Pothook, Fruitland Mesa, and West Divide projects. The locations of the The flow variations are significant because existing CRSP reservoirs are shown in figure they reduce the accuracy of long-term projec- 66. tions of water availability. They also furnish a rationale for building reservoirs to offset Reservoirs have been effective in dampen- seasonal fluctuations and stabilize supplies ing the fluctuations in the virgin flows. This is during dry years. Several reservoirs have illustrated in figure 67, which compares ac- been built in the Upper Basin for this pur- tual measured flows of the Colorado River at pose. The five largest were built by the Fed- Lee Ferry with the corresponding estimates eral Government under the Colorado River of virgin flows for the period 1953-78. The Storage Project Act (CRSP) of 1956: Lake Flaming Gorge and Navajo Reservoirs began Powell in Arizona and Utah, Flaming Gorge in filling in 1962; Lake Powell in 1963, and Utah and Wyoming, Fontenelle in Wyoming, Fontenelle in 1964. During prior years, actual Navajo in New Mexico, and the Curecanti flows varied widely, from 6 million acre-ft/yr Unit (which includes the Crystal, Morrow to over 17 million acre-ft/yr. In 1962, the ac-

Figure 65.—Annual Average Virgin Flow of the Colorado River at Lee Ferry, Ariz.

PAST DEPLETION PLUS CRSP STORAGE 26- AVERAGE VIRGIN FLOW PROGRESSIVE 10 YEAR 1922-78 24- AVERAGE OF VIRGIN FLOW AVERAGE 22— (Plotted at end of year) HISTORIC r ‘ F VIRGIN FLOW ) [~ ~ 1 20- FLOW— 1 iLIL u

II o I 0 0 b om ill% m WATER YEAR

SOURCE Upper Colorado River Commlsslon. Thlrt/efh Annua/ Reporf. Salt Lake City, Utah, Sept 30, 1978, p 44 372 ● An Assessment of Oil Shale Technologies

Figure 66.— Major Dams and Reservoirs on the Colorado River and Its Tributaries WYOMING t ,, 1

NEVADA

● cARSOmJ CIT’Y

r Y o

# - a., -... -- MM Hew

o Colorado River Storage Project Act Dam and Reservoir

SOURCE Upper Colorado River Commlssmn, Th/rf/eth Annua/ Report, Salt Lake City. Utah, Sept 30, 1978. p. 44 Ch 9–Water Availability ● 373

large. It has been estimated that bedrock aquifers in the Piceance basin could contain as much as 25 million acre-ft in storage. This is nearly twice the annual virgin flow of the Colorado River at Lee Ferry and is equivalent to the storage capacity of Lake Powell. The primary bedrock aquifer near Federal tracts U-a and U-b in Utah is estimated to contain at least 80,000 acre-ft. The actual quantities of ground water that could be used for oil shale development are uncertain. The amount available is determined by the location of the aquifers relative to potential plantsites, the water quality, and physical characteristics such as the depth and the recharge rate. The physical characteristics determine the quantity of water that can be stored or extracted, the rate at which water can be added or withdrawn, and the change in water levels that will result from withdrawing a given volume of water.

— Actual Flow The principal aquifers of the Piceance ba- — - — Vlrgln Flow sin are located in the Uinta and Green River geologic formations. (See figure 68.) The system is characterized by two bedrock aqui- ? 1 fers, the “upper” and the “lower,” that are ; ~:: i%%ggg;g$:$ -r -- u separated by a 100- to 200-ft-thick confining YEAR layer of rich oil shale known as the Mahogany SOURCE Upper Colorado River Commlsslon Ttrfrtfeth Annua/ Report Salt Lake City Utah, Sept 30.1978. p 44 Zone. In addition, alluvial aquifers occur in gravel, sand, and clay along the bottoms of tual flow dropped substantially, partly be- stream and creek valleys. cause of low virgin flow and partly because of The bedrock aquifers are recharged by the start of reservoir filling. In 1968, the ac- springtime snowmelt, which replaces an esti- tual flow approached 8 million acre-ft/yr and mated discharge of 26,110 acre-ft/yr. Water has remained within the range of 8.23 million enters the upper aquifer along the basin to 10.14 million acre-ft/yr ever since. Between margins above an altitude of 7,000 ft and 1968 and 1978, virgin flows ranged from 5.5 moves downward through the Mahogany million to 19.3 million acre-ft/yr. Actual flows Zone to recharge the lower aquifer. General- have not yet stabilized because the reservoirs ly, ground water in both of these aquifers are still filling. flows from the recharge areas toward the discharge areas in the north-central part of Ground Water the basin. In the discharge areas water moves upward from the lower aquifer Ground water resources occur near the through the Mahogany Zone to the upper surface in alluvial (floodplain) aquifers and aquifer and is discharged both to the alluvi- more deeply buried in bedrock aquifers. In um and by springs along the valley walls. most areas, alluvial aquifers contain relative- Ultimately, the discharged ground water ly little water. The amount in bedrock aqui- flows into Piceance and Yellow Creeks and fers is unknown but is though! to be very then into the Colorado River system. 22 — —

374 ● An Assessment of 011 Shale Technologies

Figure 68.— Bedrock Ground Water Aquifers in Colorado’s Piceance Basin

West East 8000’ 1 – 8000’

7000’ - 7000’

—

6000’ - 6000’

5000’ - 5000’

4000’ - 4000’ 1 I Vertical Exaggeration x PO Wasatch formation 3000’ I 3000’ 2 6 miles ~ Datum is mean sea level

9 : ...”O “9 e .,’e. -. . . ., ....O.O.O m0, n n El u:::.:.:.: Sandstone Marlstone, contains High Sand & gravel Marlstone &/or conglomerate &/or siltstone oil shale & saline minerals rewstivity zone LEGEND

SOURCE Department of the Intenor, Draft Envlronrnental Sfaternenf-Proposed Deve/opmenf of 0// Sha/e Resources by fhe Co/ony Deve/oprnenf Operaf/on In Co/o. rado, Bureau of Land Management (1975), p Ill 34

Despite the large resources, little ground little water is withdrawn, and the ground water development has taken place to date. z water system is in hydrologic equilibrium. The major economic use is for watering live- That is, the rates of recharge and discharge stock. In addition, natural seeps and springs are equal and the amount of water in storage supply water to vegetation and wildlife in does not change significantly over time. many of the valley floors. Overall, relatively

Allocation of the Colorado River System Waters

Because of competing demands, disputes preme Court decisions, and international over the proper allocation of water resources treaties has been developed to govern distri- have permeated the political, social, econom- bution of the system’s waters. Together, the ic, and legal histories of the seven States in provisions of this framework comprise “the the Colorado River system. As a result, a com- law of the river.” Their interpretation is cru- plex framework of interstate and interra- cial to an understanding of the water avail- gional compacts, State and Federal laws, Su- ability problem. Ch. 9–Water Availability . 375

Compacts, Treaties, and ects for irrigation, power generation, Legal Mechanisms and other purposes. The Colorado River Compact of 1922 The Upper Colorado River Basin Compact of 1948 The major provisions of this compact are: In this compact, the Upper Basin States ap- 1. It divided the river system into the Upper portioned the water allocated under the com- and Lower Basins, and allocated 7.5 mil- pact of 1922. The negotiators recognized the lion acre-ft/yr to each basin for bene- problem inherent in allocating water on a ficial consumptive use, Authority was strict quantity basis because of flow fluctua- also given to the Lower Basin to increase tions from year to year. As a result, water its annual use by 1 million acre-ft. was apportioned on a percentage basis to all 2. It did not recognize a specific obligation States except Arizona. Major provisions of to provide water to Mexico. However, a the compact are: framework was established whereby

any future obligation would be shared 10 Arizona was guaranteed 50,000 acre- equally between the Upper and Lower ft/yr, The remaining water was appor- Basins. tioned as follows: 3. The Upper Basin was prohibited from re- ● to Colorado: 51.75 percent, ducing the flow at Lee Ferry to below an ● to New Mexico: 11.25 percent, aggregate of 75 million acre-ft in any 10- ● to Utah: 23.00 percent, and year period. The Upper Basin was not to ● to Wyoming: 14.00 percent, withhold water, nor was the Lower Ba- 2. It recognized that new reservoirs would sin to demand water that could not rea- be needed to assist the Upper Basin in sonably be applied to domestic and agri- meeting its delivery obligation to the cultural uses. Lower Basin. Such reservoirs, however, would increase evaporative losses from the river system as a whole, thus reduc- The Boulder Canyon Project Act of 1928 ing the quantity of surplus water avail- This Act provided for the construction of able to the Lower Basin. The compact Hoover Dam and its powerplant, and for the provided that charges for such evapora- All-American Canal. Its major provisions are: tive losses be distributed among the Up- per Basin States. Each State was to be 1. It suggested a specific framework for charged in proportion to the fraction of apportioning the water supplies allo- the Upper Basin’s water allocation that cated by the compact of 1922 among the was consumed in that State on a yearly Lower Basin States of California, Ari- basis, and its maximum consumptive use zona, and Nevada. (The States did not was to be reduced accordingly. adopt this framework, but it was later 3. It provided for the division of water be- imposed on them by the Supreme Court tween pairs of States on a number of decision in Arizona v. California, as dis- specific rivers. The compact did not deal cussed below.) with the White River, which delivers ap- 2, It required California to reduce its an- proximately 500,000 acre-ft/yr to the nual consumption to 4,4 million acre-ft Utah State line and which could supply plus not more than half of the surplus water for energy development. water provided to the Lower Basin. (This requirement was met through the Cali- Mexican Water Treaty of 1944-45 fornia Limitation Act of 1929.) 3. It authorized the Secretary of the Interi- As part of negotiations over apportionment or to investigate the feasibility of proj- of water from the Rio Grande, Tijuana, and 376 ● An Assessment of 0il Shale Technologies

Colorado Rivers, the United States guaran- Colorado River Basin Project Act of 1968 teed to deliver at least 1.5 million acre-ft/yr of water to Mexico. However, in times of severe This Act instructed the Secretary of the In- drought or in the event of a failure in the terior to propose criteria for the coordinated delivery systems, Mexico could receive less long-range operation of reservoirs built under than 1.5 million acre-ft/yr. the Boulder Canyon Project Act and the CRSP Act. Criteria were subsequently established and now form the basis for operation of the Colorado River Storage Project Act of 1956 reservoirs. (These operating criteria are of importance in estimating water availability in This Act provided for several new storage the Upper Basin States, as discussed below.) reservoirs to assist the Upper Basin States in The Act also identified the Mexican Water meeting their delivery obligation to the Lower Treaty as a national obligation, to be con- Basin, while simultaneously increasing water sidered in developing any subsequent water consumption in the Upper Basin. The five projects. It prohibited the Secretary from CRSP reservoirs that have since been built studying importation of water into the Colora- were described in the earlier discussion of do River Basin until 1978. (This moratorium the fluctuating flows of the river. was subsequently extended to 1988 by the Reclamation Safety of Dams Act of 1978.) The Supreme Court Decree in Arizona v. California Surface Water Allocations This decision (376 U.S. 340 (1964)) imposed Each of the above documents assumes dif- upon the Lower Basin States the water distri- ferent values for the quantity of virgin flow bution framework that had been suggested by past Lee Ferry. They therefore differ with re- the Boulder Canyon Project Act of 1928. The spect to the total amount of water to be ap- Lower Basin’s water allocation of 7.5 million portioned. In general, each State can inter- acre-ft/yr was to be apportioned as follows: pret the law of the river so as to maximize its water-resource position and can develop its water programs on that basis. Consequently, ● to California: 4.4 million acre-ft/yr, an analysis of the opportunities for further ● to Arizona: 2.8 million acre-ft/yr, and growth in the Upper Basin States is clouded ● to Nevada: 0.3 million acre-ft/yr. by uncertainty, and it is not possible to predict with any exactitude the maximum size of The decree also required that approximately the oil shale industry that could be accom- 1million acre-ft/yr from the allocations to modated. California and Arizona be diverted for the five Indian tribes located along the lower Col- The annual virgin flows assumed in some orado River. of these documents are shown in table 77.

Table 77.–Estimates of Surface Water Allocations to the Oil Shale States (millions of acre-ft/yr)

Virgin flow Source of virgin flow estimate at Lee Ferry Colorado Utah Wyoming Total Colorado River Compact of 1922 ...... , . . 180 5.06 2.25 1.37 8.68 Mexican Water Treaty of 1944 -45...... 16.2 4.12 1.83 1,12 7,07 Upper Colorado River Basin Compact of 1948. , ., ., 15,6 3.81 1.70 1.03 6.54 Colorado River Basin Project Act of 1968 . . 14.9 3.45 1.53 0,93 5.91 Average flow 1930 -74...... 13.8 2.88 1,28 0.78 4.94

Assumes dehvery of 823 mllhon acreft/yr to Lower Basin Slates and Mexico 7500000 acre-ft/yr 10 Lower Basin (per 1922 compact) plus 750,000 acre-ft/yr 10 Mexico (per Mexican Waler Trealy of 1944-45) less 20 OOOacre-ff/yr Inflow from the Pana River below Lake Powell = 8230000 acre-ft/yr Neglecfs evaporafwe losses from Upper Basin reservoirs Assumes apportionment among the 011 shale Slates according to the Upper Colorado Rwer 8asm Compact of 1948 SOURCE Ofhce of Technology Assessment Ch 9–Water Availability 377

Also shown is the average virgin flow at Lee teria prepared under the provisions of the Ferry between 1930 and 1974. For each flow CRSP Act of 1968. As indicated, the quantity figure, the corresponding gross quantity of of surface water available to the three States surface water allocated to each oil shale under the terms of the various documents State is also shown. It was assumed that the could be as low as 4.94 million acre-ft/yr and Lower Basin States receive 8.23 million acre- as high as 8.68 million acre-ft/yr. The lower ft/yr out of the Lake Powell Reservoir above figure is more realistic for planning purposes, Lee Ferry, as called for in the operating cri-

Doctrine of Prior Appropriation Introduction wards the actual use of the water. An absolute water right is created when a holder of a The water rights policies of Colorado, conditional right perfects that right by actual- Utah, and Wyoming are, in general, similar. ly diverting the water and applying it to a Their respective constitutions hold that water beneficial use. Beneficial uses have been de- is the property of the public, not the landhold- fined to include any use in which water is not er, and that it is the State’s responsibility to wasted. apportion rights to use water among competing users, Each State administers surface Within each category there are two types water rights and some ground water rights of water rights. A direct flow or diversion according to a doctrine of prior appropria- right permits the diversion of water from a tion, This differs from the riparian doctrine stream followed by its immediate application. that prevails in most Eastern States under A storage right permits the impoundment of water for later application. None of the three which water rights are automatically the property of the owner of the land on which States recognizes the right of private parties the water is found. Under the prior appro- to require that sufficient stream flows be priation doctrine, water rights are severable maintained for the protection of instream from the land, and one may own water rights uses, such as rafting and fishing. However, a without owning any land whatsoever. Colorado law permits that State to obtain water rights for sufficient flows to preserve the natural environment to a reasonable degree. Surface Rights In Colorado, the water rights are adjudi- The key elements of the doctrine of prior cated by the State Water Courts and adminis- appropriation are: the specific types of water tered by the State engineer. The right to ap- rights, the seniority system for determining propriate water is limited only in that prop- priority of use, the preference system for dis- erty rights of other parties cannot be im- tinguishing among types of water uses, op- paired. A conditional right is automatically tions for transfer of water rights between granted if the user proceeds with due dili- parties, and policies for determining the gence towards perfection of the right and if abandonment of water rights. the rights of other users are not jeopardized. Neither the courts nor the executive branch Types of Water Rights of government has discretionary authority over the type, place, or quantity of use. Fur- There are two categories of water rights: thermore, the State has no power to remove a conditional and absolute. A potential user ac- stream or any portion of its waters from ap- quires a conditional water right by filing for a propriation. The State engineer only monitors conditional decree from the State water the system to assure that rights are protected courts and then proceeding diligently to- and water is not wasted.

53-898 ‘1 - 3 f) - 2 ‘, —

378 ● An Assessment of 011 Shale Technologies

In Utah and Wyoming, a permit system is by water court decrees in Colorado or by the employed in which the right to appropriate permitting process in Utah and Wyoming. water must be approved by the State engineer. He must consider the water rights of Preference Systems others, but is also allowed to consider public interest or public welfare when passing on an A preference system has been established application for appropriation. Thus, in con- in each State to apportion water among dif- trast to Colorado, the governments of Utah ferent beneficial uses during times of short- and Wyoming have discretionary authority to age. Under its provisions, drinking water or approve some uses and deny others. Use of municipal users have first preference, agri- this power has been minimal. culture is second, and industry is third. The preference system overrides the seniority It is noteworthy that the continuation of system; water rights with a lower preference conditional decrees requires only due dili- may be condemned in favor of a higher pre- gence and not actual use. In the past, rights ferred use, even if the preferred water right have been granted liberally by all three is junior to the displaced right. In most cases, States and as a result, the quantities of water just compensation would be required for discovered by conditional decrees far exceed placed senior water rights. the available resources. Not all of the conditional decrees have been perfected, and relatively little of the claimed water is actually Transfer of Water Rights being used. Consequently, surplus surface Water rights are considered real property water appears to be available in the oil shale and may be sold or transferred. 24 They are region. However, all of it has already been conveyed by deed and may be severed from claimed, in part by oil shale developers. Simi- the land on which the water was originally lar situations prevail in Utah and Wyoming. used, In Colorado, such transfers are reviewed by the water courts and may only be Seniority of Water Rights denied if other users would be harmed. In The prior appropriation doctrine is based Utah and Wyoming, application for transfer on the principle of “first-in-time, first-in- is made before the respective State engineer, right. ” Thus, the more senior (older) the wa- who decides whether harm will occur to ter right, the higher its priority for the use of other users and also considers public interest limited resources. If shortages occur, user and other factors. Sale and transfer of water rights that are junior in terms of the initiation rights is complicated by the need to protect date are curtailed to assure water supplies to junior appropriators, seasonal rights of some users with more senior rights. Only when the users, appurtenance (right-of-way) of water most senior rights have been satisfied do less rights to land, and preferred use as defined senior users have any rights to water. by the individual States, The date of a right, assuming the appro- Abandonment of Water Rights priation goes forward diligently to completion, is the date of the first act evidencing an In all three States, absolute water rights intent to take water for beneficial use. In gen- may be partially or completely lost by aban- eral, this is the date on which the application donment. In Colorado, failure to use an abso- for a conditional decree was filed. In Col- lute right for a period of 10 years constitutes orado, a State statute makes most water prima facie evidence of abandonment. The rights a matter of public record. Rights to sur- status of water rights is reviewed periodical- face water are established solely by the ac- ly by the division engineer in each of the tions of individual users, but these rights are State’s water divisions. In Utah and Wyo- legally protected only if they are formalized ming, abandonment is defined as nonuse for a Ch 9–Water Availability 379 period of 5 years. Unlike Colorado, these tary ground water in nondesignated ground States have no provisions for a continuing re- water areas, on the other hand, is subject to view of the status of water rights. prior appropriation. Permits for wells must be obtained from the State engineer, and Ground Water Rights ground water rights must be adjudicated by the water courts to assure legal protection, In Colorado, tributary ground water just as with a surface right. Small wells (less (ground water that is hydrologically con- than 15 gal/rein) for livestock or domestic use nected to the surface water system) is treated have been defined by law to cause no injury essentially the same as a surface flow and and are exempt from such regulations. thus is subject to the prior appropriation doctrine. Nontributary ground water (ground In Utah, all ground water is subject to the water that does not reach surface streams) is appropriation doctrine. Rights are adminis- divided into two categories: designated tered by the State engineer and permits for ground water basins and nondesignated wells may be sold as any other water rights. ground water areas, Nontributary ground In Wyoming, permits must be obtained for water resources in designated basins are any ground water use. Livestock watering controlled by a permit system through the and domestic uses have preference over all State Groundwater Commission. Nontribu- other rights, regardless of seniority.

Federal Reserved Rights

The Federal reserved rights doctrine origi- to other Federal reservations such as na- nated in the Supreme Court decision in Win- tional recreation areas, wildlife refuges, and ters v. United States (207 U.S. 564 (1908)) re- national forests. In addition, the Court ad- garding Indian water rights. It was held that dressed the question of the quantity of water when Indian reservations were established reserved for Indian use. It held that water by treaty with the United States, sufficient was intended to satisfy the future as well as water to supply all Indian lands was also the present needs of Indian reservations, and reserved. The Court did not quantify suffi- ruled that sufficient water would be reserved ciency. Rather, it reflected the opinion that to irrigate all the practicably irrigable acre- Indian reservations were created to trans- age on the reservations. 26 form a nomadic people into permanent set- lers and that those people required suffi- A further Supreme Court decision in 25 (98 cient water for irrigation. United States v. New Mexico Sup. Ct. 3012 (1978)) attempted to resolve the uncertainty A major effect of this decision is that the over the qualification of Federal reserved vater rights set aside for Indian reservations water rights for areas other than Indian res- vere interpreted to be superior to those of all ervations. The Court concluded that the doc- ther subsequent appropriators who ob- trine applied only to the original purposes of tained their rights under State law, even the reservations, and that reserved water though the Indian tribes had not yet put their rights could not be used for other purposes. 27 rights to beneficial use. Federal rights were For example, the rights associated with a na- thus entered into the prior appropriation tional forest could be used for maintaining system of each affected State, together with the forest and its wildlife, but not for indus- 11 other applicants and appropriators. try, farming, or oil shale development. In Arizona v. California, the Court ex- While the Supreme Court has served notice ended the reserved right doctrine to Indian that it will interpret the purpose of Federal reservations created by Executive order and reservations narrowly, a number of uncer- .—

380 ● An Assessment of 011 Shale Technologies tainties remain concerning the quantities of be used, whether the use must take place on water that could be claimed to serve these the reservation, and whether rights can be purposes. With regard to Indian reserva- sold or leased for uses outside the reservations, for example, it is still uncertain how tion. much water will be claimed, how much will

Physical Availability of Surface Water for Oil Shale Development Introduction other users are partially curtailed. When this will occur is not known. If it happens before The size of the industry that could be sup- the plants are built or during their useful life, ported by surplus surface water is affected then social and economic dislocations would by the following factors: result. If, on the other hand, it occurs after conservation and the development of other ● the long-term average virgin flow in the energy sources have sufficiently diminished Colorado River system (this determines the demand for liquid fuels, then the disturb- the gross quantity of water that is avail- ances caused by the temporary presence of able); an industry may not be overwhelming. ● the compacts and other documents that constitute the law of the river (these de- This section evaluates whether the surface termine how the gross water supply is al- water resources in the Upper Basin are phys- located among the basins and States); ically adequate, and legally available, to sup- ● the demands of other users (these con- port a large industry. Availability is analyzed sume part of the allocation to each State, for the Upper Basin as a whole, and for the the remainder is the surplus); hydrologic subbasins that are likely to be af- ● the oil shale technologies employed fected. The factors analyzed were highlighted (these determine how much water the in- above. Following is a summary of the assump- dustry would need); tions made and of the sources of supporting ● the siting of the facilities (this deter- information. mines how the industry’s water demands will be distributed among Colora- Virgin Flow do, Utah, and Wyoming); and ● the timing of their construction and the An annual average flow of 13.8 million duration of their operation. acre-ft/yr past Lee Ferry is assumed. This is the running average between 1930 and 1974. The final factor is particularly important. Virgin flows have been calculated since 1896, The region’s surface water resources are and the 1896-1974 average is considerably finite, and they are not large. In the past, they higher-15.2 million acre-ft/yr. However, the have generally been adequate, when supple- natural flows (the basis of the calculated mented by reservoir storage, to satisfy the de- virgin flow) have been measured more accu- mands of all users. At present, there is plenty rately since 1930, and the 1930-70 average is of surplus water for a very large oil shale in- considered a better estimate. The effects of dustry, but the surplus is shrinking because flow fluctuations around the 13.8 million of population growth (both in the Upper Basin acre-ft/yr average are discussed in the issues and in the urban areas to which its waters section. are exported), accelerated mineral resource development, increases in irrigated agriculture, and expansions of other activities. Law of the River In the future, there may not be enough It is assumed that the allocation to the Up- water for oil shale unless the demands of per Basin is determined by the operating criteria promulgated for CRSP reservoirs by the New Mexico Interstate Stream Commission, Department of the Interior (DOI). These cri- the Utah Division of Water Resources, the teria require a minimum discharge of 8.23 Wyoming State Engineer’s Office, the U.S. million acre-ft/yr from the Lake Powell Reser- Soil Conservation Service, the Department of voir into the lower Colorado River. This in- Commerce, DOE’s Denver Project Office, the corporates the Lower Basin’s allocation Region VIII Office of the Department of Hous- under the Colorado River Compact of 1922 ing and Urban Development, USBR, and EPA. (7.5 million acre-ft/yr), plus one-half of the Technical assistance and studies were pro- Mexican treaty obligation (750,000 acre-ft/ vided by USBR (hydrologic modeling), the U.S. yr), less the contribution of the Paria River Fish and Wildlife Service (USFWS) (fishery (20,000 acre-ft/yr), which discharges into the and recreational impacts), the U.S. Heritage Colorado River between Lake Powell and Lee Conservation and Recreation Service (recrea- Ferry. The Upper Basin States do not agree tional data), Los Alamos Scientific Labora- with these criteria. The effects of other inter- tory (economic modeling), the U.S. Soil Con- pretations of the law of the river are dis- servation Service (agricultural water con- cussed in the issues section. sumption and conservation), the U.S. Geologi- cal Survey (USGS) (water quality), and sev- It is also assumed that flows allocated to eral private contractors. the Upper Basin are distributed according to the Upper Colorado River Basin Compact of Because of this broad support and review 1948. As indicated previously, this compact allocated 50,000 acre-ft/yr to Arizona and, of base, DNR’s estimates of present and future water depletions appear to be the best avail- the remainder, 51.75 percent to Colorado, 23 able for the period between 1980 and 2000. percent to Utah, 14 percent to Wyoming, and 11.25 percent to New Mexico, OTA has relied on the values provided for “conventional’” (nonoil shale) depletions to define the baseline water-demand conditions Demands of Other Users under which the oil shale industry could be Section 13(a) of the Federal Nonnuclear established. DNR”s results have also been Energy Research and Development Act of used to evaluate water-supply options in the 1974 directed the U.S. Water Resources areas in which oil shale development is most Council to assess the water requirements of likely to occur. emerging energy technologies and the availability of water for their commercialization. DNR projected water consumption pat- Studies were to be undertaken at the request terns for conventional activities in 2000 of the Energy Research and Development Ad- based on low, medium, and high regional ministration (ERDA), In 1977, ERDA re- growth rates. The medium-growth scenario, quested three such “l3(a)” assessments, one which was based on declared plans by the directed to the water-resource aspects of oil various users for expanding their water shale development and coal gasification in needs, is considered by the States to be the the Upper Basin. Oversight for these projects most realistic. The high growth rate scenario was transferred to the Department of Energy was derived from the medium scenario by as- (DOE) in 1978. suming that announced projects would be finished sooner than expected or would con- The Upper Basin 13(a) assessment was or- sume more water than anticipated. A few ganized under the management of DNR of the projects not considered in the medium-growth State of Colorado. DNR’s work has been re- scenario are included in the high-growth sce- viewed by an interagency, intergovernmental nario. The low-growth scenario was derived steering committee that includes represent- by assuming project delays or lower than an- atives of the Arizona Water Commission, the ticipated water consumption. In this section, Colorado Water Conservation Board, the OTA considered only the medium growth 382 ● An Assessment of 011 Shale Technologies

rate. The low and high rates are considered The Availability of Surface Water in the in the issues section. Upper Colorado River Basin

Oil Shale Technologies Water Consumed by Conventional Activities It is assumed that the technology mix used At present, the following activities con- by any future industry will resemble that of sume surface water in the Upper Basin:. the projects presently active or proposed. The ● characteristics of this industry were de- thermal power— for steam-electric pow- scribed in table 76. About 51 percent of the er generation; ● for irrigation, watering facilities use indirectly heated AGR, 33 per- agriculture— cent directly heated AGR and MIS, and 16 stock, and other agricultural purposes; ● wildlife and recreation—for mainte- percent a combination of MIS and indirectly nance of fish, wildlife, and recreational heated AGR. On this basis, each plant would areas; require about 8,500 acre-ft/yr for production ● of 50,000 bbl/d of shale oil syncrude. The ef- minerals—for extraction, processing, and transporting ores and concentrates; fects of other technology mixes are discussed ● in the issues section. municipal and industrial—for domestic, commercial, retail, and manufacturing facilities, including final processing of Distribution of Facilities raw materials into finished products; If the siting pattern of the present projects and were extended to a major industry, 68 per- ● exportation— for diversion and trans- cent of the production would be based in Col- portation to other basins or to other orado, 32 percent in Utah, and none in Wyom- areas within the Upper Colorado River ing, Although they are of lower quality, some Basin. development of Wyoming shales may occur if Water consumption patterns for these ac- a major industry is established. Therefore, it tivities, at present and as projected to 2,000, was assumed that approximately 5 percent of are shown in table 78. Agriculture presently future production will come from Wyoming, depletes nearly 71 percent of the total, water about 70 percent from Colorado, and about exports are the second highest category at 24 25 percent from Utah. This assumption deter- percent, and the remaining 5 percent is dis- mines which hydrologic subbasins will be im- tributed fairly evenly among the other uses. A pacted. It also determines how much of the comparison with the year 2000 projections in- production could be sustained by the exten- dicates shifts both in the absolute quantities sive ground water resources of the Piceance of water consumed and in the distribution of Basin. In this section, it is assumed that all of consumption among the various activities. the plants rely on surplus surface water. The The following trends are indicated: possible substitution of ground water is discussed in the issues section. ● Agricultural water consumption is projected to increase by 19 percent. How- Timing and Lifetime of the Projects ever, agriculture’s share of total consumption is projected to decrease to 61 It is assumed that the facilities will be in- percent from its present level of 71 per- stalled before 2000, regardless of the indus- cent. try’s size. As discussed in the other chapters, ● Thermal power’s water consumption is establishing a large industry this quickly may projected to increase by a factor of 6. be difficult. ● Exportation of water is projected to in- Ch. 9-Water Availability • 383

Photo credits. OrA staff Feed for livestock consumes large amounts of the available water —— —..

384 An Assessment of Oil Shale Technologies

Table 78.–Present and Projected Water Depletions for Activities Other Than Oil Shale Development in Colorado, Utah, and Wyoming (thousand acre-ft/yr)

Present Year 2000 Colorado Utah Wyoming Total Percent Colorado Utah Wyoming Total Percent Thermal power. 10 7 18 35 1,2 74 64 83 221 5,7 Agriculture 1,197 527 279 2,003 70.7 1,380 671 330 2,381 61.3 Wildlife and recreation 15 9 6 30 1,1 28 9 20 57 1,5 Minerals ., 19 12 21 52 1.8 33 12 64 109 2.8 Municipal and industrial 21 10 4 35 1,2 49 19 8 76 2.0 Exportation 541 132 7 680 24,0 757 262 22 1,041 26.7 Total 1,803 697 335 2,835 100.0 2,321 1,037 527 3,885 100,0

SOURCE Colorado Oepariment of Natural Resources, Upper Co/orado Rwer Regmn See//on 13 (a) Assessmen/ A Report (O (he U S Wa/er Resources CouncI/ drafl August 1979

crease by 53 percent. The proportion of surplus were reserved for oil shale develop- total depletions exported, however, will ment, an industry of about 9.76 million bbl/d remain at about 25 percent. could be accommodated. The projected sur- ● At present, the oil shale States together plus in 2000 would support a 2.76-million- consume about 2.84 million acre-ft/yr. bbl/d industry without disrupting other users. The total depletion would increase 37 A more precise analysis, which considered percent to 3.89 million acre-ft/yr. seasonal flow fluctuations, return flows from These trends are considered below in con- irrigated fields, effects of fill rates, and sus- junction with law of the river allocations to tained depletions on reservoir evaporation, estimate the quantities of surplus water that was performed for DNR with USBR’s Colora- would be available to support additional re- do River system simulation model. The model gional growth. predicted a natural discharge from Lake Powell of 8.63 million acre-ft/yr in 2000 Estimation of Surplus Water in the —400,000 acre-ft/yr more than the minimum Upper Basin discharge requirement, but 69,000 acre-ft/yr less than the year 2000 surplus shown in Surplus water is defined as the difference table 79. The surplus would support an oil between the water allocated and the total shale industry of 2.35 million bbl/d in the Up- water consumption, which includes water per Basin. However, the industry’s total caused for beneficial purposes plus reservoir pacity would be further reduced by the Upper evaporative charges. * As discussed previous- Colorado River Basin Compact of 1948 that ly (see table 77), the oil shale States should be governs how water can be distributed among entitled to a total of 4.94 million acre-ft/yr: the individual States in the Upper Basin. The 2.88 million to Colorado, 1.28 million to Utah, effects of this compact are indicated in table and 0.78 million to Wyoming. In table 79, esti- 80, where the 400,000-acre-ft/yr surplus is mates are given for the quantities of surplus distributed among Colorado, Utah, Wyoming, surface water at present and in 2000. At and New Mexico according to the compact’s present, approximately 1.66 million acre- percentage formula. As shown, the total ft/yr of surplus water is available. By 2000 shale oil capacity would be 2.09 million bbl/d: the surplus would be reduced to about 1.22 million in Colorado; 541,000 in Utah; and 469,000 acre-ft/yr. These surpluses are legal- 320,000 in Wyoming. ly available to the States. If all the present It is important to note that these calcula- *The term “reservoir evaporative charges” refers to the tions apply to average flow conditions in the total amount of water that evaporates from certain reservoirs Colorado River system. During dry years, nat- in the Upper Basin, The States are charged on a percentage ural flows out of Lake Powell might not be suf- basis for losses from reservoirs that are built to serve the entire Upper Basin. Evaporation from reservoirs built for a spe- ficient to satisfy the delivery requirement to cific State are charged entirely to that State. the Lower Basin and might have to be aug- Ch 9–Water Availability ● 385

Table 79.–Estimation of Surplus Surface Water in Colorado, Utah, and Wyoming at Present and in 2000 (thousand acre-ft/yr) —— Present Year 2000 Colorado Utah Wyoming Total Colorado Utah Wyoming Total Total water usea 1,803 697 335 2,835 2.321 1,037 527 3,885 Evaporation ” 259 115 70 444 334 148 104 586 Total consumption 2,062 812 405 3,279 2,655 1.185 631 4,471 Allocatlonc 2,880 1,280 780 4,940 2,880 1,280 780 4,940 Surplus. 818 468 375 1,661 225 95 149 469 aDala from table 78 bE~~lmated ~harge~ for CRSp ,e~er,,olr~ pre~enI ,alue~ ~roilded by R~la”d Fls~her (jjorado River waler Conserval, on Dlslrlc[ year 2000 estlmales by [he Colorado Depa’lmeot of N?lucd Resources cAssumes 13 8 milllon acre-ft yr vl~gln flow al Lee Ferry 8 23 mlll~on acre If yr Lake Powell discharge cllslrlbutlon of flows and evaporative charges per the oerceltage (am) ula of !he Uoper Colorado Rwer Basin Compact of 1948 SOURCE Otffce 01 Technology Assessment

Table 80.–Maximum Shale Oil Production interpretation of the law of the river, one set a Based on Surplus Surface Water in 2000 of depletion estimates for conventional users Assumed virgin flow at Lee Ferry, million acre-ft/yrb 138 in 2000, one assumed value of virgin flow, Surplus surface water available, acre-ft/yrC and an industry that employs a technology New Mexico 45 000 1 mix similar to that being developed in the Colorado 207,000 Utah 92,000 present projects. If a different basis were se- Wyoming 56,000 lected, the estimated capacity of the industry Total 400,000 could be significantly different. Some other Shale 011 capacity, million bbl/dd bases are discussed in the issues section of Colorado 1 22 Utah 054 this chapter. Wyoming 033 The conclusion also does not account for Total 209 —— regional and local supply impediments that aAs~umes 823 mllllon acre If yr annual U(scharqe ~rom Ldke Powe!l D[sfrlbutlon among the UP could affect facility siting and thereby deter- per Basin Slates according 10 Ihe Upoer Coloraco Rwer Basin Compact of 1948 b1930 74 annual average mine the ultimate size of the industry. The c Based on year 2000 deplello~ orojectlons for nono{l shale users Medium growfh rate scenario next section evaluates water availability with dBa~ed o 8 soo acre ft ~ yr for production 0150000 bbl d Of shale 011 syncrude n respect to specific development sites within SOURCE Olflce ot Technology Assessment specific hydrologic basins in the oil shale area. mented by discharge from the Upper Basin reservoirs. As noted earlier, these were built to allow the Upper Basin States to satisfy Water Availability in Hydrologic Basins their delivery requirements to the Lower Basin. Their active capacity is expected to be Affected by Oil Shale Development about 35 million acre-ft in 2000. If virgin Oil shale development is likely to affect flows dropped to say, 12.9 million acre-ft/yr three hydrologic subbasins: - and stayed there, * the reservoirs could offset the 0.9-million-acre-ft/yr shortfall for only ● the Green River basin in the southwest- about 39 years. ern corner of Wyoming, which includes the northern mainstem of the Green In summary, surplus surface water legally River and its tributaries; available to the oil shale States could support ● the White River basin, which encom- a shale industry of about 2.1 million bbl/d passes the northern portion of the Pi- through 2000. This conclusion is based on one ceance basin and the eastern portion of the Uinta basin, and whose tributaries *’I’his []ppears to be the lower limit for long-term virgin flows in the Colorado River system. See the issues section of this include the White and Yampa Rivers to chapter. their confluence with the Green River in 386 ● An Assessment of Oil Shale Technologies

eastern Utah, plus streams flowing north The Adequacy of Surface Water Resources out of the Piceance basin into these by Hydrologic Basin rivers; and In the Green River basin, water depletions ● the Colorado River mainstem basin, for a l-million-bbl/d oil shale industry would which includes the Colorado River main- be approximately 8,500 acre-ft/yr. Two major stem in Colorado, streams that flow Federal reservoirs within this basin, Flaming south from the Piceance basin into the Gorge and Fontenelle, have well over 100,000 Colorado, and upstream tributaries at acre-ft/yr of surplus water in storage that is higher elevations. available for sale to industrial users such as oil shale developers. Consequently, there is The impacts on these subbasins can be esti- more than enough water available within the mated only after certain assumptions are basin to provide for projected growth. It is un- made regarding the locations of the oil shale likely that any new reservoirs will be needed. plants and the timing of their construction. If the trend indicated by the present oil shale Oil shale development would have a great- projects were continued, about 40 percent of er effect on the White River basin. With a 1- the shale oil production would come from the million-bbl/d industry, depletions would ap- White River basin in Colorado, 30 percent proach 200,000 acre-ft/yr by 2000. About 60 from the Utah portion of that basin, and 25 percent would be used for oil shale. These de- percent from the basin of the Colorado River pletions would strain the water resources of mainstem in Colorado. The remaining 5 per- the White River because its total annual flow cent might come from as-yet unannounced at the boundary of the basin is only about projects in Wyoming’s Green River basin. The 568,000 acre-ft/yr, 61 percent of which oc- water requirements for a l-million-bbl/d in- curs between April and July. Although sever- dustry distributed in this manner are indi- al oil shale plants could be supplied from ex- cated in table 81. Also shown are the water isting resources, new reservoirs would be requirements for conventional uses in 2000, needed and river flows would be substantial- as projected by DNR under its medium ly reduced. growth rate scenario. As shown, the industry would increase the total water consumption According to DNR, only about 6,000 acre- in the three subbasins by about 10 percent. ft/yr could be obtained from streams within The increases in the Green River and Colora- the Piceance basin because of their low do mainstem basins would be relatively small, streamflows. A l-million-bbl/d industry would but water demands in the White River basin require an additional direct-flow diversion of would increase by nearly 150 percent. 4,500 acre-ft/yr from the White River below

Table 81 .–Water Requirements by Hydrologic Subbasin for a 1-Million-bbl/d Industry in 2000

Water for conventional Oil shale industry Increase due to Subbasin uses, acre-ft/yra Oil capacity bbl/d Water acre-ft/yrb Total water acre-ft/yr 011 shale, percent White River, Colo. and Utah 80,000 700,000 119,000 199,000 149 Colorado mainstem, Colo. . 1,220,000 250,000 42,500 1,262,500 35 Green River, Wyo. 482,000 50,000 8,500 490,500 18 Total. ., 1,782,000 1,000,000 170,000 1,952,000 9.5 aconventlonal “~e~ ,flclude th~r~a[ power agriculture Wlldllfe and recreallon, minerals muruclpal and (ndus(nal and exporfs Eshmates for the Colorado Depafiment of Nafural Resources medium 9rowfh rate scenario bBased on 8 5i30 acre. ft/yr for producflon of 50000 bblid Of shale 011 Swcrude SOURCE Off Ice of Technology Assessment Ch. 9–Water Availability ● 387

Meeker, a reservoir with an active capacity acre-ft would be needed. The third scheme in- of 60,000 acre-ft on the south fork of the volves direct flow diversions from the Colo- White River in Colorado, and a 120,000-acre- rado River below Rifle, in conjunction with ft reservoir on the White River mainstem in reservoirs on the Colorado mainstem or in Utah. An industry of more than 2 million bbl/d side canyons in the Piceance basin. A l-mil- would require these facilities plus a 35,000- lion-bbl/d industry could be supplied with a acre-ft reservoir on the White River main- 30,000-acre-ft/yr diversion and a 15,000- stem between Meeker and Piceance Creek, a acre-ft reservoir. The reservoir could be lo- total of 35,000 acre-ft of active capacity in cated in a dry canyon because it would be several smaller reservoirs along ephemeral supplied with pumped water from the Colora- streams in the Piceance basin, and a reser- do mainstem and would not rely on local voir of about 10,000 acre-ft/yr along Piceance stream flows. Creek. All reservoirs would store spring runoff. Water from the White River would be In the fourth scheme, 50,000 acre-ft/yr of pumped to the reservoirs in the Piceance ba- surplus water would be purchased from ex- sin during the rest of the year. isting USBR reservoirs (such as Reudi Reser- Within the Colorado mainstem basin, oil voir) and pumped to the oil shale facilities. shale development would increase water de- This would supply all of the water required pletions only slightly. However, large water for that portion of a l-million-bbl/d industry demands would be imposed by the growth projected for the Colorado mainstem basin. rates projected for other uses, especially irri- Larger levels of production could be sup- gated agriculture. Reservoirs may be needed ported by any of the other three schemes, to supply both irrigation and oil shale devel- with reduced storage and diversion require- opment. DNR considered four siting schemes ments. for reservoirs in this basin. In summary, new storage requirements for In the first scheme, reservoirs would be a l-million-bbl/d industry could range from built at high elevations along tributaries like 180,000 acre-ft, with reservoirs in the White the Roaring Fork and Eagle Rivers. Spring- River basin and no storage in the Colorado time runoff would be trapped for release over mainstem basin, to about 230,000 acre-ft for the dry months. The released water would be storage in both basins. The maximum storage recovered from the Colorado River below Ri- requirements would be encountered if high- fle and pumped to the oil shale plants. The altitude reservoirs were built. Less storage only appreciable inflows to the reservoirs would be needed if most water was obtained would occur in the spring and large active ca- by direct diversions from the mainstem riv- pacities would be needed to sustain outflows ers. The additional reservoirs would increase during the dry seasons. Total capacities reservoir capacity in the Upper Basin by might exceed 50,000 acre-ft for a l-million- about 0.6 percent. Evaporative losses from bbl/d industry. the new reservoirs should also be charged The second scheme also involves reservoirs against the industry. Their precise magnitude on upstream tributaries but at lower eleva- would depend on the characteristics of the tions to permit capture of agricultural return new reservoirs and their sites, but should add flows and of water from secondary streams. only a small percentage to each shale plant’s A total storage capacity of 30,000 to 50,000 annual water requirements. 388 An Assessment of Oil Shale Technologies

Water Acquisition Strategies and Their Costs

The following strategies could be used by some potential developers at that time are either alone or in combination to suppl.- v. tabulated below: water to oil shale facilities: Developer Storage rights, acre-ft ● perfection of conditional water right decrees, EXXON , ... , ...... 122,000 Mobil ... , ...... , , 66,000 ● purchase of surplus water from Federal Getty Oil. ., ...... 53,000 reservoirs, Sinclair...... , 51,500 ● purchase of water supplies and water Tosco . . . , .. 0.., ., . . . . 34,600 rights from irrigated agriculture, Total, ... , ...... 327,100 ground water development, and . interbasin diversions. These companies also owned conditional decrees to over 1 million acre-ft/yr of direct- A brief discussion of each strategy and its flow diversions from the Colorado and White associated costs follows. Constraints and im- Rivers and their tributaries. Substantial pacts are discussed later. rights were also held for ground water. Supe- rior Oil, for example, held conditional de- Perfection of Developer Water Rights crees to over 2,400 acre-ft/yr of ground water in the Piceance basin. Description Most potential oil shale developers have al- The rights of the limited sampling of com- ready acquired water rights. Some were ob- panies shown above could support an indus- tained by direct filings through the prior ap- try of nearly 8 million bbl/d and would be suf- propriation system. These are now in the ficient for the shale oil production levels pro- form of conditional decrees both for storage jected for the near term. and for direct-flow diversions. Exact yields are not available because they are consid- Developers who do not presently own ered proprietary information by the compa- rights could file for new ones. In general, this nies. The rights are believed to be large but option is considered undesirable because the relatively junior. The oldest was acquired in quantity of water covered by rights issued to 1949. date already exceeds the resources of the river system. Any new rights would be junior Other rights were purchased from irri- to those of all other users and therefore the gated agriculture. Most of these are relative- most likely for curtailment during water ly senior absolute rights that were perfected shortages. by the seller. To avoid a declaration of abandonment, some developers have allowed the Filing for new rights might be feasible for sellers to continue to use the water for farm- near-term development, however, because of ing. Little information is available regarding the improbability that all of the water cov- the potential yields of these rights. However, ered by present conditional decrees will be total historic consumption, which would de- put to use for several decades. The long-term termine the quantities of water that could be feasibility of this strategy is highly uncertain transferred to oil shale development, could be 28 because supply curtailments will become as low as 10,000 to 20,000 acre-ft/yr. more likely as regional growth proceeds. To An idea of the extent of developers rights assure supplies in the long term, new filings can be gotten by examining their water posi- would have to be merged with other strate- tions in 1968.29 Conditional storage rights held gies. Ch 9–Water Availability ● 389 costs storage is adequate for initial development. For example, Green Mountain and Reudi Res- The costs of acquiring these kinds of rights ervoirs in the Colorado mainstem basin could are negligible, comprising only legal fees for supply about 100,000 acre-ft of surplus recording the water claim, and for pursuing water, which would be sufficient for nearly any resultant litigation, and small annual in- 600,000 bbl/d of shale oil production. How- vestments to demonstrate due diligence. The ever, existing reservoirs could not support a costs incurred by developers when they pur- larger industry unless other users were par- chased their current irrigation rights are tially curtailed. Therefore, new reservoirs unknown but were probably small. There- would have to be built. New pipelines would fore, the costs of water supplies obtained also be needed in all three basins to divert through the prior appropriation system com- water to the oil shale plants. prise only the costs of transporting the water from the diversion point to the oil shale site, Transportation costs are discussed later with respect to intrabasin diversions. costs Reservoir construction costs are highly Purchase of Surplus Water From site-specific and are reflected in the charges Federal Reservoirs for purchased water. These charges vary widely from reservoir to reservoir. Although Description charges for existing reservoirs are known, only rough estimates are available for new Oil shale developers could also purchase reservoirs, surplus water from reservoirs operated by USBR and other entities. Various amounts of Some examples of long-term contracts for water are presently available from existing water from existing USBR reservoirs are reservoirs in the oil shale area. As noted shown in table 82. As shown, charges in the previously, the Flaming Gorge and Fontenelle late 1960’s were from $7 to $11/acre-ft while Reservoirs in the Green River basin have suf- previous charges were less than $1/acre-ft. ficient surplus water for much more shale oil The highest charge, $22.54/acre-ft in 1972, is production than is likely to occur in the basin for a small diversion from the Emery County in the near term. This water is not being used reservoir. Because future contracts will be for any purpose and could be made available negotiated individually, water costs cannot to oil shale developers. be accurately predicted, although it seems In the basins of the White River and the unlikely that they would be much higher than Colorado River mainstem, surplus water in $25/acre-ft.

Table 82.–Examples of the Charges for Purchasing Surplus Surface Water From U.S. Bureau of Reclamation Reservoirs

Year of Quantity of Unit cost, Project/reservoir River basin Purchaser contract diversion, acre-ft/yr $/acre-ft Seedskadee/Fontenelle Green State of Wyoming 1962 60,000 $0.40 Seedskadee/Fontenelle Green State of Wyoming 1974 60,000 500 Emery County Central Utah Utah Power & Light and others 1972 6,000 2254 Glen Canyon/Lake Powell Colorado Resources Co and others 1969 102,000 7.00 Glen Canyon/Lake Powell Colorado Salt River project 1969 40,000 7.00 Navajo San Juan New Mexico Public Service 1968 20,200 700 Navajo San Juan Utah International 1968 44,000 700 Navajo San Juan Southern Union Gas Co. 1968 7.00 Missouri River/Bighorn and Boysen Yellowstone Various 1967-71 658.000; 11,00 Boulder Canyon/Lake Mead Lower Colorado Colorado River Commission 1966 30,000 050

SOURCE R F Probsleln H Gold and R E Hicks Wa(er Requ/remenfs Po/Iu/Ion Effecfs and Costs O( Wafer Supply arm Treamefl( for [he (7II Sha/e Indusky eporl prepared for OTA by Water Punflcallon Associates October 1979 —. ——

390 ● An Assessment of Oil Shale Technologies

Some cost estimates for new reservoirs in The feasibility of using irrigation rights for Western Colorado are summarized in table oil shale development is site specific and 83. Unit construction costs in 1979 dollars depends on their cost in comparison with vary from $120 to $740/acre-ft of storage other strategies, the proximity of irrigation capacity. To obtain estimates of water costs diversions to potential plantsites, and the from these reservoirs, assumptions must be seasonal nature of irrigation rights. Transfer made about financing methods and operating is unlikely in the Green River basin, for exam- characteristics of the reservoirs. A rough ple, because adequate and inexpensive water estimate can be made if it is assumed that appears to be available from existing Federal storage and delivery capacities are equal, reservoirs. On the other hand, it could occur and 10 percent of construction costs are in the White River and the Colorado main- charged to water purchasers per year. Then stem basins because of the limitations of ex- the charges for the water would range from isting storage capacity. about $10 to about $75/acre-ft, which is substantially higher than costs from existing res- In the White River basin, irrigated agricul- ervoirs. ture consumes about 37,000 acre-ft/yr, This amount of water could supply a 250,000-bbl/d oil shale industry. If this water were trans- Table 83.–Estimated Construction Costs for Proposed ferred to oil shale, additional storage would Reservoirs Within the Colorado River Water Conservation District probably be needed because of the seasonal nature of irrigation rights. These rights Storage Unit capital capacity, Construction costs, generally rely on direct diversions from a acre-ft costs, million$ $/acre-ft river, and river flows might not be sufficient Haypark ,, 20,000 $60 $300 during dry seasons to satisfy the oil shale Azure 30,000 11.4 380 water requirement. Toponas, .,...,.. ,, 18,000 3,3 180 Iron Mountain, 60,000 289 480 Yoeman Park . ~ ~ ~ ~ 7,000 49 740 In the basin of the Colorado River main- Bear Wallow. . 49,000 11.9 240 stem, irrigated agriculture currently con- Kendig, ., ., . ., ~ 15,000 5.0 320 sumes about 430,000 acre-ft/yr, which is Una...... 196,000 363 190 Yamcolo ,,. ,. 9,000 5.8 640 much more than would be required for any Bear, .., ,,. . 12,000 30 260 projected level of oil shale development. Pur- Grouse Mountain. 79,000 9.2 120 chase of irrigation rights would reduce, but Rampart. . 12,000 4.0 350 California Park 37,000 52 140 probably not eliminate, the need for new stor- Rangely ..,, .,, , 55,000 112 200 age capacity. Irrigation water from the Col- Dunkley. . . . . 57,000 13,2 230 orado mainstem could also be diverted to oil Pothook .,, 60,000 85 140 shale facilities in the White River basin, thus SOURCE R F Probslem H Gold and R E H!cks Wafer Reqwremenfs pollution Effecfs, and reducing the need for new storage in that Cos/s of Wafer Supp/y and Trearmerr/ for (he 0// .Sha/e /rrdus/ry report prepared for OTA by Water Purlhcatlon Associates October t979 basin. Some new interim storage would be needed near the plantsites. In any case, new pipelines would be needed to transport water Purchase of Irrigation Rights from current diversion points to the oil shale facilities. Description costs Most oil shale developers have indicated that they plan no further purchases of irriga- It is important to distinguish between the tion rights. However, the strategy warrants purchase of a specific quantity of water for discussion because large quantities of water use in a given year and the purchase of a are currently consumed by farming and the water right that would authorize use in all water laws allow rights to be transferred future years. In recent years, the cost in Col- from willing sellers to willing buyers. orado of purchasing irrigation water for one . Ch. 9–Water Availability ● 391 year’s use has ranged from about $10 to er pretreatment, much of it could be up- $25/acre-ft, which is similar to the costs of graded for such use. If this were done to the purchasing water from existing Federal res- fullest extent, the aquifers could supply a 1- ervoirs. 30 The cost of purchasing a water million-bbl/d shale oil industry for from 200 to right for use in perpetuity, however, could 500 years, depending on the processing tech- range from $1,000 to $2,500 for each acre- nologies used. ft/yr covered by the right.31 If capital to purchase the right were borrowed at lo-percent Less is known about ground water in the interest, annual costs might range from $100 White River basin in Colorado and Utah and to $250/acre-ft. These costs are substantially about Utah’s water resources in general. It is higher than current prices for single-year known that the Uinta basin contains large ar- diversions. The reason is that most farming tesian aquifers, one of which discharges in could not be conducted without irrigation. the vicinity of Federal lease tracts U-a and Selling water rights essentially puts a farmer U-b. The water is not potable but could be out of business. treated for use in oil shale processing. Because bedrock aquifers in the Piceance Ground Water Development and Uinta basins often coincide with minable oil shale zones, ground water will be an im- Description portant consideration in most development plans. Even if ground water is not intentional- Ground water aquifers could be feasible ly developed for use as process water, it will water sources for oil shale development if be produced on most tracts during mine de- they are favorably located relative to plant- watering and the preparation of in situ re- sites, if the water quality is suitable for in- torts. In many locations, the water could sat- dustrial applications, and if physical char- isfy all processing needs, In some areas, an acteristics (such as burial depth, storage excess will be produced that will have to be volume, and discharge rates) are advanta- disposed of through evaporation, by reinjec- geous. Although knowledge is incomplete, ex- tion, or by discharge to surface streams. Puri- isting data suggest that selected aquifers in fying excess ground water to discharge the Upper Basin are worthy of consideration standards could be costly. for some, if not all, potential oil shale facilities. In the Piceance and Uinta basins, yields from test wells vary with location from less In the Piceance basin, for example, up to than 1,000 to over 4,000 acre-ft/yr. Two to 25 million acre-ft is estimated to be stored in four of these wells would be sufficient to sat- two major bedrock aquifers that are sepa- isfy the needs of an oil shale plant producing rated by rich oil shale beds. This resource is 50,000 bbl/d by directly heated AGR. Several currently being used in limited amounts for additional wells would probably be drilled to livestock watering, for irrigated agriculture, provide backup capacity. and for localized domestic consumption. The water is generally high in dissolved solids and costs fluoride. For this reason, its use for conventional purposes will probably not increase. It The cost of ground water development will is likely that an oil shale industry would be vary with site, with water quality, and with the only large-scale application for which this the water management program of the devel- ground water would be suitable. * With prop- oper. In a recent study the geohydrologic *W~ter in the upper aquifer generally contains less than characteristics of three wellsites in the 2,000 mg/1 of dissolved solids, while in the lower aquifer these Piceance basin were analyzed, and estimates may range from 1,000 to 63,000 mg/1. The fluoride content is were prepared of drilling capital and pump- typically from 10 to 70 mg/1. Federal drinking water standards 32 recommend a dissolved solids limit of 500 mg/1 and a fluoride ing costs. For two of the sites, which had content of !ess than 1.0 mgll. prolific water-bearing zones extending to .—.—

392 ● An Assessment of 011 Shale Technologies about 1,000 ft below the surface, a minimum Interbasin Diversions cost of about $30/acre-ft was estimated for delivery of 1,500 to 4,000 acre-ft/yr. The third Description site contained much less permeable rocks, which reduced maximum flows and thus in- Interbasin diversions move water from one creased costs. The estimate of the maximum major hydrologic basin to another. Exports flow from this well was 700 to 900 acre-ft/yr, from the Upper Basin to the cities of Col- with a minimum cost of about $90/acre-ft. In orado’s Front Range Urban Corridor (Denver, the DNR study, water costs from a well yield- Colorado Springs, etc. ) are examples of inter- ing 3,000 acre-ft/yr from a depth of 500 ft basin diversions. Diversions could also be were estimated to be $22 to $30/acre-ft. 33 used in the future to increase overall water Another estimate is about $55/acre-ft for a availability in the Upper Basin by relocating l,000-ft well yielding 1,500 acre-ft/yr. 34 water from other major basins such as the Columbia River Basin or the Upper Missouri The costs of well drilling and pumping River basin. * As an illustration, diverting 1 could, therefore, range from $20 to $60/acre- percent of the net water supply of the State of ft, assuming that aquifers occur at reason- Washington in the Columbia River Basin able depths and in reasonably permeable for- would provide 2 million acre-ft/yr of addi- mations. These costs are comparable to those tional water to the oil shale area, an amount for surface water. Ground water could offer equal to two-thirds of the present water con- a major economic advantage in that wells sumption in all of the Upper Basin States. could be located near the oil shale facilities, thus avoiding transportation costs. On the costs other hand, the poor quality of some ground water would necessitate costly purification. Costs of interbasin diversions vary with pipeline construction and pumping costs, Water from some aquifers is highly saline which in turn depend on the route, diameter, or brackish. It would not need to be purified and length of the pipelines; on the number for use in dust control and spent shale com- and capacity of pumping substations; and on paction, but would have to be for use as boiler the cost of purchased power for the pumps. feedwater or cooling water. Purification can These costs are highly project-specific, but, in be quite costly. For example, treating brack- general, decrease with pipeline throughput ish water to cooling water standards can cost 35 and increase with distance. Variations in unit from $200 to $300/acre-ft, and treatment to costs can be illustrated by considering two boiler feedwater standards can cost from 36 alternate pipelines; one providing water to a $650 to $ 1,000/acre-ft. These high treatment single oil shale plant and the other supplying costs would not be needed for all of a plant’s water to an entire industry. An oil shale plant water supply, because some requirements producing 50,000 bbl/d by directly heated could be satisfied with water of any quality. surface retorting would consume about 6,000 If the overall water management plan of an acre-ft/yr of water. This quantity could be AGR facility is considered, a brackish ground transported to the site in an 18-inch-diameter water supply would add about $250 to $530/ pipe at a unit cost of about $12/acre-f t/mile. acre-ft to the costs of water acquisition. In comparison, about 240,000 acre-ft could be Thus, the overall costs of ground water de- conveyed through a 90-inch-diameter pipeline velopment and use could range from $20 to at a unit cost of $1 .90/acre-ft/mile.37 $600/acre-ft/yr. The lower estimate corre- *Under the CRP Act, the Secretary of the Interior was re- sponds to a high-quality ground water from quired not to undertake reconnaissance studies of any plan for permeable rocks at reasonable depths. The the importation of water into the Colorado River Basin until 1978. The Reclamation Safety of Dams Act of 1978 extended higher estimate corresponds to brackish wa- this moratorium until Nov. 2, 1988. Thus. no water imports ter from relatively impermeable formations. from other major basins will be allowed until well after 1988, CH. 9–Water Availability ● 393

Four options illustrate typical distances of the water to obtain the overall cost of and costs that might be encountered with in- developing a given water supply. terbasin diversion for a large oil shale in- Intrabasin diversions redistribute water dustry. One option would be to bring water to within a major hydrologic basin such as the the White River basin from the Oahe Reser- voir on the mainstem of the Missouri River in Upper Basin, They include transfers between individual subbasins such as the basins of the South Dakota. The distance would be 500 to Green River, the Colorado River mainstem, 600 miles, and the unit costs would be $950 to and the White River. Intrabasin diversions $1,150/acre-ft. A second alternative would be are not an acquisition strategy, but are a to transport water from the Missouri River at method for relocating acquired water to oil Kansas City to the John Redmond Reservoir in Kansas, then to Denver, and finally over the shale plants. Except for selected tracts using 38 ground water and for the few oil shale plants Rocky Mountains to the White River basin. built very close to major tributaries, new in- The pipeline would be about 700 miles long, trabasin diversions will be needed. and the unit transportation cost about $1,130/acre-ft. A third option would be to Intrabasin diversions would not reduce the transport water about 800 miles from the Co- strain on the resources of the Colorado River lumbia River Basin to the White River basin. system. They would simply redistribute water Unit costs would be about $1,520/acre-ft. A among individual subbasins. They could be fourth possibility would be to divert water to used, for example, to augment the sparse nat- the White River area from the Yellowstone ural flows of the White River with surplus River, a distance of approximately 400 miles, surface water from the Colorado River main- This would cost about $750/acre-ft, stem. They could also be used to transport stored surplus water from Federal reservoirs In summary, interbasin transfers for a in the Green River basin to developments large industry would require 400- to 800-mile- along the White River or the Colorado River long pipelines and would entail unit costs of mainstem. Such diversions would be required $750 to $1,500/acre-ft. Exact costs vary wide- regardless of whether the oil shale water sup- ly but are, in general, quite high. To these plies are obtained from new or from existing costs must be added the purchase price of the reservoirs, water that is moved through the pipeline. costs Intrabasin Diversions The costs of transporting water by an in- Description trabasin diversion pipeline will depend on the fees charged by the supplying reservoir and The total cost of a water supply includes the costs of building and operating the pipe- the cost of acquiring the water and the cost of line between the reservoir and the plantsite. moving it to the oil shale facility. As indicated Some USBR estimates of the unit costs of se- above, transportation costs can outweigh ac- lected intrabasin diversion projects are sum- quisition costs if the facility is far from the marized in table 84. Reservoir charges and water source. The costs of transporting operating costs for the pipeline are esti- water acquired in the oil shale area will also mated, but not the costs of acquiring the be high, although less than for transfers from water that is moved through the pipeline, Sev- other major basins. The following discussion eral types of supply systems and flow rates describes some of the typical intrabasin di- are shown, and both existing and new reser- versions that could occur within the oil shale voirs are considered. The range of unit trans- region, and estimates the costs of moving portation costs is from $70 to $550/acre-ft. If water through such diversion systems. This the highest and lowest are excluded, the cost can then be added to the purchase price range is reduced to from $180 to $440/acre-ft. 394 ● An Assessment of 0il Shale Technologies

Table 84.–Summary of Cost Estimates for Intrabasin Diversions Within the Oil Shale Area

Unit transportation cost, Data source Type of reservoir Destination Flow volume, acre-ft/yr $/acre-ft USBRa New Tract C-a 57,000 $240-390 USBR New Tract C-b 18,000 260-280 USBR New Tracts C-a and C-b 75,000 240-440 USBR Existing Tracts C-a and C-b 75,000 310-350 USBR New Tracts U-a and U-b 8,000 280-400 USBR New Tracts U-a and U-b 36,000 70-160 USBR Existing Tracts U-a and U-b 36,000 190-230 USBR New Tracts C-a, C-b, U-a, and U-b 111,000 180 DNRb Existing Green River basin 14,000 280 30,000 260 DNR New Colorado River mainstem basin 29,000 550 84,000 400 DNR New White River basin 141,000 380 240,000 360

au s EIUreaU of lleclarnallorr ,41(er~a(iw Wafer Sources /or Pro/otype Od Shale Oeve/opmen( Salt Lake City Utah September 1974 Dcolora(fo ~pa~ment of Natural Resources Upper Co/orado t%ver L3asm Sec/(on 13(a) Assessrneru A RepOfl fO (he (/ S wafer Resources CourJc// (Oraff) August 1979 SOURCE Office of Technology Assessment

Summary of Supply Costs ● Water for interbasin diversions is purchased at a cost of $25/acre-ft. Estimates of the costs of supplying indus- ● Surface water is of good quality and trial-quality water to oil shale sites by means does not require substantial purification of the several acquisition and transportation prior to use. strategies discussed previously are summa- ● Ground water quality is variable. Only rized in table 85. The strategy costs include brackish ground water must be treated the costs of purchasing the water, of trans- prior to use. porting it from the point of acquisition to the ● All ground water is developed in the im- point of use, and of treating it for use in the mediate vicinity of the oil shale plants. facilities. The estimates are approximate. Pipelines to points of use are of insignifi- They were derived using the following as- cant length. sumptions: • Surplus water from existing reservoirs costs $25/acre-ft. Water from new reser- ● All surface water acquired in the oil voirs costs $100/acre-ft. shale region is transported over substantial distances through intrabasin pipe- The lowest cost strategy is the development lines. of good quality ground water. Unit costs

Table 85.–Summary of Approximate Water Supply Costs for Several Acquisition Strategies

Component cost, $/acre-ft Strategy costs Strategy Purchase Transportation Treatment $/acre-ft $/bbl of oila Perfection of conditional decrees ...... nil $180-440 nil $180-440 $0.09-0.23 Purchase from existing Federal reservoirs ... $25 180-440 nil 205-465 0.11-0.24 Purchase from new Federal reservoirs, ., ., 100 180-440 nil 280-540 0.14-0,28 Purchase of senior Irrigation rights ., ., 100-250 180-440 nil 280-690 0.14-0,36 High-quahty ground water . . 20-60 nil nil 20-60 nil-0.03 Brackish ground water ...... 20-60 nil $250-530 270-590 0.14-0.30 Interbasin diversions ., ., 25 750-1,500 nil 775-1,525 0.40-0,79

a Assumes that 8500 acre-ft/yr IS consumed per 50,000-bbl/d Plant SOURCE R F Probslem H Gold and R E Hicks, Waler Requirements Po//u(Iorr E/lecls, and Cos(s of Wafer .SWIp/y arrd Trealmerrf for fhe 0// S/ra/e induslry report prepared for OTA by Water Purification Associates Oclober 1979 Ch. 9–WaterAva/labd/[y ● 395 range from essentially zero to about $0.03/bbl $0.79.The higher unit cost for interbasin di- of oil. The perfection of conditional water de- versions was calculated under the assump- crees is more costly, with unit costs ranging tion that water would be transported for 800 from $0.09 to $0.2/bbl of oil. It is comparable miles from the Columbia River Basin. to purchasing surplus water from existing Federal reservoirs. Purchasing water from Except for interbasin diversions, the costs new Federal reservoirs is comparable in cost of water supplies range from essentially zero to developing brackish ground water—about to about $0.36/bbl of upgraded shale oil. Such $0.14 to $0.28/bbl of oil. Water obtained by water costs, which would have seemed unat- purchasing senior irrigation rights costs a lit- tractively high in the early 1970’s when oil tle more. Interbasin diversions are by far the prices were about $3.00/bbl, are less conse- most expensive, with unit costs from $0.40 to quential with current oil prices.

Legal and Institutional Considerations

The previous sections evaluated the physi- identified above. This is a questionable as- cal and economic requirements of several sumption because several aspects of the law water supply strategies. The feasibility of any of the river are in direct conflict and not all of them also depends on a number of legal have been accepted by the States, particular- and institutional factors, some of which are ly in the Upper Basin. For example, the Col- examined below. orado River Compact of 1922 assured delivery of 7.5 million acre-ft/yr to both the Upper and Lower Basins. This would be possible The Law of the River with virgin flows of at least 15 million acre- As discussed previously, water develop- ft/yr; it would not be possible with the lower ment in the Upper Basin will be constrained flows that have prevailed since 1930. The de- by the following factors: livery obligation of the Mexican Water Trea- ty of 1944-45 is another source of conflict. ● The operating criteria for Federal reser- The treaty has not been a constraint on the voirs in the Upper Basin, which require Upper Basin States because of their low a minimum discharge of 8.23 million water demands in the past. However, it could acre-ft/yr from Lake Powell. significantly affect future development pro- ● The Upper Colorado River Basin Com- grams. If the obligation were imposed on the pact of 1948, which limits the percent- Upper Basin under the percentage formula of age of total Upper Basin depletions that the Upper Colorado River Compact of 1948, can be consumed by each State. Colorado’s share would be 388,000 acre-ft/yr, Utah’s 173,000 acre-ft/yr, and Wyoming’s Different assumptions about virgin flow, re- 10 105,OOO acre-ft/yr. If the Upper Basin States gional growth rates, processing technologies, were able to avoid the obligations through liti- and plantsites can lead to widely different gation, much higher levels of regional growth projections of the maximum size of the oil and energy development would be possible. shale industry that could be supplied by surplus surface water in 2000. Assuming 13.8- The States may choose to follow this path. million-acre-ft/yr virgin flow, medium growth For example, Colorado Governor Richard rates, and an industry with an average water Lamm maintains that Colorado and the other Upper Basin States are not responsible for requirement of 8,500 acre-ft/yr per plant, the 39 limit appears to be about 2 million bbl/d. satisfying the Mexican treaty obligation. The director of the Colorado Water Conserva- This estimate assumes that the States in tion Board describes the State’s position as the Upper Basin concur with the constraints follows: 40 396 ● An Assessment of Oil Shale Technologies

There has been a considerable amount of could be curtailed during dry periods to pro- study, together with a considerable amount vide water to more senior users, with severe of speculation, concerning the amount of economic repercussions unless sufficient water which is still available to the State of water storage had previously been con- Colorado under the terms of the Colorado structed. Any new rights obtained through River Compact and the Upper Colorado River the prior appropriation system would be ex- Basin Compact. The problem with any study is that no one can actually define the precise tremely junior and even more susceptible to amount of water to which Colorado is en- curtailment. Any large-scale use of ground titled under the terms of the compacts. In ad- water for oil shale development would have dition to existing uncertainties concerning to protect the water rights of senior surface the compacts, the Mexican Treaty of 1944 water users. further complicates any water supply study. There are some basic disagreements among Thus, the prior appropriation doctrine re- the various states of the Colorado River Ba- duces the attractiveness of developing water sin as to the obligation of each State for the supplies through perfection of existing or fu- release of water to satisfy the Mexican Trea- ture conditional decrees. Given the con- ty. At some future time it appears likely that straints of the appropriation system, it ap- these differences will be taken to the United pears that the most reliable strategies would States Supreme Court for resolution. be additional purchase of highly senior irriga- Analysis of the legal position of the States in tion rights, purchase of surplus surface wa- this controversial matter is beyond the scope ter from reservoirs, ground water develop- of this assessment. It is possible, as the above ment in selected areas, or interbasin diver- citation implies, that resistance to supply sions. obligations could be directed at the Mexican treaty itself. However, because the treaty is a Federal Reserved Rights Doctrine national commitment, it is more likely that resistance will be manifested against the Under this doctrine, water has been set operating criteria for Federal reservoirs in aside for use on Federal lands, but the the Upper Basin. These criteria have been im- amounts of water affected have not yet been plemented by DOI through requirements for quantified. An important aspect of the doc- minimum annual discharges from Lake Pow- trine is that Federal rights, when perfected, ell. The 8.23 -million-acre-f ft/yr discharge re- will be senior to most others. Any more junior quirement incorporates both the Lower Basin user will face curtailment in times of water allocation of 7.5 million acre-ft/yr and the Up- shortage. The doctrine is an example of the per Basin’s share of the Mexican obligation. constraints imposed by prior appropriation. The Upper Basin States do not agree with the operating criteria. 41 42 The doctrine would affect any acquisition strategy that relied on flows originating within the Upper Basin. The only strategies The Doctrine of Prior Appropriation that would avoid the doctrine’s constraints would be the development of nontributary As stated earlier, most of the water rights ground water, interbasin transfers specifi- held by potential oil shale developers are cally for use in oil shale facilities, or the pur- either conditional decrees, which are large in chase of irrigation rights that are senior to quantity but junior in date of appropriation, the Federal rights. The latter would be dif- or absolute irrigation rights, which are small ficult because many of the potential Federal but senior. Under the appropriation doctrine, rights date back to the late 19th century. only the irrigation rights would provide secure water supplies. They would be limited It is possible, although uncertain, that the to about 10,000 to 20,000 acre-ft/yr. If the Federal reserved rights could be used to more junior decrees were perfected, they assist oil shale development. Because the Ch. 9–Water Availability ● 397

Supreme Court has decided that the affected Upper Basin to this system might affect water may only be used to further the pur- their future use for energy development, poses for which a reservation was estab- ● The Wilderness Act. This Act established, it appears that the only relevant rights lishes a National Wilderness Preser- would be those that might be claimed for the vation System composed of federally Naval Oil Shale Reserves in Colorado and owned wilderness areas as designated Utah. These reserves were established in the by Congress. The Act also stipulates the 1920’s and the rights, if they could be imple- conditions under which reservoirs and mented, would be quite senior. However, the other facilities can be built within these legal position of the rights in Colorado is com- areas. As a consequence of this Act, res- plicated because the reserves do not border ervoirs and other water facilities needed on the Colorado River and they contain little for energy development might be re- ground water. The Government has indicated stricted in certain areas. that it intends to claim water for the Colorado These laws should not reduce the availabil- reserves; the claim is in the early stages of ity of water within the Green River hydrologic litigation by the State, basin because there are presently no known endangered species or designated water Environmental Legislation areas within this basin. Furthermore, flows of the Green River will be insignificantly af- There are a number of environmental laws fected by the projected levels of shale oil pro- which do not directly restrict water use but duction. which could affect the siting of facilities, the scale of operation, and particular water ac- In contrast, environmental legislation quisition strategies, It is difficult to predict could constrain oil shale development in the their effects on development of water re- White River basin. High levels of shale oil sources in the oil shale region, but it is impor- production are projected for this basin, and tant to note their existence and to recognize the associated water requirements could sig- that they could be of considerable conse- nificantly reduce river flows. Furthermore, quence. Included are the following laws: the Colorado River squawfish, a federally designated rare and endangered species, is ● The Fish and Wildlife Coordination Act. known to inhabit the lower portions of the This Act required that all Federal agen- White River. In addition, the Flat Tops Wil- cies which direct, impound, or modify derness area, an existing Federal wilderness, water bodies must consult with USFWS. includes portions of the headwaters of the Plans for water resource development north and south forks of the White River. Flat are reviewed by the Service to assure Tops could affect oil shale development in that they include appropriate protective that reservoirs and other structures would measures for fish and wildlife. not be permitted within the wilderness area, ● The Endangered Species Act, Under this except under presidential approval. Act, Federal agencies are to conserve threatened or endangered species. In Water availability within the basin of the the Upper Basin there are species of en- Upper Colorado mainstem might be affected dangered fish—the humpback chub and by the Endangered Species Act, the Wilder- the Colorado River squawfish—which ness Act, and the National Wild and Scenic might influence the siting of reservoirs Rivers Act. The Colorado River squawfish infor energy development. habits the Colorado River from the back- ● The National Wild and Scenic Rivers waters of Lake Powell upstream to the con- Act. This Act is designed to preserve fluence of Plateau Creek. The humpback chub portions of selected streams in a natural is found in the Colorado mainstem down- state. The addition of any streams in the stream from the Colorado/Utah State line. 398 . An Assessment of Oil Shale Technologies

This basin also contains three designated perfection of instream rights reduced the wilderness areas, and additional areas are amount of surplus water available for sale. being considered for inclusion in the wilderness system pursuant to the ongoing Roadless On the other hand, minimum flow bypasses Area Review and Evaluation (RARE II) re- around reservoirs and dams are required for view. ’ New reservoir storage would probably aquatic life under the Clean Water Act. De- not be permitted in these areas. However, pending on the interpretation given this Fed- they are in high-elevation watersheds and eral statute by the States, the total amount of thus would probably not contain potential surplus surface water could be decreased. sites for reservoirs. In addition, several Finally, USFWS is engaged in a study to de- rivers within this basin are being considered velop strategies for reserving flows to main- for wild and scenic designation. tain fish and wildlife habitats. Although they Thus, these environmental laws might af- are not yet part of the legal system, such fect the siting of storage reservoirs and limit strategies might ultimately reduce surface the amount of water that could be diverted water availability for any type of growth in from certain rivers. Water supply strategies the oil shale region. that require extensive storage, such as the purchase of irrigation water, could be af- Interbasin Transfers fected. Several legal barriers constrain interbasin Instream Water Flow transfers of water to the oil shale region. The Yellowstone River Basin Compact of 1950 (65 Instream flow requirements are legally Stat. 663) requires approval of Wyoming and considered only in Colorado, where the State Montana before transfers of Yellowstone has retained the right to obtain water for water can occur. Moreover, the Colorado preserving the natural environment to a rea- River Basin Project Act of 1968 (82 Stat. 885) sonable degree. Instream rights are subject specifically prohibits the Secretary of the In- to the prior appropriation system, and have terior from undertaking feasibility studies of priority over consumptive rights only if they any plan to import water into the Colorado are more senior in time. The State recognized River Basin until 1978. This moratorium on instream rights in 1973, and thus these rights water feasibility studies was extended under are quite junior and should not impede the the Reclamation Safety of Dams Act (92 Stat. perfection of rights held by oil shale devel- 2471) until November 1988. Thus, until this opers, some of which date back to 1949. How- moratorium is removed no new imports can ever, if the oil shale industry were to file for occur. additional surface rights they would be junior to the instream rights and would have a lower Salinity Standards priority in times of water shortage. Other water acquisition strategies—such as the The States within the Colorado River sys- purchase of senior irrigation rights, trans- tem are committed to maintaining salinity at basin diversions, and ground water devel- or below the average 1972 levels in the lower opment—would not be significantly affected. mainstem of the Colorado River. They have The purchase of surplus water from Federal developed salinity criteria for three points in reservoirs would be affected only if the the Lower Basin—Hoover Dam, Parker Dam, and Imperial Dam. The criteria have been ap- *The Forest Service, in its RARE 11 program, is evaluating proved by EPA, but are tentative and subject over 66 million acres of land to determine their suitability for designation as wilderness. During the period of initial evalua- to revision. tion and up to final disposition of the wilderness recommendation by Congress, these lands will be in some form of restrictive Salinity criteria could constrain oil shale management. development because such development has Ch. 9–Water Availability ● 399 been linked, through theoretical calculations, would be little affected, and interbasin diver- to salinity increases in the river system. In- sions would not be constrained as long as the creases could occur through either of two salinity of incoming water was lower than mechanisms: salt loading (in which saline upstream surface flows within the basin. The wastewaters are discharged from an oil shale transfer of senior irrigation rights would plant) or concentration (in which waters of probably not be impeded because, as dis- higher than average quality are removed cussed in chapter 4, irrigation return flows from the Upper Basin tributaries for use in oil are the chief man-related source of salinity in shale processing). Salinity increases from the Colorado River system. A reduction in concentration are discussed in the next sec- these flows through diversion to oil shale tion of this chapter; those from salt loading processing should decrease the salinity of the are discussed in chapter 8. lower mainstem. It is possible that salinity criteria could af- In summary, the effects of emerging salin- fect oil shale operations if such operations ity standards cannot be predicted with any acted to increase the salinity in the lower confidence. Certain water acquisition strat- mainstem. If this were the case, acquisition egies would feel them more than others. They strategies that increase the total depletions should not severely affect any strategy if from the river system would be constrained. water released from oil shale sites is treated These would include the perfection of surface to achieve the discharge standards promul- water rights and the purchase of stored sur- gated under the Federal Water Pollution Con- face water. Ground water development trol Act.

Critical Uncertainties

The previous analyses have calculated that Virgin Flow an oil shale industry of up to 2 million bbl/d could be supported to the year 2000 by sur- As noted, the flows of the Colorado River plus water that is legally available to the oil vary widely. Estimates of future water avail- shale States. This calculation is based on four ability have been based on the flows meas- key assumptions: ured at Lee Ferry after 1930 because earlier estimates of virgin flow were less accurate. The long-term average virgin flow is 13.8 (Before 1922, flows were not measured at Lee million acre-f ft/yr—the running average Ferry; they were estimated from the meas- between 1930 and 1974. ured flows of upstream tributaries. ) How- The industry continues to use a mix of ever, it is not clear that the flows encoun- mining and processing technologies simi- tered in the past will continue into the future. lar to that which would be used if pres- The 13.8-million-acre-ft/yr average could sus- ently active and proposed projects were tain a large industry through 2000, but if the completed. long-term average decreased by 3 percent, to Water demand for conventional uses in 13.4 million acre-ft/yr, there would be no the Upper Basin increases at a medium surplus surface water available then. Meas- rate. urements of tree rings in the Colorado River The industry relies solely on surface Basin suggest that the long-term average flow water; ground water is not ‘developed. may be closer to this level than to 13.8 million Following is a discussion of how the indus- acre-ft/yr. 43 On the other hand, if the flows in- try’s capacity might be affected if other creased to 14.2 million acre-ft/yr, 3 percent assumptions were made in these areas. Con- above the 1930-74 average, there would be sideration is also given to the problems of sufficient surplus water in 2000 for a 4- water availability beyond 2000. million-bbl/d industry. The average flow be- —.

400 ● An Assessment of Oil Shale Technologies

tween 1906 and 1974 was 15.2 million acre- 2007, again without oil shale development. ft/yr. The average between 1922 (when flows The implications of this potential problem for were first measured at Lee Ferry) and 1974 oil shale are controversial. On the one side it was 14.2 million acre-ft/yr. is argued that possible long-term water shortages should preclude the establishment of an Technology Mix industry. On the other side, it is maintained that a major industry could function for much The industry’s actual average water re- of its economic lifetime without interfering quirement may be substantially higher or with other users, and in any case would use lower than the 8,500 acre-ft/yr per plant that relatively little water. (A l-million-bbl/d in- would result if present trends continued. An dustry would accelerate the point of critical industry based solely on directly heated AGR water shortage by about 3 years. ) would consume only about 4,900 acre-ft/yr per plant. The amount of surplus surface water projected for 2000 would be sufficient for Ground Water Development a 3.5-million-bbl/d industry if only this technology were employed. On the other hand, an If the presently active and proposed proj- industry of indirectly heated AGR facilities ects were completed, more than 40 percent of (at 12,300 acre-ft/yr per plant) could produce the shale oil production would come from only 1.4 million bbl/d from the same surplus. ground water areas in the central and northern Piceance basin. If additional Federal leasing were pursued, a much higher percent- Conventional Depletions age of the industry’s facilities would be sited in this area. Ground water will have to be de- Although the medium growth rate for con- veloped on these sites in order to allow mining ventional water uses is regarded by the or in situ retorting. The ground water ex- States as most likely, it is possible that tracted would have to be reinfected into the demands could increase at a much higher or source aquifer, or treated for discharge to lower rate. DNR analyzed the effects of low, surface streams, or used in the facilities. If it medium, and high growth rates. Although the were used as process water, the need for sur- medium rate would allow an industry of up to face water would be substantially reduced. If 2 million bbl/d, a high rate would reduce the 15 percent of the roughly 25 million acre-ft in surplus surface water by 247,000 acre-ft/yr in 2000. Only a 550,00@ bbl/d industry could the Piceance basin bedrock aquifers were used for oil shale, it could support a l-million- be accommodated. On the other hand, a low bbl/d industry for 20 years. However, this growth rate would increase the surplus by rate of consumption would exceed the re- 326,000 acre-ft/yr and would allow an in- charge rate for the aquifers. Thus, the dustry of up to 3.9 million bbl/d. ground water levels would decrease and In any case, surplus water availability is some of the surface streams that are supplied much less assured after 2000. If the low by ground water discharge would dry up. growth rate prevails, demand will exceed This would have relatively minor economic supply by 2027, even without an oil shale in- ramifications because the rate of ground dustry. With a medium growth rate, the water discharge is only about 20,000 acre- surplus will disappear by 2013. A high ft/yr. The environmental effects woulds be growth rate will consume the surplus by mixed, as discussed in the next section. Ch.9–WaterAvai

The Impacts of Using Water for Oil Shale Development Introduction utility lines would have to be relocated, and riparian and aquatic systems could be dis- The use of water by an oil shale industry turbed. These impacts should be minor com- will cause economic, social, and ecological pared to those of the mining and processing changes in both the Upper and the Lower Ba- operations. Because the reservoirs will be sins of the Colorado River system. The effects relatively small, the overall impacts would be of salinity increases are of special concern small compared to those that were associated because salinity levels in the Colorado River with the construction of existing reservoirs. have been identified as a matter of national (The new reservoirs needed for a l-million- concern. 44his section discusses the salinity bbl/d industry would increase the total water increases that are expected to result from storage in the Upper Basin by 0.6 percent. ) use of surface water for oil shale devel- These impacts will be site specific and have opment. The overall impacts of water diver- not yet been analyzed. sion on the Upper and Lower Basins are then discussed. Because of time restrictions, OTA did not perform an independent analysis of Impacts From Changes in Surface Flows these impacts, However, assessments have Extraction of surface water will decrease recently been completed by DNR, USBR, the instream flows of the Colorado River and USGS, and USFWS. The following discussion its tributaries. These changes will have direct is largely based on the results of these effects on water users and indirect effects on studies. water quality and aquatic ecosystems. The direct effects are considered in this section; Impacts From the Construction and the indirect effects in the section that follows. Operation of Water Supply Facilities Decreased flows would reduce hydroelec- Construction of dams, wells, and diversion tric power production at specific CRSP reser- facilities would create jobs and increase dis- voirs. According to the DNR assessment, rev- posable income. However, pressures on hous- enue losses could reach $7 million per year in ing and on community facilities and services 2000 as a result of a 2.44-million-bbld/ indus- would result. Both the positive and the nega- try. ’5 Flow reductions would also decrease de- tive effects would diminish once construction liveries to the Central Arizona project and was completed. Operation of the facilities force the agricultural industry in the Lower would require fewer than 10 employees per Basin to rely on more expensive ground water plant, out of a total work force of approx- pumping. Net farm income would be reduced by about $2.3 million per year by 2000 as a imately 1,500. Consequently, relatively few of 46 the socioeconomic impacts that may accrue result of a 2.44 million-bbl/d industry. from creating an oil shale industry can be According to USBR, environmental impacts associated with the water supply systems. in the Lower Basin depend more on reservoir New reservoirs will flood land that may operating criteria than they do on the quanti- presently be used for farming or grazing or ty of water in a particular stream, and flow that may have special scenic or ecological reductions in the Lower Basin would have sig- value. Homes, farms, businesses, roads, and nificant effects only in that portion of the Col- 402 ● An Assessment of Oil Shale Technologies orado River between Glen Canyon Dam and below the withdrawal point. Some of the esti- Lake Mead.47 mates that have been made of this salt concentration* effect are summarized in table Reductions in instream flow will also affect 86.48-54 Included for each source are estimates recreational use of some stream reaches. of salinity increases for the project or indus- Although most recreational activities, such as try originally analyzed and estimates scaled rafting, boating, and kayaking, would remain to a common basis of a l-million-bbl/d indus- unchanged in 2000 even with high levels of oil . try. As shown, a l-million-bbl/d industry in shale development, negative impacts would the Upper Basin could increase salinity levels occur in two river reaches. In the Colorado at Lower Basin measuring stations by 0.2 to River between Rifle, Colo., and its confluence 2.4 percent. The estimates incorporate wide- with the Gunnison River, rowing and rafting ly differing assumptions regarding plantsit- conditions would be degraded from the pres- ing, types of processing technologies, water ent fair condition to poor if a 2.44-million- requirements, and quality of water diverted. bbl/d industry were established. Fishing con- A very approximate average salinity in- ditions would be reduced from fair to poor crease for a l-million-bbl/d industry might be with substantially lower levels of develop- about 1 percent. ment. In the White River from Meeker, Colo., to Ouray, Utah, conditions for canoeing, kay- It should be noted that similar effects aking, and fishing would be reduced from ex- would be experienced if the same amount of cellent to good. Adverse public reaction water were used for other purposes. The Uni- should be expected. Secondary impacts on versity of Wisconsin study cited in table 86 tourism and recreational service suppliers estimated that diversion of 300,000 acre-ft/yr may occur, although no detailed analysis of of upstream water to oil shale would increase these impacts has been undertaken. salinity at Imperial Dam by about 20 mg/l. If the same quantity of water were used for irri- Impacts on Water Quality gation, the salinity increase would be about 57 mg/1. Exportation of the water from the Up- Withdrawal of water of relatively high per Basin would increase salinity by about 24 55 quality from upstream tributaries of the Col- mg/l. orado River system will increase salinity lev- The economic losses, including damage to els in the lower reaches of the Colorado River agricultural, municipal, and industrial users by making the water unavailable for dilution of more saline streams that enter the river *Increases in salt loading are discussed in ch. 8.

Table 86.–Projected Salinity Changes in the Lower Colorado River From Oil Shale Development

Salinity increase from 011 shale For model Shale 011 capacity Present Industry For 1 million bbl/d Source of estimate Reference modeled, bbl/d Measuring station salinity, mg/la mg/l mg/l Percent Colorado Department of Health 48 1,000,000b Glen Canyon Dam 609 4 4 0.7 National Academy of Sciences 49 800,000 Hoover Dam 745 2 1,6 02 1,600,000 4 25 03 Stanford Research Institute ., ., 50 250,000 Hoover Dam 745 1 4 0.7 Unversity of Wisconsin 51 1,000,000 Imperial Dam 850 20 20 24 Department of the Intenor 52 1,000,000 Hoover Dam 745 10-15 10-15 1 3-20 Bureau of Land Management 53 47,000 Hoover Dam 745 01 26 0.3 U S. Bureau of Reclamation 54 1,300,000 Imperial Dam 850 7 5 06 2,440,000 15 6 07 a Data from reference 59 Calculated from estimates for Increases in the White River and the Colorado Mainstem SOURCE Off ice of Technology Assessment in the Lower Basin could reach $5.4 million ogy of smaller streams at high elevation so no per year in 2000 for a 2.44-million-bbl/d in- conclusions can be drawn on impacts on dustry. This estimate is based on a salinity in- these streams at present. crease at Imperial Dam of 18.1 mg/l—l.8 per- Limited effects on fishery habitats were in- cent of present salinity levels.’” dicated for the Upper Basin as a whole, ex- The full salinity impacts of water used in cept for the White River. For rainbow trout in the Upper Basin are not felt until much later the Green River, the fry, juvenile, and adult in the Lower Basin because of the dampening stages would be little affected by a 2.44- effects of Lake Powell and Lake Mead. For million-bbl/d industry. Spawning conditions example, the Colorado River Basin Salinity would remain poor. Adult Colorado River Control Forum estimates that the full effects squawfish in the Yampa River would not be do not occur until after 17 years. The fore- affected, but conditions for squawfish fry in casts for 2000 therefore underestimate salini- the same stream would improve from their ty effects on the Lower Basin, In addition, an present poor level to fair. Conditions for adult assumption of the USBR analysis is that three squawfish in the White River would degrade authorized desalinization plants will be in from their present level of excellent to good. operation by 2000, removing over 700,000 Assessment of impacts on plants, inverte- ton/yr of salt. brates, and other components of the aquatic To a lesser extent other water quality pa- ecosystem have not been undertaken, rameters will be affected by the use of water for oil shale development. Sediment loading Transfer of Water From Irrigated will increase in some reaches as the result in changes in land use associated with the Agriculture dams, pipelines, and roads for the water supply facilities. Changes in river flow from res- Although it is not necessary to take water from irrigated agriculture to supply oil shale ervoir operation could alter sediment trans- developments, such transfers are legally per- port and the biochemical oxygen demand in mitted. Because the economic value of an some reaches. These impacts have not yet been assessed in detail. acre-foot of water to an oil shale developer is much greater than to irrigated agriculture, transfers of water rights could occur in some Impacts on River Ecology areas. These transfers would have social and economic ramifications, including a redistri- Changes in instream flow can affect the bution of income. Farm income would be re- aquatic ecosystem including the habitat of duced, but these reductions would be coun- sport fish and rare and endangered species. tered by a regional income gain because of in- Of special concern are the effects on rainbow creased employment in the oil shale industry, trout, a major sport fish, and the Colorado According to DNR, the gain would be 10 to River squawfish and humpback chub which 58 are endangered species. Analyses of the im- 100 times greater than the 10SS. The number pact of water use for oil shale on the rainbow of farming families would also be reduced. trout, the squawfish, and numerous other fish Significantly larger impacts would be experi- species have been undertaken by USFWS enced, however, from factors not directly re- and the U.S. Heritage and Conservation Serv- lated to water use patterns, such as the com- ice,57 but the effects on the humpback chub petition for local labor and the purchase of have not been assessed due to lack of criteria agricultural lands for municipal expansion. in the USFWS study, These assessments do Irrigated agriculture diverts large quan- not include studies of the complete aquatic tities of surface water, but only a portion is ecosystem and exclude impacts on the ecol- actually consumed. The balance eventually ——.

404 ● An Assessment of 01/ Shale Technologies

returns to the water systems through agricul- Ground Water Development tural return flows and/or percolation into ground water aquifers. Oil shale developers The impacts caused by well-drilling and can only purchase rights to the consumptive maintenance would be similar to those for the portion of the diversion. Therefore, if irriga- construction of reservoir and pipeline facil- tion rights were transferred to oil shale devel- ities for surface water development—rela- opment, less water would be diverted from tively small and of short duration. After the surface streams, and stream flows would in- wells are drilled, only a few workers would crease. The effects of these increases were be needed for maintenance. The number not modeled for DNR because of their small would be small in comparison with the esti- size and because a significant diversion of mated total work force of an operating oil agricultural water to oil shale development is shale plant. Unlike purchase of irrigation not anticipated in most areas. If significant rights, ground water development should not effects occurred at all, they would most likely have significant effects on the economic base be in the White River Basin, where fish habi- of the oil shale region. tats and recreational opportunities would be Stream flows would not be significantly re- improved as a consequence. duced for the overall basin, although substan-

Photo credit OTA staff Pumping water from the White River for agricultural purposes Ch. 9–Water Availability ● 405

tial reductions would occur in those areas in constitutes an irrevocable decision to exploit which ground water discharge supplies a ma- a nonrenewable resource, hence precluding jor portion of surface flows, For example, its use for other purposes in the future. some streams in the Piceance basin are fed Oil shale projects that use low-quality by ground water discharge during most of the ground water may produce a net decrease in year. Aquifer drawdown as a result of salinity in Colorado. For example, the Superi- ground water development would reduce or Oil project in Colorado’s Piceance basin flows in these streams, and in some cases will use water from the lower bedrock aqui- would completely eliminate them except dur- fer that has a salinity concentration of about ing the spring snowmelt. Fishery habitat in 26,000 mg/l—about 30 times the salinity of these streams would be severely affected. the Colorado River at Imperial Dam. With- According to DNR, the overall effects of drawal of this water would reduce the quan- ground water development on fish habitats tity of salts discharged into Piceance Creek and recreation would be much less than by about 24,500 ton/yr. As a result, the salin- would be encountered with water acquisition ity of Piceance Creek would decrease by strategies that relied solely on surface water about 1,040 mg/l. Salinity in the near reaches diversions.5’ However, heavy dependence on of the White River, into which Piceance Creek ground water could lead to using under- discharges, would be reduced by about 40 ground water resources faster than the rate mg/l.60 Salinity at Glen Canyon Dam would of recharge and in some instances to mining decrease by about 1.6 mg/1—about 0.3 per- geologically old water. The use of such water cent of its present level.

Methods for Increasing Water Availability

Sufficient water should be physically avail- tegies would have to be focused on the larger able in the Upper Basin to support a large oil cities in Colorado’s Front Range Urban Cor- shale industry while simultaneously satisfy- ridor that import water from the Upper Ba- ing the needs of other users. However, water sin. For example, if Front Range cities low- scarcity could constrain regional growth ered consumption by 20 percent, exports after 2000. Additional surface flows could be would be reduced by about 100,000 acre- provided through conservation (i.e., more effi- ft/yr. 61 Demand could be reduced by methods cient use of water), interbasin diversions, and such as restricted lawn watering or imposed possibly by weather modification. Water use peak-use surcharges, seasonal pricing differ- efficiency and weather modification are dis- entials, and price incentives. Recycling sys- cussed below; interbasin diversions were dis- tems could also be considered, but implemen- cussed earlier. tation could be hindered by high costs and their unfavorable image. More Efficient Use Irrigated Agriculture By reducing demand, water conservation would increase net water availability. Oppor- Present irrigation methods are inexpensive tunities exist in municipalities, in irrigated to the farmer but relatively inefficient. Even agriculture, and in industrial activities in- small improvements could release large cluding oil shale development. quantities of water for other purposes and decrease the quantity and perhaps salinity of Municipal agricultural return flows. Losses from canals could be reduced by adding impermeable lin- Because municipalities in the oil shale re- ings or pipelines. Sprinkler systems or trickle gion consume little water, conservation stra- irrigation would reduce evaporation from 406 ● An Assessment ot 011 Shale Technologies

field soils. Losses to noncrop vegetation could tions would probably not exceed 120,000 be reduced by eliminating the vegetation. acre-ft/yr even with vigorous programs. Crop evapotranspiration and loss of cropcap- tured water could be reduced by substituting Industrial crops that need little or no irrigation water. Oil shale plants will use water efficiently. Few of these strategies could be introduced This is a consequence more of the nature of on a large scale, however, without substan- the processing technologies and the desire to tial economic, social, and environmental pen- avoid having to treat excess process water to alties. Mechanical irrigation, for example, discharge standards than it is of an interest would be very expensive, as would fabricated in water conservation. * However, different pipelines. Vegetation removal could threaten technologies consume different amounts of the ecological balance along stream courses water for the same production rate and the and manmade waterways. Dryland farming overall requirements of the industry could be might not be technically or economically fea- reduced by encouraging the use of processes sible. Furthermore, conservation could be with the lowest water requirements. It is risky because if a farmer did not use all of the unlikely that technologies would be chosen water covered by his water rights, abandon- 62 solely on this basis because water costs are a ment could be declared. very small fraction of total processing costs. Estimating possible reductions by conservation is technically straightforward. Esti- *The U.S. Water Resources Council states that an AGR plant mating likely reductions is much more dif- would consume about 89 percent less water than a steam- elec- tric powerplant with the same net energy output, 25 to 87 per- ficult because of the social and economic cent less than a comparable coal gasification plant, and 40 to complications. DNR concluded that reduc- 90 percent less than a comparable coal liquefaction facility.’)’ Ch 9–Water Availability ● 407

Offsite powerplants to support municipal ground water that could be withdrawn with growth could adopt conservation methods out disrupting the aquifer equilibrium.66 without substantially increasing power costs. Preliminary cost estimates range from $1 It has been estimated that water require- to $10/acre-ft of additional runoff, There ments for power generation in the oil shale would be additional costs for capturing and States will increase by as much as 221,000 transporting the augmented flows, and stor- acre-ft/yr before 2000, If the new power- age facilities would still be needed, Any addi- plants relied on a combination of wet and dry tional runoff would be subject to the prior ap- cooling, water consumption could be reduced propriation system because the augmented by about 175,000 acre-ft/yr, sufficient water flows would be indistinguishable from natu- for production of 1 million bbl/d of shale oil. 65 ral flows. Because of the problem of uncertain ownership, the delivered water cost might well exceed the costs of other supply Weather Modification methods. Cloud seeding could be used to enhance The consequences of weather modification precipitation and thereby increase surface are not well understood, but a successful pro- water and ground water resources. The re- gram could be expected to have widespread sults of three major projects during the last effects on the region’s ecosystems. Species two decades suggest that overall increases in composition, vegetation growth rates, and snowfall could range from 5 to 20 percent. It wildlife habitats might be altered. Although appears that if snowfall were increased by there could be recreational benefits from in- 10 percent, runoff might increase by from 5 to creased snowfall and higher streamflows, ag- 20 percent and might add up to 2.0 million riculture and transportation could be ham- acre-ft/yr to normal surface flows. Ground pered. Losses in precipitation to areas be- water aquifers would also be affected beyond the zone of augmented rainfall or snow- cause they are recharged principally from fall could have severe ecological, agricul- snowpack. USGS has estimated that a 10- tural, and economic impacts. There could be percent increase in snowfall in the Piceance legal difficulties if cloud seeding were linked basin would add over 10,000 acre-ft/yr of to drought in downwind areas.

Policy Options

The distribution of water from the Colora- by Congress, the administration, State gov- do River system is governed by a complex ernments, and the oil shale developers. framework of interstate and interregional compacts, State and Federal laws, Supreme Court decisions, and international treaties. The Determination of Water Needs Policy decisions affecting the use of this water for oil shale development must take In order to more accurately assess the total into account both the provisions of these amount of surplus surface water that will be documents and the need to protect the rights available for additional growth in the Upper of competing water users. A number of policy Basin, the amount needed by all projected options that would affect the availability of users must be determined. The uncertainty water for an oil shale industry in the Upper about the future availability of water sup- Colorado River Basin are examined below. plies to the Upper Basin would be reduced if Their implementation could involve actions the necessary determinations were carried 408 ● An Assessment of Oil Shale Technologies out by Congress, by Federal and State govern- known, reliable estimates of water availabil- ments, and by private developers. Some possi- ity for regional growth cannot be made. The ble options are: uncertainty would be reduced if there were some indication in the near future of the The development of a water management amounts that will be claimed under this doc- system.—Preliminary water management trine. studies have been conducted by the Bureau of Reclamation and by individual developers The determination of water needs by the and other users. However, no systematic Colorado State Government.—In Colorado, basin-wide evaluation of water management the requirements for instream flows are alternatives has compared water supply op- legally considered only where the State has tions with respect to their water and energy retained the right to obtain water for preser- efficiency, their costs and benefits, and their vation of the natural environment. Colorado environmental and social effects. Such an recognized instream rights in 1973; thus, assessment—involving Federal, State, and lo- these rights are junior and should not impede cal governments; regional energy developers; the perfection of rights held by other users other users; and the general public—may be prior to this date. However, such rights could an appropriate prelude to actions to con- affect the amount of water available to users struct new water storage and diversion proj- who file in the future for additional surface ects. It could be especially useful in evaluat- rights— any additional rights would have a ing and coordinating such controversial op- lower priority in times of water shortage. The tions as the importation of water. Funding State is presently in the process of filing for could be provided by DOI, DOE, or other rights for instream water needs. Completing agencies. The study could be managed by the this process would further clarify the total Bureau of Reclamation or by Colorado River amount of water available for development in Compact Commission. this region. The determination of the amount of water The determination of water needs by mu- needed by the Federal Government.—This nicipalities, private developers, and other could be done for Federal lands for which water users. —Water rights in the oil shale water rights are set aside under the Federal States have been granted liberally. As a re- reserved rights doctrine. One possible alter- sult, the quantities of water covered by condi- native for Congress is to provide legislation to tional decrees far exceed the available re- facilitate this determination in coordination sources of the river. At the same time, not all with one of the administration’s task forces the conditional decrees have been perfected, devoted to evaluating Indian and Federal re- and relatively little of the claimed water is ac- served water rights. tually being used. If it could be determined how much of the water allocated under the It is anticipated that the largest Federal conditional decrees will actually be benefi- claims in the oil shale region will be for the cially used in the near term (for municipal, Naval Oil Shale Reserves. The U.S. Navy has agricultural, or industrial purposes), then the made a preliminary filing with the Colorado Upper Basin States would have a clearer indi- water court for 45,OOO acre-ft/yr. In addition, cation of the actual amount of surplus water small amounts of water may be needed for di- available. versions, impoundments, wells, and stream flows. Although filings are being made under this doctrine, most indications are that the Reservoir Siting and total amount of water that will be claimed by Direct-Flow Diversions the Federal Government in the oil shale region will not be excessive. The exact quan- All water acquisition strategies that rely tities, however, have not been determined. on the large-scale development of surface Because the extent of future filings is un- water resources within the oil shale area would necessitate the construction of new Designation of rivers to be set aside under reservoirs and direct-flow diversions (e.g., the Wild and Scenic Rivers Act. —Any river pipelines). Such construction might be ham- area possessing one or more scenic, recrea- pered, delayed, or even disallowed under pro- tional, archeologic, or scientific values and in visions of the Endangered Species Act, the a free-flowing condition, or under restoration National Wild and Scenic Rivers Act, and the to such condition, may be considered for in- Wilderness Act. Potential problems could be clusion in the Wild and Scenic Rivers System. reduced through several mechanisms. A number of rivers have already been designated under this legislation, and Congress is Identification of endangered or threat- considering adding others. To date none in ened species. —The Endangered Species Act the oil shale region has been designated; how- provides for the Federal identification of en- ever, several within the Colorado mainstem dangered and threatened species of fish, basin are being considered for wild and sce- wildlife, and plants; prohibits private activity nic designation. The amount of water that that imperils such species; and requires Fed- could be diverted from specific river reaches eral agencies to avoid any activities that could be reduced if these rivers are set aside, would jeopardize such species or result in the thus an early designation of rivers eligible destruction of critical habitats. A number of under this legislation would be of value in studies are underway to identify endangered planning for future shale oil production. and threatened species in the Upper Basin. Given this information, direct-flow diversions To date, two federally designated rare and could be sited downstream to those portions endangered fish species have been found in of rivers designated as wild and scenic the waters of the oil shale region. The Col- rivers. This would avoid a direct conflict orado River squawfish inhabits the lower por- within a given river stretch but could add to tions of the White River and the Colorado the water supply cost. River from the backwaters of Lake Powell upstream to the confluence of Plateau Creek. Designation of wilderness areas.—The The humpback chub lives in the Colorado Wilderness Act created the National Wilder- mainstem downstream from the Colorado/ ness Preservation System to provide “the Utah State line, Additional species requiring benefits of an enduring resource of wilder- protection may be found in the future. ness” for the whole Nation. In keeping with The Act may be interpreted as restricting the purpose of preservation, the use of these activities that might adversely affect the areas is highly restricted. To date four areas critical habitats of such species, although in the White River basin and the Colorado none has been declared for the squawfish or mainstem basin have been designated under the humpback chub. Knowing their approxi- this legislation. Also, additional areas are mate locations would be helpful because the being considered for inclusion in the system timely siting of reservoirs and direct-flow pursuant to the ongoing RARE II review. New diversions could be affected by agency inter- reservoir storage would probably not be per- pretations involving instream flows. Should mitted in these areas, once designated. Since construction of these facilities begin before they are located at higher elevations in upper the critical areas were identified, there could watersheds, they would probably not contain be opposition to their completion, and water potential sites for reservoirs; however, addi- supplies from a particular reach of a river tional wilderness areas at lower elevations could be delayed or interrupted. If the loca- could pose problems in siting storage facil- tions of all designated critical habitats were ities. A complete listing of wilderness areas identified by DOI and the required biological that might be considered in the near uture opinions obtained, the facilities could be sited would aid potential developers in locating to minimize interference and delay. their facilities in other areas. 410 w An Assessment of Oil Shale Technologies

Financing and Building New Reservoirs orado River mainstem. The river district maintains that these decrees will likely be New reservoir and storage facilities would used as a source of supply for an oil shale in- need to be constructed if a large shale indus- dustry. Several possibilities exist for the try were to be created. There area number of funding of reservoirs. One possible funding possible policy options for the financing and arrangement might be to sell water from ex- construction of such facilities. isting State-administered reservoirs, such as Green Mountain and Reudi, to oil shale devel- Federal financing. —Congress could pro- opers at very high cost (e.g., $250/acre-ft/yr). vide for the construction and funding of new The short-term needs of many potential oil Federal water projects through two mecha- shale developers, depending on the siting of nisms. First, Congress could appropriate their facilities, could be met from such exist- funds for those Federal water projects that ing reservoirs. The profits from such sales already have been authorized. Several proj- could be used as leverage capital for market- ects have been evaluated by WPRS (formerly ing public revenue bonds. The capital gener- USBR), and their construction approved. Ac- ated from these bonds could then be used to tual construction of these projects cannot finance the new reservoir facilities that begin until they are funded. However, not all would be needed by an oil shale industry in of these projects have been evaluated for the longer term. A second funding scheme, their suitability to supply water for oil shale which has been practiced by CRWCD in the development, and some project features may past, is to sell options for water from pro- not be optimally located to serve oil shale posed reservoirs to potential water users, projects. thus raising the funds needed for the con- A second option available to Congress is struction of the reservoirs. the passage of legislation that would specify Developer financing.—Reservoir and stor- the construction and funding of new, not age facilities could be financed and con- previously authorized Federal water proj- structed by the oil shale industry itself. ects. However, unless language was included to expedite construction, these projects would require a long review process. They Financing and Implementing could, however, be designed and sited with More Efficient Practices and Water their purposes as water sources for oil shale Augmentation (as well as other possible uses) in mind. An example would be constructing irrigation res- Surface flows in the Upper Basin could be ervoirs with additional capacity for oil shale increased if water conservation procedures requirements. were practiced by irrigated agriculture, Under either option, DOI, through USBR, municipalities, and industry. Weather modi- could operate these reservoirs in accordance fication is another possibility. Since carrying with State water laws. Their costs could be out these approaches could be quite costly for recovered over the operating life of the facil- a particular developer or municipality, their ities from revenues generated by selling chance of being implemented might improve water to oil shale developers and other users if Federal and State governments were to and in accordance with authorizing legisla- supply some special funding or incentives. tion. The following are some possible ways this could be done. State participation. —A State organization, such as the Colorado River Water Conserva- Funding and implementing water use tion District (CRWCD), could finance and con- practices.—Techniques for more efficient struct new storage facilities. CRWCD holds water use in irrigation and farming were il- large storage decrees in the basin of the Col- lustrated earlier. As noted, farmers would be taking risks by adopting water conservation conserving techniques could be used to mini- strategies because capital recovery would be mize overall consumption. For example, some uncertain and they might lose water rights. development technologies require less water At the sometime, improvements in irrigation than others—directly heated AGR has the and farming practices could substantially re- lowest requirement (4,900 acre-ft/yr for duce the demands for water in the Upper 50,000 bbl/d of shale oil), while indirectly Basin. A number of options are available that heated AGR has the highest (about 12,300 would encourage such improvements. Con- acre-ft/yr for the same output). Total industry gress could provide financial incentives, consumption could be reduced by encourag- through such mechanisms as tax advantages, ing the use of the lowest water-consuming to those farmers who used water more effi- process. One congressional option would be ciently, Technical assistance teams specializ- to provide financial incentives to those fa- ing in conservation techniques could also be cilities that implemented this process. provided to cooperating farmers by the Fed- Another would be to provide tax advantages eral and State governments. In addition, Con- to any facility that introduced specific water- gress could give direct financial assistance conserving techniques. Also, through Govern- through grant programs, administered either ment contracts, Federal agencies could spe- by Federal or by State agencies. cifically fund R&D by developers to improve the efficient use of water. Individual municipalities could institute voluntary education programs and regulatory strategies aimed at reducing overall water Funding of weather modification pro- consumption. Regulatory programs could re- grams.—A number of Federal agencies, in- strict the watering of lawns and promote the cluding the Departments of Commerce and of use of water-saving devices. Cities could es- the Interior, have sponsored programs relat- tablish peak-use surcharges, seasonal pricing ing to winter orographic weather modifica- differentials, and price incentives to reduce tion, The Federal Government could continue usage. Local municipalities could also adopt to fund programs in the Upper Basin with the water conservation techniques for their aim of eventually increasing overall regional wastewater treatment facilities. surface flows. If programs are funded, they should include work to better understand the Municipal conservation techniques, wheth- impacts of weather modification. er voluntary or mandatory, are costly. Fi- nancing is needed to pay for administrative Weather modification programs, although personnel as well as to produce and distrib- costly, could be undertaken by a State organi- ute educational materials. While these pro- zation, municipality, or private developer. grams would probably be administered at the However, the ownership of any additional local level, they could be financed at the Fed- surface runoff would be uncertain under the eral or State level by direct grants or cost- current water appropriation system, and sharing programs. To help pay for carrying legal complications could arise if cloud seed- out costly conservation procedures in munici- ing were linked to drought in other areas. It is pal wastewater treatment facilities, Congress unlikely that a particular municipality or pri- could provide tax incentives for such expend- vate developer would undertake such a pro- itures. gram without some assurance that a portion Although oil shale facilities are expected to of any additional runoff would be available be efficient water users, a number of water- for its own use. 412 • An Assessment of 0il Shale Technologies

Federal Sources of Water for since Federal reserved water rights are subject to rights vested prior to the date of the Oil Shale Development reservation. Congress, under its constitutional powers, could make water available for oil shale de- A final option available to Congress would velopments from Federal water projects, or be to deny Federal water for oil shale devel- potentially from the reserved right doctrine. opment, if it decides that such development If Congress decides that water from congres- should not be given a high priority. sionally funded projects should be made available for oil shale development, then any The Allocation of Water Resources legislation enacted should provide that the term “industrial use or purpose” includes the If Congress were to pass legislation en- use of water for oil shale development. * Con- couraging the development of an oil shale in- gress could also amend the authorizing legis- dustry it might wish to address the issue of lation for those projects from which water for how the necessary water would be supplied oil shale development might be sought to per- and how oil shale legislation might affect mit the use of their water for that purpose. In water allocation. such a case, legislation may be required if the project authorization does not list among the Water in the oil shale region is presently contemplated purposes for its water “indus- distributed by a complex framework of in- trial purposes” or some other category that terstate and interregional compacts, State could encompass oil shale facilities. The ob- and Federal laws, Supreme Court decisions, jective of such legislation would be to over- and international treaty and administrative come any administrative reluctance to permit decisions. Within Western States, water the use of water for oil shale development rights are apportioned by the States to com- under an authorization that did not specif- peting users according to a doctrine of prior ically mention it. appropriation under which water rights are a The power of Congress over reserved wa- form of property separate from the land. ters is more limited than its power over waters in congressionally funded projects. The If control over the water supply for oil use of water under the reserved right doc- shale is to be left to the States, then Congress trine must be “in furtherance of the purpose should probably so specify in oil shale legisla- of the reservation. ” For this reason, Federal tion to avoid any question of the preemption water rights do not seem to be likely sources of State water laws. Legislation that would for oil shale development, except perhaps in confirm preservation to the States of the the case of lands set aside for the Naval Oil same power over water for oil shale as they Shale Reserves. This matter, however, is in have over other water supplies should re- the early stages of litigation. New reserva- quire the developer to comply with State pro- tions of land set aside for the purpose of mak- cedures in securing a water supply and pro- ing water available for oil shale development vide that the established State appropriation would not appear to be a feasible alternative, system has the same authority to grant, deny, or place conditions on water rights and per- *A Memorandum of Understanding exists between DOI and mits as would prevail in the absence of the the State of Colorado with respect 10 the use of water from ex- legislation. isting or authorized WPRS (formerly USBR) projects. The State desires that the water not be changed from agricultural, municipal, or light industry uses to energy production (including oil If Congress were to attempt to remove the shale), that are inconsistent with State policies. Under this water supply for oil shale production from memorandum, the State will review any application to redis- the control of the States, strong legal and tribute water from conventional uses to energy production. The memorandum could be superseded by congressional directives political resistance would ensue. Such re- of overriding national importance. sistance could delay oil shale development. Interbasin Diversions shale development or for all users. Alterna- tively, the water needs of Colorado’s eastern Interbasin diversion is a technically feasi- slope cities, presently being supplied in part ble although costly* option for bringing addi- from the Upper Colorado River Basin, could tional water to the oil shale region. There are be met from other hydrologic basins. The also serious political obstacles to this alter- water presently being exported from the Up- native. The Reclamation Safety of Dams Act per Basin then could be used for oil shale de- of 1978, amending the Colorado River Basin velopment. In a third application of inter- Project Act, prohibits the Secretary of the In- basin transfers, all or a portion of the terior from studying the importation of water 750,000 acre-ft/yr presently being supplied to into the Colorado River Basin until 1988. If it Mexico by the Upper Basin States under the were decided to pursue this option as a Mexican Water Treaty of 1944-45 could be means of supplying water to an oil shale in- taken from another hydrological basin (per- dustry coming on line in 1990, this prohibition haps the Mississippi basin). The water thus would have to be lifted. freed in the Upper Basin could be assigned in Interbasin diversions could be used to part to oil shale development (750,000 acre- relieve the water problems of the region in ft/yr would be sufficient for a 3,000,000- to 7,500,000-bbl/d shale oil industry). several ways. Water could be transferred directly to the area, either exclusively for oil The transfer of water from another hydrologic basin could have detrimental impacts on *The cost of supplving water by interbasin transfers is estimated to be no more than 5 percent of the total cost of produc- that basin, and impact analysis should pre- ing a barrel of shale oil. cede diversion.

Chapter 9 References

1T. D. Nevens, et al., Predicted Costs of Environ- Development Plan, Oil Shale Tract C-a, report sub- mental Controls for a Commercial Oil Shale indus- mitted to the Area Oil Shale Supervisor, Grand try: Volume 1, An Engineering Analysis, Depart- Junction, Colo., May 1977. ment of Energy, Washington, D. C., July 1979, 8Rio Blanco Oil Shale Project, Supplemental Ma- 2R. E. Hicks and R. F. Probstein, “Water Man- terial to Revised Detailed Development Plan, Oil agement in Surface and In Situ Oil Shale Process- Shale Tract C-a, report submitted to the Area Oil ing, ” paper No. 39e, 87th National Meeting of the Shale Supervisor, Grand Junction, Colo., Septem- AIChE, Boston, Mass., August 1979. ber 1977. 3Colony Development Operation, An Environ- 9Eyring Research Institute and Sutron Corp., An mental Impact Analysis for a Shale Oil Complex at Analysis of Water Requirements for Oil Shale Parachute Creek, Colorado, vol. I, Denver, Colo,, Processing by Surface Retorting, report TID- 1974. 27954, Energy Research and Development Admin- 4J. M. McKee and S. K. Kunchal, “Energy and istration, Washington, D. C., Aug. 5, 1976. Water Requirements for an Oil Shale Plant Based 10R. F. Probstein and H. Gold, Water in Synthet- on Paraho Processes, ” Colorado School of Mines ic Fuel Production: The Technology and Alterna- Quarterly, vol. 71, No. 4, October 1976, pp. 49-64. tives, MIT Press, Cambridge, Mass., 1978. ‘C-b Shale Oil Venture, Oil Shale Tract C-b Mod- 1lGolder Associates, Inc., Water Management ifications to Detailed Development Plan, report in Oil Shale Mining: Volume 1, report prepared for submitted to the Area Oil Shale Supervisor, the U.S. Bureau of Mines, Washington, D, C., NTIS Grand Junction, Colo., February 1977. No. PB-276 085, September 1977. ‘The Ralph M, Parsons Co., “Water Flow Dia- 12Cameron Engineers, Inc., Draft Working gram for Treatment of Mine Drainage Water,” Paper for a Case Study of Oil Shale Technology: personal communication to Water Purification Oil Shale Retorting Technology, prepared for Associates from C-b Shale Oil Venture, July 1978. OTA, Washington, D. C., March 1978. ‘Rio Blanco Oil Shale Project, Revised Detailed “University of Oklahoma, Energy From the 414 ● An Assessment of Oil Shale Technologies

West: Policy Analysis Report, prepared for the En- “Supra No, 23, at p. 9-69. vironmental Protection Agency, report No, EPA- “R. F. Probstein, H. Gold, and R. E, Hicks, 600-7-79-083, Washington, D. C., March 1979. Water Requirements, Pollution Effects, and Costs 14U.S. Bureau of Reclamation, Critical Water of Water Supply and Treatment for the Oil Shale Problems Facing the Eleven Western States— Industry, prepared for OTA by Water Purifica- Westwide Study: Volume I, Main Report, NTIS No. tion Associates, October 1979, p. 43. PB-263 981, Denver, Colo., April 1975. “H. Gold, D. J. Goldstein, and D. Yung, “The Ef- 15Colorado Department of Natural Resources, fect of Water Treatment on the Comparative The Availability of Water for Oil Shale and Coal Costs of Evaporative and Dry Cooled Steam-Elec- Gasification Development in the Upper Colorado tric Generating Plants, ” Proceedings of the River Basin—Summary Report (Draft), Denver, WWEMA 1977 Industrial Pollution Conference. Colo., November 1979. ‘“F, B. Suefert, et al., Conceptual Designs for 16Supra No. 5. Water Treatment in Demonstration Plants, De- 17Supra No. 7, partment of Energy, Washington, D, C., 1979. 18 Supra No. 9. %upra No, 34, at p. 36. ‘YE. F. Bates and T. L. Thoem (eds), Pollution ‘8Geraghty and Miller, Inc., Issues Relative to Control Guidance for Oil Shale Development, Re- the Development and Commercialization of a Coal vised Draft Report, Environmental Protection Derived Synthetic Liquids Industry, Volume 111-3: Agency, Cincinnati, Ohio, July 1979. Availability of Water for the Development o_f a 20K. W. Crawford, et al., A Preliminary Assess- Coal Liquefaction Industry, report No. FE- ment of Environmental Impacts From Oil Shale De- 1752-18, submitted to the Hudson Institute, Inc., velopment, report No. EPA-600/7-77-069, Environ- Croton-on-Hudson, New York, May 1977. mental Protection Agency, Cincinnati, Ohio, July %upra No. 13, at p. 100. 1977. ‘oF. Sparks, “Water,”’ Rocky Mountain News, 21W, J. Ramsey, I. Y. Borg, and R, L. Thornton, editorial, Aug. 2, 1979. Institutional Constraints and the Potential for Oil “lSupra No. 24, at p. 153. Sha]e Development, report No. UCRL-52468, Law- ‘zColorado Department of Natural Resources, rence Livermore Laboratory, University of Cali- Upper Colorado River Region Section 13[a) Assess- fornia, Livermore, Calif., July 1978. ment: A Report to the U.S. Water Resources Coun- “J. B. Weeks, et al., Simulated E~~ects of Oil- cil (Summary Report), August 1979, p. 1 xi. Shale Development on the Hydrology of Piceance ‘iC. W. Stockton and G. C. Jacoby, “Long-Term Basin, Colorado, professional paper 908, U.S. Geo- Surface-Water Supply and Streamflow Trends in logical Survey, Washington, D. C,, 1974, p. 1. the Upper Colorado River Basin Based on Tree- “Colorado Department of Natural Resources, Ring Analyses, ” Lake Powell Research Project Upper Colorado River Region Section 13(a) Assess- Bulletin No. 18, March 1976. ment: A Report to the U.S. Water Resources Coun- “National Academy of Sciences, Mining and cil (Draft), January 1979, p. 3-26. Processing of Oil Shale and Tar Sands, Washing- “’’Statement of Roland Fischer, Secretary- ton, D. C,, 1979, p. 104, Engineer, Colorado River Water Conservation ‘5 Supra No. 42, at table 10-7. District, Glenwood Springs, Colorado, ” Hearings “U.S. Bureau of Reclamation, Impacts on the on Water Availability for Energy Development in Lower Colorado River Region Resulting From the West, Subcommittee on Energy Production Alternative Levels of Emerging Energy Develop- and Supply of the Senate Committee on Energy ment in the Upper Colorado River Region (Draft), and Natural Resources, 95th Cong., 2d sess., September lg7g, p. 17. March 1978, committee print 95-134, p, 146. ‘7 Supra No, 46, at p. 24. %upra No, 23, at p. 8-17. “Economic Impact of the Oil Shale Industry in “)Ibid. Western Colorado, Subcommittee on Public Lands “Ibid. of the Senate Committee on Interior and Insular a ‘ Ibid., p, 8-14, Affairs, 93d Cong,, 2d sess., Jan. 19, 1974, p, 110. “Cameron and Jones, Inc., Synthetic Fuels ‘gSupra No. 44. Quarterly Report, vol. 5, No. 1, March 1968, pp. 50E, E. Hughes, et al., Oil Shale Air po]~ution con- 1-28. trol, report prepared for EPA by Stanford Re- 30Supra No. 13, at p. 156. search Institute, May 1975. “Supra No. 23, at p. 9-63. Sluniversity of Wisconsin-Madison, Oil shale %upra No. 11. Development in Northwestern Colorado: Water and Related Land Impacts, Madison, WJis., July %upra No. 42, at p. xc, 1975, p. 225. ‘>’’ Bureau of Land Management, Dra_ft Environ- “Department of the Interior, Final Environmen- mental Statement—Proposed Superior Oil Compa- tal Statement for the Prototype Oil Shale Leasing ny Land Exchange and Oil Shale Resource Devel- Program, GPO stock No. 2400-00785, Washington, opment, Department of the Interior, 1979, p. 70, D. C., 1973, p. 111-76. ‘)lSupra No. 23, at p. 9-79. ‘) Bureau of Land Management, Draft Environ- “2Supra No. 13, at p. 148. mental Impact Statement—Proposed Devel- ‘){ Hearings on Water Availability for Energy De- opment of Oil Shale Resources by the Colony De- velopment in the West, Subcommittee on Energy velopment Operation in Colorado, Department of Production and Supply of the Senate Committee the Interior, Dec. 12, 1975, p. IV-91. on Energy and Natural Resources, 95th Cong,, 2d %upra No. 46, at p. 21. sess., March 1978, committee print 95-134, p. 26. ‘%upra No, 48. “Ibid., at p. 62, %upra No, 51, at p, 20. ‘%upra No, 42, at p. 4-4, “Supra No, 15, at p. xiii. ‘Wupra No, 22. “3Supra No, 42, at p. 1 xxxviii. CHAPTER 10 Socioeconomic Aspects Page Page Introduction ...... 419 95* AllocationofOilShaleTrust Funds, Fiscal Years 1975-80 ...... 438 420 The Setting ...... 96. SelectedFederalProgramsUsed by Historical Background ...... ,420 WesternStatesforAssistance With The Oil Shale Country Today ...... 421 SocialandEconomicEffectsofEnergy Early Planning for Oil Shale Development. , , .423 Development...... 439 Mechanisms to Manage Growth ...... 426 97. PopulationGrowthofColorado Oil Local Infrastructures...... 426 ShaleCounties, 1970-77...... 447 Private Sector Contributions ...... 429 98. PopulationofColoradoCommunities State Programs...... , 430 AptToBeAffectedbyOilShale Evaluation of State and Local Mechanisms. ., 436 Development 1977...... 448 Federal Programs...... 438 99. SelectedDemographicIndices ofOil ShaleCountiesofColorado,July1975.. 448 PossibleConsequencesofOil 100. PopulationProjectionsbyDevelopment ShaleDevelopment...... 443 ScenariofortheOilShaleCounties of GeneralEffectsofRapidPopulationGrowth...... 443 Colorado ...... 449 AnticipatedGrowthintheColorado Oil 101. ProjectedPopulationGrowth of ShaleRegion ...... 447 Selected Oil ShaleCommunities, Needs Arising FromAnticipatedGrowth ....449 1979-85...... 451 Needs From Oil ShaleDevelopment...... 452 102. PriorityNeedsIdentifiedby OilShale PotentialEffectsofAccelerated Development 460 Counties andCommunities, 1980-85 . . . 460 Issues andPolicyApproaches ...... 462 103. ActualandProjectedPopulation and SummaryofIssues ...... 462 EstimatedCapacityofOilShale PolicyApproaches ...... ,464 CommunitiesinColorado...... 460 1040 SelectedPolicyOptions, 1978Reportto Chapter l0References...... 470 thePresident ...... 466 List of Tables List of Figures TableNo. Page 87. ComparisonofBasicto Local Service Figure No. Page EmploymentMultipliers...... 424 69. CountiesoftheOilShale Region .,.... 422 88. BaselineData-Selected Social 70.Communities intheColorado OilShale andEconomicStudies ...... 425 Region...... 423 89. ImpactData—Selected Social and 71. Energy-RelatedEmployment, Tax EconomicStudies ...... 427 Revenues, andNeedforPublic Services 90, RevenuesoftheColoradoOilShale in an AreaAffectedbya Large-Scale TrustFund, FiscalYears 1975-79 . . . . . 432 EnergyDevelopment ...... 444 91. ExpendituresoftheColorado OilShale 72. PopulationProjections forColoradoOil TrustFund,FiscalYears 1975-80 . . . . . 432 Shale Counties byDevelopment 92. AppropriationsFromthe OilShale Scenario, 1980-2000 ...... 450 FundsbyObject,FiscalYears 1975-80. 433 73. PopulationProjectionsfor SelectedOil 93. Projects Funded by the Colorado Oil ShaleCommunitiesinColoradoby ShaleTrustFund, 1975-80...... 434 DevelopmentScenario, 1980-2000 . . . . 451 94. Wyoming Programs to Mitigate Social 74. ProposedRoadFromRangely to and Economic Impacts...... 437 TractC-a. . ., ., ...... 456 CHAPTER 10 Socioeconomic Aspects

Introduction

An oil shale industry will bring new people Time, money, and technical help are into the oil shale region. As a result, the social needed to ameliorate the detrimental aspects fabric will be changed in ways both benefi- of sudden growth. Communities need time to cial and detrimental, Growth problems aris- catch up, particularly if extensive construc- ing from the simultaneous development of oil tion of private and public facilities—such as shale and other energy resources are likely to housing and water and sewer systems—is in- be more difficult to solve than those from volved. Both Federal and State governments shale development alone. and oil shale developers are providing impact

2 mitigation funds and technical support, To The 3,200-mi area where near-term development will take place is rural and sparsely date in Colorado, upwards of $50 million of populated. The three counties in Colorado public and private funds have been invested in preparations for shale development have only one community with over 5,000 residents. Even without expansion of the oil growth. Programs to administer these resources have been successful, but they have shale industry populations are projected to increase significantly. If a major oil shale in- yet to be tested under conditions of sustained rapid growth. Assuming that present plans dustry is created within the next two decades can be realized in a timely fashion, a total of there could be average growth rates of up to 40 percent per year in the early stages of de- about 35,000 people could be accommodated in existing communities in the 1985-90 period. velopment. Such a rapid population influx Any development that brought more than this would have inevitable social and economic number into the area would cause wide- consequences. Among the benefits would be increased employment and expanded commu- spread problems unless the growth were nity services. Direct employment in the shale carefully timed to the region’s ability to ac- industry and the stimulation of support indus- cept the new migrants, or plans for additional new communities were quickly implemented. tries and services would increase wages. The larger tax base would permit the counties and municipalities to extend and upgrade The maximum growth rate that can be sus- their facilities and services. As long as the tained by these communities before boom- public and private sectors could keep pace town symptoms emerge, and the nature of the with the growth, most residents probably appropriate Federal role with regard to so- would welcome it, Among the negative conse- cial and economic impacts are major issues. quences could be a strain on public services The Federal Government now is involved with and facilities, an increase in crime and other impact identification, evaluation, and mitiga- manifestations of social stress, certain pri- tion, but additional activities are controver- vate-sector dislocations such as business fail- sial, Possible congressional policy options ures, and in the eyes of some, a deterioration would be to continue present financial sup- in their quality of life. If these negative out- port to mitigation programs, to increase ef- comes overwhelm the capacity to adjust, a forts to manage growth through regulation, boomtown situation would result, similar to and to expand Federal involvement in mitiga- what has happened in other western and tion programs, including passage of new leg- plains communities during the rapid develop- islation directed to energy development in ment of energy resources, general or to oil shale impacts in particular.

419 —

420 ● An Assessment of Oil Shale Technologies

The Setting Historical Background treaty was ratified by Congress in 1880. Under its terms, the White River Utes were Oil shale country covers about 17,000 mi2 given land in Utah in the southern part of the in the tristate area of Colorado, Utah, and Uintah Indian Reservation to which they were Wyoming. (See ch. 4 for a description of the removed in September of 1881. Congress de- geography of the region.) Archeological evi- clared the former Ute lands as public domain dence reveals that people probably have lived on June 28, 1882. there for at least 10,000 years. ’ The ances- While the ownership questions were being tors of today’s Ute Indians arrived at an as debated, squatters appropriated some land il- yet undetermined time. The Utes were a no- legally. In 1879, when miners founded Car- madic people who lived in a few permanent bonate in the Flattops area north of Glenwood settlements and had many scattered hunting Springs, Colo., they displayed their aware- camps. The earliest direct contact between ness of this by naming their first building Fort these indigenous people and Europeans was Defiance. Coal camps were established west most probably with Spanish explorers, and of Glenwood Springs along what came to be British and French fur trappers and traders. known as Coal Ridge Hogback. While silver Trade between the Indians and the Euro- and gold lured the miners, the rich grasslands peans existed from the 1600’s onward. attracted cattle and sheep raisers. Large In the late 1700’s and early 1800’s, contact beef herds roamed free; one in 1888 was with Western explorers, traders, hunters, numbered at 23,000.5 The great runs lasted and trappers increased. In 1776, the Esca- until the turn of the century, when they lante-Dominguez expedition passed through became uneconomic owing to severe winters the region in search of an overland route to combined with overgrazing. 2 California. In 1868, John Wesley Powell led a Ranching, mining, and recreation became party across Berthoud Pass, into Middle the economic cornerstones of the region. Al- Park, and eventually to the White River val- though no great precious metal strikes were ley. A small group wintered at a site near made, coal mining formed a stable industry Meeker, Colo., which is now called Powell’s ) for many decades. Coal was produced for the Park. The number of people entering the railroads and for the steel mills of Pueblo, area rapidly increased during the mining Colo. (See ch. 4 for the history of oil shale and boom of the mid-1800’s. Settlement was made related mineral exploration. ) Farms and easier when transportation was improved. ranches were established as homesteading The Denver and Rio Grande Western Rail- flourished. Hay production in the valleys road obtained the route through the Colorado became profitable, especially with the advent River valley to Salt Lake City. The Colorado of irrigation. The visits of Theodore Roosevelt Midland and the Denver and Salt Lake City to the Flattops area in the early 1900’s, with railroads explored the White and Yampa their attendant publicity, gave impetus to River valleys as alternative routes, although tourism.’ Communities grew, with Rifle, neither was built, Meeker, and Rangely, Colo., as centers of The United States obtained title to the land trade. The town of Meeker was incorporated as part of the Mexican Cession of 1848. From in 1885. A trading post was built at the loca- the time of the Cession until the 1880’s the tion of Rangely in the early 1880’s. Oil was United States engaged in a number of treaty discovered nearby in the early 1900’s and negotiations and councils with the Indians.4 production began in the early 1920’s. Smaller The treaties ceded the mineral lands to the communities sprang up along the valleys. United States and established reservations West of Rifle, the town of De Beque was infor the different bands of Utes. The final corporated in 1890. Grand Valley, founded in Ch. 10–Socioeconomic Aspects Ž 421

1882, soon became a farming center. To the several energy companies. Interstate 70 (seg- east of Rifle, New Castle was the hub of the ments of which are not yet completed) ex- coal communities. Many of the residents to- tends eastward up the valley of the Colorado day are descendants of the early settlers, Oil River and westward into Utah; it is 260 high- shale country, therefore, is an area with way miles to Denver and 285 to Salt Lake stable communities populated by many long- City. The only airport on the western slope established families. able to accommodate commercial jets is in Grand Junction. The Denver and Rio Grande The Oil Shale Country Today Western Railroad also has extensive facilities there. Agriculture, mining, and recreation have z Garfield County lies adjacent to Mesa continued as the main economic activities. County on the north. It encompasses the Roan Livestock grazing is the leading agricultural Cliffs along the southern border of the Roan use, followed by dry land farming, and irri- Plateau, and is the site of most of the private gated cropland production. Hay and winter oil shale holdings. The Colorado River flows wheat are major crops. The best irrigated through the eastern part of the county, and land is in Mesa County, Colo., outside the im- transportation is readily available along this mediate oil shale area, where orchards have corridor. Glenwood Springs, the county seat, long been established. Mineral resource pro- is located in the eastern portion. Rifle, Grand duction, mostly oil and gas, and recently coal, Valley, Silt, and New Castle are communities constitutes the major mining activity. Tour- affected by the present modest scale of oil ism, fishing, and hunting have long been the shale development. Rifle is the home of many mainstays of the recreational sector, and oil shale workers from tracts C-a and C-b. A with the expansion of winter sports areas in vanadium plant is located nearby, and coal the mountains, year-round recreation has development activities have recently in- become important. In recent decades, trade, creased along the valley. The Naval Oil Shale manufacturing, and construction industries Reserve at Anvil Points lies between Rifle and have grown, along with public and private Grand Valley. If present trends continue, the services. Economic indices, such as retail Rifle vicinity will experience the most growth. sales and per capita and family income, have reflected a steady economic growth. a Rio Blanco is the county most likely to experience the major effects of expanded oil The oil shale region encompasses about shale development. Lying between Garfield eight counties. (See figure 69. ) In Colorado, and Moffat Counties, it is where the richest these are Rio Blanco, Garfield, and Mesa; oil shale deposits in the United States are some social and economic effects from ex- located. Most of these are on Federal lands in panded oil shale development may also be felt the Piceance basin. Rio Blanco is the least in Moffat County, north of the Piceance basin. populated of the three, and has the most lim- The counties in Utah that will be affected are ited surface transportation. The White River Uintah, Daggett, Grand, and Duchesne. The 2 flows along the northern part; the two major tricounty area of Colorado covers 9,563 mi , communities, Meeker (the county seat) and has a limited transportation system, and in- Rangely, lie within the river valley. Rangely is cludes about a dozen communities that could a center for oil and gas development activ- be affected by oil shale industry expansion, ities. The primary north-south highway goes (See figure 70.) from Rifle through Meeker and Craig and Stretching along the southern edge of oil then on to Wyoming. The main east-west road shale territory, Mesa County is the transpor- goes from Meeker to Rangely, before turning tation and service center for the western north to Dinosaur, where it passes into Utah. slope of Colorado. Grand Junction, the largest A State highway goes south from Rangely city of the region, is the site for the offices of through Garfield County and eventually to — —

422 . An Assessment of 0il Shale Technologies

Figure 69.—Counties of the Oil Shale Region

A CROOK I w .

L- .- 1 “1 Q** e- 0° . I ●

w x o I. 1: -./1-. . *I

—— —

--l i

SOURCE The Natlona/ At/as, Department of the Interior

Grand Junction. A county road extends along approximately doubled in the past decade the Piceance Creek valley and another goes with most of the growth centered in Craig. eastward from Meeker up the White River Coal development and the construction of a valley to recreation areas. These are the only 2 760-MW coal-fired electric generation plant improved roads to serve the 3,263 mi of Rio account for most of the expansion, which is Blanco County. expected to continue with a possible doubling in the size of the powerplant. Because Moffat Moffat County, which occupies the ex- County lies to the north of the principal oil treme northwest corner of Colorado, abuts on shale areas, it will probably only experience Wyoming to the north and Utah to the west. indirect effects from shale development. The Its county seat, Craig, is in the east-central town of Dinosaur, however, which is located portion. The population of Moffat County has 18 miles northwest of Rangely in the extreme Ch 1O–Socioeconom/c Aspects ● 423

Figure 70.—Communities in the Colorado Oil Shale Region

VERNAL 32 mi.

——_———— ———— r 4 —J

— — — ‘“F s u — — — — — — — — — — — — —.” —

JUNCTION

SOURCE 0il Shale Tracf C-b SOCIO Ecomnic Ajssessment 76 VOI II southwestern corner of the county, could be growth from expansion of the shale industry directly affected. It has already grown from will most likely take place in the least popu- oil and gas exploration, and oil shale activ- lated county, Rio Blanco, which contains the ities in Utah as well as the Piceance basin richest oil shale deposits. Garfield County is could further accelerate its growth. apt to experience major impacts from its growth. In sum, the oil shale region of Colorado, Utah, and Wyoming is a large area with a Early Planning for Oil Shale Development small population. Most of the residents are found in widely separated communities that Concern about the social and economic ef- are linked by a few highways. Before the re- fects on Colorado communities of large-scale cent increase in energy-related industrial ac- oil shale development was expressed in the tivity, the main economic base was ranching late 1960’s.9 As a result, planning activities and farming, supplemented by tourism, recre- began in the early 1970’s. The environmental ation, and mining. A large number of new res- impact statement (EIS) filed in conjunction idents have migrated to Moffat County, to the with the Prototype Leasing Program exam- north of the oil shale region. The fastest ined some social and economic elements. 424 ● An Assessment of Oil Shale Technologies

However, its lack of detail prompted industry to prepare socioeconomic monitoring reports to take the initiative to undertake additional and to work with local citizens on strategies analysis. In 1972, an Oil Shale Regional Plan- for managing growth. The lessees were also ning Commission was formed, which took an members of a private development, the Col- inventory of the area and of shale technol- ony project. Several socioeconomic reports ogies. Contracts with consulting firms pro- were prepared as part of this joint effort,l4 duced several planning documents. ’” The re- and, under the direction of Atlantic Richfield, sponsibilities of the Commission were as- early plans were prepared for Battlement sumed later by the Colorado West Area Coun- Mesa, a proposed new town to accommodate cil of Governments (CWACOG). An aware- workers from the Colony project. ’5 ness of the need to prepare for growth The tracts C-a and C-b lessees each con- prompted these early planning efforts, but as work proceeded, an atmosphere of uncertain- tributed $40,000 to help establish the Rio ty arose. When the lessees requested suspen- Blanco County Planning Department. The money was used to prepare a comprehensive sions, expansion of the oil shale industry be- plan that was adopted and certified to the came questionable in the minds of many who were charged with the responsibility of pre- communities in the latter part of 1976. Both groups of lessees funded development of a paring for its consequences. ” growth-monitoring model by CWACOG, and Local programs to minimize possible ad- the original tract C-b partners and one of the verse affects were begun after the leasing of C-a partners participated in the preparation tracts C-a and C-b. The C-a lessees, Rio Blan- of a tax study. Planning was also underway in co Oil Shale Co. (Gulf Oil and the Standard Utah between 1970 and 1975. For example, in Oil Co.—Indiana), prepared an impact anal- 1975 a socioeconomic analysis was published ysis for their operation. ’2 They hired a con- by the White River Shale project that dealt sultant, the Foundation for Urban and Neigh- with the effects of the proposed development borhood Development (FUND), to survey com- of a 100,000-bbl/d industry in Utah. 16 munity attitudes toward energy development in Rangely, Meeker, and Rifle. The lessees The value of the early studies varied be- also engaged a planning firm, the Gulf Oil cause each had a different emphasis, cover- Real Estate Development Co. (GOREDCO), age, and set of basic assumptions. Comparing that—with the participation and direction of the multipliers used to derive projected the community—prepared a comprehensive growth illustrates these differences. To ob- development plan for Rangely. The master tain an estimate of new employment fostered plan was completed in 1976 and subsequently by a project (local service employment), the adopted by the town, certified to the county, expected work force for the project (basic and incorporated in the county plan. Through employment) is multiplied by some factor FUND an attorney was engaged to update (multiplier). Table 87 compares the multipli- and codify Rangely’s municipal ordinances. Table 87.–Comparison of Basic to Local Service The lessees also contributed to the improve- Employment Mutipliers ment of the county road leading to tract C-a, — and paid for the design and preparation of Multipliers used Construction Operating cost estimates for a 22-mile extension from a the tract more directly to Rangely. IIlustrative study phase phase 1. Prototype EIS. 63 77 In 1976, the lessees of the C-b tract (at that 2. C-a (Rio Blanco) Social & Economic Statement . 5 5 time consisting of Ashland, Atlantic Richfield, 3 C-b Soclo-Economic Assessment 5 to 1 0 15 Shell, and Tosco) published a baseline de- 4. Colony EIS. ., .29 97 scription and an impact analysis study. ’3 Like 5. Uinta Basin Study 3 to 10 10 to 1.5

the tract C-a lessees, they hired a consulting d~ee (e! 1 T for iUII htle of the sludles firm, Quality Development Associates (QDA), SOURCE Of ftce of Technology Assessment Ch. 1O– Socioeconomic Aspects Ž 425 ers used in five of the early studies,17 These The differences occurred for several rea- vary so much that a single increment of em- sons. In the EISs, socioeconomic factors re- ployment can result in a twofold to threefold ceived little emphasis because at that time difference in the projected populations. (The they were not considered—as is now the case five studies are compared in greater detail in —essential to environmental impact analysis. tables 88 and 89. ) In general, the EISS assumed that existing

Table 88.–Baseline Data–Selected Social and Economic Studies (each dot indicates the inclusion in the study of this category of data) —. — Title of studyb C-a social C-b a Data categories Prototype EIS and economic— socioeconomic Colony EIS Uinta Basin Existing economic/demographic data Population and employment County population ● ● ● ● ● Number of households by county ● ● ● ● Number of households by community ● Labor participation by county ● ● ● ● ● Education Enrollment by county ● Enrollment by school district Enrollment by city ● Student/teacher ratio ● ● ● Median school years attained ● ● Dropout/turnover rates ● Employment by industry Total employed–sector by county ● ● Total employed–sector by city Total employed–sector by region ● Employment–other energy Industry Family/lndwldual Income Indicators Median family Income by county ● ● ● Per capita Income by county Unemployment rate by county ● ● Poverty status by county ● ● Rate of population growth By county and community ● ● ● Projected without 011 shale ● ● ● Existing public services/facilities Education Age of school buildings by district Certified staff Excess pupil capacity 9 Public safety Fire/pollee protection by area Manpower/number of vehicles Water Estimated depletion (1970) by region ., ● Status of projects by State ● Source, storage capacity, number of taps per population served by community ● Status of water rights ● Wastewater and solid waste disposal Treatment facilities by community type/population served/design capacity ● ● ● Transportation Existing roads/airports by county ● ● ● Status of current projects ● Average weekday traffic counts ● Health Facilities/manpower by county ● ● ● ● Mental health facilties ● ● Recreation and land use Resource Inventory ● 426 ● An Assessment of Oil Shale Technologies

Table 88.–Baseline Data–Selected Social and Economic Studies –continued

Title of studyb C-a social C-b a Data categories Prototype EIS and economic socioeconomic Colony— EIS Uinta Basin Recreational facilities by type Land by ownership by county Agricultural land by county Government structure/fiscal information County/municipal government finance Revenues and expenditures by county ● ● Municipal revenues and expenditures ● ● Property tax valuation, average mill levy, and total levy by county ● ● Distribtion of levy revenues by county ● Sales tax Information ., ● Retail trade information ● School district finances Total expenditures by county. ● Total and per capita expenditures by districts ● Comparison of per pupil expenditures and mill levies by districts ., MiII levy by fund. assessed value revenue by source, by district Bonding principal and remaining capacity Housing Inventory and costs Estimated housing by county ● ● Status of available units by type ● ● Value of owner-occupied units. ● ● Value of other units Projected needs by tenure by county Characteristics by type by city ● Public opinion Local opinion regarding Socioeconomic environment and quality of life ., ● ● Attitudes about changes In quality of life and society. ● ● ● ● Attitudes about perceived advantages/disadvantages of 011 shale development ●

dBala ~ategorles are for Il[ustra[lon NO a!tempt has Deen made 10 Include all of the !nformallon In these studies Dsee ~ef I 7 for Ilsf(ng of full Ilfle

SOURCE Olflce of Technology Assessment mechanisms could deal with most conse- were not made a part of the C-a analyses be- quences of growth. When it became apparent cause they were in the Rangely master plan. they could not, subsequent studies went into Little attention was paid in any of the studies greater detail about the effects of the ex- to other resource development projects an- pected growth and possible remedial actions. ticipated or underway in the region. As a Not all of the studies, however, included the result, all of them are deficient in analyzing same types of information. For example, com- the cumulative effects of industrial expan- munity facilities and local government data sion.

Mechanisms to Manage Growth Local Infrastructures Rangely, Rifle, and Grand Junction have full- time city managers, and Grand Junction and In Colorado, Garfield, Rio Blanco, and Rifle have city planners. Rio Blanco County Mesa Counties all have planning councils, has adopted an ordinance applying to land professional planning staffs, and approved use that, in certain circumstances, requires countywide comprehensive plans. Meeker, filing an impact analysis statement specifying Ch. 10–Socioeconomic Aspects Ž 427

Table 89.–impact Data–Selected Social and Economic Studies (each dot indicates the inclusion in the study of this category of data)

Title of studyb C-a social C-b Impact categoriesa Prototype EIS and economic socioeconomic Colony EIS Uinta Basin Population/employment projections Total basic population projections ● ● ● ● ● Project-related employment projectionc ,. ● ● ● ● ● Estimated family size for construction and service populations ● ● ● ● ● Timelag included for local service employment forecasts ...... ,. ● ● ● Estimation of community choice for residence and allocation of population ● ● ● ● Community facilities/services projections Education Site and plant costs, personnel needs, salary requirements ● Projected numbers of pupils and room requirements. ● Projected increase in demand for teachers and classrooms Public safety Fire and pollee needs and costs ● ● Cumlative impact on faci!ities and personnel ● Water Expected needs by technology ● Needed Improvements and estimated costs–one municipal system Projected site, plant, personnel, and salary requirements ● Capacity and expansion by towns, depletion by sector by region Solld waste disposal and wastewater ● ● Transportation ● ● Health ● Mental health ● Recreation Land loss by State by technology ● Projected open space and recreational needs and costs ● New sites and facilities needed (project development area) ● Local government fiscal need projections School district financing needs ● County and municipal government finances Estimated Federal, State and local revenues by tax source by State ● Projected total revenues and expenditures, by tax source/per capita ● ● Facility and personnel costs, valuation and taxes levied ● Impact by development pattern or project phase ● ● Housing Projected housing requirements Types needed by development phase ● ● Demand by community...... ● ● Land use requirements by units per acre, total units, and type ● Public construction expenditures and tax receipts by State ● Recent construction by communities ●

a mPacl Cdleqorles are ‘or III usfra!lon OPI y No atlem Df has Deen made 10 Include al’ of lhe Intormatlon avd(lablc In these st( IdIP$ bseel ,e; I j’ for a Ihstlng Of fdll tl[ c cSee [ext for a Otscusslon of Ihe elf ferences m the projecl(ons as d Iuncllon of the multlp.lers used In each study dsee ~exl for an explanation of Irle lac~ Of IIfoma!oo for Ine C a socia dnd econom~c study column

SOURCE Off Ice of Techno ogy Assessment actions that will be taken to alleviate any try representatives, their consultants, and adverse effects of changes in land use.18 county officials, and consists of about 30 members organized into a core group and two In the early planning stages, special groups advisory panels. The core group, which meets were created in Rio Blanco and Mesa Coun- monthly, is composed of the county commis- ties and the Rifle area. The most active, sioners; the city manager and mayor from the called the Impact Mitigation Task Force, is in two municipalities, Rangely and Meeker; and Rio Blanco County. It was initiated following representatives from industry, the Federal a series of informal meetings between indus- and State governments, and CWACOG. It has 428 . An Assessment o/ 011 Shale Technologies

Photo credit OTA staff Monthly meeting of the Rio Blanco County Impact Mitigation Task Force been officially designated to serve in an ad- out through the Rifle planning and adminis- visory capacity to the county commissioners. trator’s offices. In the fall of 1979, the orga- One advisory panel represents Meeker and nization was enlarged to involve other com- the eastern part of the county, the other munities along the Colorado River valley. The Rangely and the western portion. Many dif- core group was broadened to include all of ferent interests are reflected, including agen- the county commissioners and represent- cies such as the sanitation district and the atives from each of six towns. To advise the public schools, and less formally organized core group, a West Garfield Impact Commit- groups such as youth. The advisory panels, tee was created composed of 19 voting mem- which also meet once a month, discuss differ- bers chosen to represent a wide range of in- ent growth-related topics, and forward their terests. The Impact Committee will undertake concerns to the core group. They have pre- planning activities and recommend to the pared needs assessments on a variety of gen- core group which projects they support for eral subjects and have reviewed specific submission to the State for funding assist- issues such as housing for teachers. ance. Prior to the establishment of this process, requests were made through the cities The Rifle area organization was formed in directly to the county commissioners. mid-1977 with a core group and series of In December 1977, Mesa County organized working panels. When first established, it an Impact Assistance Team. Fifteen mem- was called the Development Impact Commit- bers, representing local, State, and industry tee, and consisted mainly of Rifle residents. A interests, review funding requests made to county commissioner from the area was a the county commissioners. Applicants must member but countywide communication was provide information to the team justifying not extensive. Most of the development and their requests. Responsibility for setting planning management activities were carried priorities rests with the commissioners. Ch. 1O–Socioeconomic Aspects ● 429

The Functions of the Local Planning Processes plications for financial assistance validates the process and formalizes the responsibility. The work of the special groups has centered around three areas: physical planning This consideration of the functions of Col- and development, information generation and orado’s local planning mechanisms illustrates transfer, and screening and placing priorities several general questions related to socioeco- on requests for funding. As an illustration of nomic effects. Among them are: the first function, the Rio Blanco advisory and Ž Who identifies the consequences of core groups, using population forecasts pro- growth? vided by CWACOG, have reviewed the ability ● Who judges whether these are positive of local public facilities, such as sewer and or negative? water systems, to handle larger loads, and ● Who determines which ones require re- have helped plan expansions where appropri- dress? ate. Needs for housing, schools, recreational facilities, and downtown redevelopment have Local entities address all three questions in also been considered. Each planning group the model presently operating in Colorado. In has struggled with the implications of com- some instances, these are established govern- prehensive land planning for its region. mental units, such as planning offices; in others, unique panels with broad community Because energy development often involves representation. The latter arrangement has uncertainties about factors such as the timing several advantages. It allows individuals of construction and the size of work forces, close to the communities to judge the balance obtaining accurate information is important between positive and negative impacts, and to officials and residents, The best estimates provides an opportunity for citizens with dif- available are required and, in this regard, ferent interests to propose solutions to local most groups receive frequent updates from problems, Many share the responsibility of industry representatives about the status of deciding which difficulties are severe enough their projects. Sharing information also in- to require assistance beyond that available volves communication between local officials from local resources. The assumption under- and citizens. The advisory groups provide a lying the model is that those affected should public forum for the presentation, analysis, have the prerogative of deciding what a nega- and discussion of issues, which allows indi- tive impact is and how it might be amelio- viduals to help determine future growth pat- rated. terns. The core groups, especially when screening requests for impact mitigation funds, help establish a consensus among local Private Sector Contributions interests on priorities and policies. Throughout the West, energy development An important function of each group is rec- industries are contributing significantly to ommending to their respective county com- growth management.19 As previously noted, missioners which project applications should several oil shale developers have voluntarily be forwarded to the Federal and State gov- contributed to projects in communities af- ernments for consideration for funding. The fected by their activities. The Rio Blanco Oil Rio Blanco County structure is unique in this Shale Co., for example, spent over $700,000 respect, The involvement of the task force in direct grants and purchases of services to core group and advisory panel members with assist the Rangely area and over $135,OOO in local officials, industry representatives, con- support of Rio Blanco County. The Colony De- sultants, CWACOG, State legislative and ex- velopment Operation invested about $3 mil- ecutive staff, and Federal agency personnel lion to acquire land and plan for the new broadly allocates responsibility for decisions. town of Battlement Mesa. Industry has also Having the task force place priorities on ap- adopted programs to deal with particular 430 . An Assessment of 0il Shale Technologies

problems. To reduce traffic and contribute to sistance to real estate developers for con- highway safety, the tract C-b lessees operate struction of apartment units in Rifle and buses for their workers from Rifle to the Meeker, and for a mobile home park in Rifle.20 tract. They have also provided financial as-

Photo credit OTA staff Apartment units in Rifle, Colo., developed with industry assistance

State Programs AGENCIES INVOLVED IN MITIGATION PROGRAMS Two State governmental groups are in- Colorado volved in Colorado’s programs for impact mitigation: the Division of Energy and Miner- Colorado’s programs largely involve finan- al Impact in the Department of Local Affairs cial and technical assistance. Financial support is directed to municipal, county, and pri- (DLA) and the Joint Budget Committee (JBC) of vate agencies with money obtained from two the General Assembly. main sources, lease revenues collected by the JBC is a legislative committee composed of Federal Government and severance taxes col- members from both houses of the Colorado lected by the State. Technical assistance is in General Assembly. It is responsible for draft- the form of information gathering and dis- ing the State budget and forwarding it to the semination, advisory services, program co- Assembly for final action. In 1974, the Gen- ordination, and similar support activities. eral Assembly created the State Oil Shale Ch. 10–Socioeconomic Aspects ● 431

Coordinator’s Office,21 which subsequently ments paid to the Federal Government evolved into the Governor’s Socio-Economic by the tract lessees. Under the bonus off- Impact Office (SEIO). SEIO, the lead agency set provision of the Prototype Leasing for coordination within the State government, Program, expenditures for certain devel- is now the Division of Energy and Mineral Im- opment work on the lease tracts can be pact in DLA. The Division reviews requests credited against the final two payments. for Oil Shale Trust Fund assistance (de- Since the lessees have proceeded with scribed below), and recommends projects for development, it is likely that 100 percent funding to JBC. It is also responsible for con- of the final two bonus payments will be tract negotiations and for administering ap- offset, and that, therefore, neither the propriations. The Division also handles miti- State nor the Federal Government will gation programs for communities experienc- receive any additional lease payments in ing boomtown impacts from other types of de- cash. (See table 90 for a summary of the velopment. DLA coordinates State and local Fund’s revenues.) mechanisms in several ways: The State statute creating the fund ● reliance on local and regional groups to specifies that the income shall be dis- take an advocacy role in presenting local bursed as follows: needs to State agencies, ● ... for appropriation by the General review of requests by State-level agen- Assembly to state agencies, school dis- cies involved with or that might be af- tricts, and political subdivisions of the fected by mitigation projects, and state affected by the development and ● administration of appropriations and production of energy resources from oil contracts through field representatives shale lands primarily for use by such in concert with local officials and con- entities in planning for and providing tractors. facilities and services necessitated by such development and production and Financial Assistance.– secondarily for other state purposes.24 Federal Revenues. —Under the provisions The Oil Shale Trust Fund is not techni- of the Mineral Leasing Act of 1920, as cally a trust since there is no statutory amended,22 each State receives 50 percent of requirement that the principal be kept the proceeds from the sale or lease by the intact. However, JBC has maintained the Federal Government of public lands within principal at approximately $60 million, the State. Colorado has created two distinct funds to receive these revenues: one for those returned from oil shale lands and another for those returned from lands other than oil shale. The former is called the Oil Shale Trust Fund and the Oil Shale Interest Earned Fund; the latter is the Colorado Mineral Leas- ing Fund.

● Oil Shale Trust Fund and Interest Earned Fund. Colorado’s Oil Shale Trust Fund 23 was created in 1974 to receive those revenues specifically coming from lease payments, royalties, and bonuses on the two Federal oil shale tracts in western Colorado. To date, the Oil Shale Trust Fund has received payments cor- Upgrading of facilities in Rangely, Colo., utilizing responding to the first three bonus pay- Oil Shale Trust Fund monies 432 ● An Assessment of Oil Shale Technologies

Table 90.–Revenues of the Colorado Oil Shale by the development, processing, or ener- Trust Fund, Fiscal Years 1975-79 gy conversion of minerals” that are Lease/bonus Interest Total annual leased from the Federal Government Year i ncomea earned income and/or that are subject to State sever- b 27 FY1975 ...... $24,607,020 0 $24,607,020 ance taxation. The State statute pro- FY1976 b ...... 24,607,020 $2,685,600 27,292,620 b vides for an automatic distribution of the FY1977 ...... 24,607,020 3,811,271 28,418,291 FY1978 b o 4,219,970 4,219,970 monies to the public schools, to the coun- FY1979 c ... .. ::. o 5,999,918 5,999,918 ties where the leased lands are located asee[ext for discussion ofoffsefllng prowstonsapplymglo 197879 (except that no county can receive more bSummaryafld S/afus Repoflo/ (fie Mlflera/ Lease amj Severance Tax Fund, Second Annual Re than $200,000 in any calendar year), to port lolhe Colorado Slale Legislature Eleparfmenl otLocal Affam 1979 cStatefreasurer sotflce the Colorado Water Conservation Board SOURCE Office of Technology Assessment Construction Fund, and to the Local Gov- ernment Mineral Impact Fund. and appropriations have been madeonly from interest earnings and from the State revenues.—In 1977 Colorado levied principal in excess of $60 million. The in- a severance tax on the production and export terest earned by the State is set aside as of metallic minerals, molybdenum ore, oil and 28 the Oil Shale Interest Earned Fund, a gas, coal, and shale oil. Proceeds are allo- special account established in 1975.25 cated to different accounts according to the Loans as well as grants from the interest mineral being taxed. To date, most of the in- fund are permitted; the authorized pur- come has been derived from oil and gas, mo- poses for appropriation of the interest lybdenum, and coal. Two new funds were es- earnings are identical to those of the tablished at the time of passage of the sever- principal fund. (See table 91 for a sum- ance tax: a State Severance Tax Trust Fund mary of expenditures.) and a Local Government Severance Tax Fund. When shale oil revenues are realized, ● Colorado Mineral Leasing Fund. Colo- they will be distributed as follows: rado’s share of public land monies collected by the Federal Government for ● 40 percent to the State General Fund, leasing of minerals other than oil shale is 40 percent to the State Severance Tax placed in the Colorado Mineral Leasing Trust Fund, and Fund.26 The fund was created in 1977 to ● 20 percent to the Local Government Sev- be used for planning, construction, and erance Tax Fund. maintenance of public facilities, and the Although separate legislation created the provision of public services. Priority is to Local Government Mineral Impact Fund and be given to “those. .. political subdivi- the Local Government Severance Tax Fund, sions socially or economically impacted for practical purposes they have been combined into an Energy Impact Assistance Fund Table 91 .–Expenditures of the Colorado Oil Shale Trust Fund, that is administered by the Division of Miner- Fiscal Years 1975-80 al and Energy Impact.

Amount of Amount Outstanding Mechanisms for Disbursement.– Year appropriation expended commitments

b The Colorado General Assembly makes ap- FY 1975a $ 451,187 $325,926 o FY 1976a ,,, 10,385,300 10,029,381 $ 2,000 propriations from the oil shale principal and FY 1977 a 4,239,646 3,283,408 47,332 interest funds based on the recommendations FY 1978a 6,464.793 4,702,737 993,510 FY 1979a 8,929,090 6,306,940 2,622,150 of JBC. Requests for financial assistance from FY1980c 10,446,102 Not available Not available the oil shale funds are initiated at the local level. Priorities for needs are assigned at the asumma~Yafld~ldluS ~ePof/ Ofjhe /dmera/ [ease and Severance rar Fund Second Annual Re porf lo fhe Colorado State Leglsldture Oeparlmenlof Local Affairs 1979 local level and forwarded to JBC. In addition, b$ I ~~ P61 of the $.$51 I !37 orlglnal approprlahon was returned 10 the 011 Shale Trust Fund COe~drfmenl of Locdl Affatrs Dlwon of Energy and Mined Impact the requests are reviewed by the Division of SOURCE Offfice of Technology Assessment Mineral and Energy Impact. JBC receives the Ch. 1O–Socioeconomic Aspects ● 433

requests in public hearings and subsequently Colorado West Area Council of Govern- corresponds with local officials if clarifica- ments.—CWACOG is a clearinghouse for the tion is needed. After analyzing the requests, municipalities and counties of northwestern JBC incorporates, as a series of line items in Colorado. With respect to energy develop- the appropriations bill, the sums recom- ment, it provides communities with informa- mended for expenditure from the oil shale tion about industry plans and government funds. (See tables 92 and 93 for a listing of assistance programs, and makes local groups the general categories under which these aware of the responses of neighboring juris- monies have been expended and the projects dictions to impact problems. It also assists the that have been funded.) mitigation task forces in preparing their needs assessments and in assigning priorities In contrast to the legislative process con- to the final requests submitted to the State; trolling the oil shale monies, disbursements from the Energy Impact Assistance portion of and it is the central agency through which grant applications to both State and Federal the Mineral Leasing Fund are at the discre- agencies must pass. tion of the executive director of DLA. Obliga- tions are made by contracts negotiated and CWACOG uses a growth-monitoring sys- administered by field representatives from tem to project future employment and total the Department. DLA uses the same local and population figures. Industry work force in- regional review process followed in the oil formation and economic and demographic shale appropriations procedure for the iden- multipliers are combined for these forecasts. tification of needs and the ranking of funding The computer model can accommodate up- requests. It is assisted by a statewide energy dated information, and can supply outputs impact assistance advisory committee that such as projections based on alternative makes recommendations to the executive di- assumptions and growth scenarios. The sys- rector of DLA. tem provides a single source of data for government and industry officials. Technical Assistance.– Information gathering and dissemination, Field Representatives for DLA.—Field per- program coordination, regional planning, and sonnel are located in several areas of Col- advisory services are the main types of tech- orado that are experiencing energy-related nical assistance provided to local planners. growth. They help organize community miti- For the oil shale region, this assistance comes gation teams and coordinate local, county, from CWACOG and DLA. and regional requests for funding assistance. They also negotiate and administer contracts Table 92.–Appropriations From the Oil Shale Funds by Object, involving the expenditure of impact funds. Fiscal Years 1975-80 They serve a valuable function by expediting State funding, advising local officials about Amount appropriated Percent of total Purpose FY 1975-80ab appropriation current assistance programs, and monitoring Road, bridge, and drainage $14.298736 35.1 the progress of authorized work. Schools 9,262,714 22.7 Water 9,402,403 230 Utah Sewer 2,802,058 69 Health and mental health 440,668 11 Municipal facilities 3,013500 74 Between 1970 and 1977, the population of Recreation 370,000 0.9 Utah increased by 20 percent. Unlike other Coordination and planning 1,190,788 29 Western States, however, most of this growth Total $40,780.867 1000 was from a high birth rate, with immigration aSumnrary and Sralus Repor( ot the Minera/ lease and Severance Tax Fund Second Annual Re accounting for only 4 percent of the increase. port 10 Ihe Colorado Stale Leg,slafure Department of Local Affairs 1979 bstale Approprlafton Acf for FY 197980 IS B 5251 Although there has not been a large migration SOURCE Office of Technology Assessment to the State as a whole, energy development 434 . An Assessment of 0il Shale Technologies

Table 93.–Projects Funded by the Colorado Oil Shale Trust Fund, 1975-80

FY 1975 FY 1976 FY 1977 Recipient Amount Recipient Amount Recipient Amount Mesa County schools (Re-51 ) $42,575 Water Construction fund $2700,000 Piceance Creek Road $2,135,000 Moffat County schools (Re-1 ) (Colorado Water Board) Roan Creek Road 665,858 Garfield County schools (Re-2) 12,389 Piceance Creek Road 1,873,091 Rangely sewer 460,000 RIO Blanco County planning 10,000 RIO Blanco County schools (Re-1) 1,189,000 Craig Hospital 230,000 Garfield County planning 10,000 Garfield County schools (Re-2) 1,000,000 Craig water tank 215,000 Mesa County planning 10,000 Moffat County schools (Re-1) 670,000 Mesa County schools (Re-49) 147,000 Garfield County schools (Re-1) 8,000 Bonanza Road 497,909 011 Shale Coordinator’s Off Ice 106,000 Mesa County schools (Re-49JT) 7,260 Rulison Bridge 471,000 Garfield County planning 100,000 Meeker schools 4,000 Roan Creek Road 467,595 Moffat school leases 51,456 Colorado West Area Council of Gov’ts 781 Mesa County schools (Re-51) 400,000 Mental health services 34,000 Office of the Governor De Beque Bridge 299,658 Hayden school site 25,000 Administration 87,187 Garfield County schools (Re-1) 200.000 Colorado West Area Council of Gov’ts 25,000 State Impact Report 92,734 Colorado West Area Council of Gov’ts. 200,000 Delta County 17,000 (technical assistance) De Beque sewer 15,000 Garfield County schools (Re-16) 121.057 New Castle sewer planning 6,666 Routt County Road 100,000 Silt sewer planning 6,666 Oil Shale Coordinator’s Off Ice 100,000 Town of Hayden, streets 50,000 Mesa County schools (Re-49) 36,000 Rio Blanco County schools (Re-4) 10,000

FY 1978 FY 1979 FY 1980 Recipient Amount Recipient Amount Recipient Amount De Beque water $608,000 Rifle water 2,056,000 Rifle school construction $2,750,220 Grand Valley Bridge 532,125 County Road 24 1,000,000 Rifle bypass 2,000,000 Rangely streets 500,000 Rangely streets 900,000 Meeker sewage treatment expansion 1,440,000 Carbondale sewer 479.000 Craig High School 750,000 Silt water Improvements 1,400,000 Moffat County–Sunset School 450,000 Colorado Water Conservation Board 600,000 Meeker streets and drainage 800,000

Hayden Elementary School 4501000 Rifle bypass 500,000 Mesa County sewer system Rifle sewer 438,750 Meeker sanitation 368,000 Improvements 796,787 Meeker streets 435,400 Meeker pool 350,000 C-a to Rangely Road engineering 300,000 Mesa County schools (Re-51) 350,000 Meeker streets 320,000 De Beque water system 300,000 Hayden water 280,000 Mesa County airport water 293,250 Rifle senior center 172,500 Craig City Hall 275,000 Garfield County airport 260,000 Grand Valley sewage treatment plant 141,206 Garfield County schools (Re-2) 273,757 Grand Valley water 250,000 Dinosaur water system 66,153 Moffat County bypass 250,000 Fruita sewer 200,000 Roan Creek Road 135.000 Transportation planning, CWACOG 198,000 Craig water 125,000 New Castle water 196,000 Oak Creek water 122,000 Silt water 151,000 Oil Shale Coordinator’s Office 114,079 Impact Coordinator’s Office 114,079 Rangely sewer 100.000 Colorado Northwest Community Mental health center 95,857 College 110000 Carbondale Municipal Building 75,000 Mesa County sewer 104,450 Moffat–modular rooms 74,000 Regional School Fund 100,000 Rifle lift station 66,825 Rangely Hospital 50,811 Colorado West Area Council of Gov’ts Mesa County transportation 25,000 (Planning) 62,500 RIo Blanco County Impact Coordinator 17,500 Hayden drainage 41,000 Silt planning 15.000 Meeker Hospital 30,000 Craig drainage 25.000 Delta County water 25,000 Hayden recreation 20,000 Walden water 15,000 Rifle planning 10,000 Silt planning 6,500

SOURCE Summary and Status of the Mineral Lease and Severance Tax Fund Second Annual Report 10 the Colorado State Legislature. Colorado Department of Local Affairs 1979 Ch. 1O– Socioeconomic Aspects ● 435

activities have been responsible for rapid the legislation creating the account specified population increases in certain rural counties that those expecting large population in- and communities. Until the recent boom, the creases are eligible for help. The Uinta basin, population in most of these areas had de- where the oil shale deposits are located, has creased over several decades, As a conse- not received any funds from the account even quence, the communities have been ill-pre- though it is undergoing oil and gas explora- pared to respond effectively to current tion and development. Because the Communi- changes. ty Impact Account is the only funding source in the State designed to respond to problems The oilfields of eastern Utah attracted peo- associated with energy development, re- ple to Duchesne and Uintah Counties, al- quests for help have far surpassed the avail- though oil drilling there has peaked and the able monies. In mid-l979, with only $4 million growth is now waning, Area residents hope available for distribution, a total of $11 mil- that the present emphasis on synthetic fuels lion had been requested. will lead to a boom from oil shale and tar sands development.29 Increased coal mining Adequate water supplies are one of the has caused growth in Carbon, Sevier, and paramount needs in the energy-impacted Emery Counties. In 1960, the population of areas of Utah. Several towns have had to communities in these counties was under place moratoriums on additional building 1,000; several even declined during the because water systems cannot service in- 1960’s. Because there are no larger towns in creased demands, and during summer the area that can provide housing and other months many communities are forced to ra- services, they have been forced to absorb all tion the available water. To help solve these the migration. A resurgence of uranium min- problems, the City Water Loan Fund32 was ing along with oil exploration has stimulated created by the State legislature in 1975. It growth in San Juan, Grand, and Garfield provides interest-free loans to cities for the Counties. The towns of Blanding, Moab, and construction of water supply and water treat- Monticello, which have all gained new resi- ment facilities. The fund provides up to 80 dents, are expected to continue growing. percent of the amount needed with the only qualification that the community be incor- Utah created a Community Impact Account porated. Originally the revenue came from in 1977 to assist areas affected by energy 30 taxes on the sale of alcoholic beverages, but development. It is a “revolving account for recently the funding source was changed to loans and grants to state agencies, political State mineral lease royalties; the amount subdivisions of the state, and special service varies from around $2 million to $2.5 million districts which are or may be socially or eco- annually. Surprisingly, the fund has pretty nomically impacted by mineral resource de- 31 well been able to keep up with the demand for velopment . . ." Revenues come from a por- loans. Every application has received a loan tion of the State’s share of Federal mineral offer, even though not always the amount release payments, Projects are chosen by a quested, A problem that might arise in the board comprised of chairpersons of several long term could be that a loan taken out dur- State boards, councils, committees, and de- ing a time of boom would have to be paid by partments. The board establishes the criteria the remaining, smaller population during a for awarding grants and loans, determines subsequent time of bust. Also, since the loans the order in which projects will be funded, are just for water-related projects, help is and serves as the sponsoring agency. The limited to only this one problem area. chief criterion for determining which projects to support is urgency of need. To date, almost Wyoming all support has been for water and sewer projects. Only those communities already im- Some of the largest growth in the Western pacted have received assistance even though States has been in Wyoming. Between 1970 436 Ž An Assessment of Oil Shale Technologies and 1978, the population in all but one of Wyoming also has an array of mitigation Wyoming’s 23 counties increased. In con- programs. (See table 94.) They are funded by trast, in 15 of the 23 it declined in the decade Federal mineral lease revenues and State between 1960 and 1970. Much of the recent severance and excise taxes. Most are admin- growth has been related to energy develop- istered by the Farm Loan Board, composed of ment, although some reflects the trend of set- the Governor, secretary of state, auditor, tling in rural areas for simpler living patterns treasurer, and state superintendent of public or for retirement. From 1970 to 1978, popula- instruction. Allocation of funds is specified in tion expanded 30 percent or more in eight most cases by the taxing legislation, and counties. These are distributed in three there are few discretionary programs. One distinct geographical areas. Lincoln, Uintah, alternative available to local communities to Carbon, Sweetwater, and Teton Counties lie generate discretionary revenue is an optional in the west and southwest where there are l-cent sales tax.35 It has been used successful- coal, uranium, and oil deposits and the only ly in several communities although approval large oil shale deposits in the State. Most of by the local voters must be sought every 2 the growth in Campbell and Converse Coun- years. Case studies of boomtowns in Wyo- ties, in the Powder River basin in central ming indicate that there are major differ- Wyoming, has been from the opening of coal ences in the effects of rapid growth, and to and uranium strip mines. Platte County, in accommodate these differences, flexible pol- southeastern Wyoming, is the site of a 1,500- icies are needed. This is especially true for MW coal-fired plant. providing such human services as day care centers, youth assistance and senior citizen Wyoming has several programs for manag- programs, and alcohol counseling. Too few ing growth. The major tool, designed for large funds are available to alleviate the social im- development activities, is the Wyoming In- 36 pacts accompanying rapid growth. dustrial Development Information and Siting Act.33 This Act, passed in 1975, requires that any project with construction costs in excess Evaluation of State and Local Mechanisms of $63,588,000 obtain a siting and construc- State policies regarding social and econom- tion permit from the Industrial Siting Council, ic effects vary. In Colorado, local initiative is a board appointed by the Governor. Before a central in the mitigation process. The State permit is granted, the developer must submit and its oil shale counties and municipalities a plan for the alleviation of social, economic, have been preparing for increased shale de- and environmental impacts, and can be re- velopment for nearly 10 years. However, in quired by the council to undertake their miti- the past, this development has been inter- gation. For example, applicants can be asked rupted or delayed by market changes, regula- to provide direct loans and grants to a politi- tory modifications, and technological compli- cal subdivision. Another management device, 34 cations, which has made planning difficult. In created by the Joint Powers Act, allows two addition, oil and gas, coal, electric genera- or more agencies, such as cities, counties, tion, and uranium industries are all expand- and school districts, to form a Joint Powers ing at the same time as oil shale. This compli- Board that can create, expand, finance, or cates the identification of impacts specifi- operate facilities. This not only makes possi- cally attributable to shale development and ble combined financing by the participating adds to the potential for disruption. political entities but also makes them eligible for Joint Powers Loans. There is no ceiling on An elaborate planning infrastructure is in a loan, and the terms must be no longer than place in the Colorado counties and munici- 40 years at an interest rate of not less than 5 palities. Over $40 million has been appro- nor more than 10 percent. priated for oil shale impact mitigation, with Ch. 10–Socioeconomic Aspects ● 437

Table 94.–Wyoming Programs to Mitigate Social and Economic Impacts — . Implementing Name of mitigation program Objectives Funding agencies Comments Wyoming Industrial Develop- Provide information about new Industrial Not applicable Wyoming Siting Council can require applicants ment Information and Siting facilities costing over $63,588,000 council to take actions to mitigate Act ( 1975) Siting and construction permits re- adverse socioeconomic quired before building starts Impacts Joint Powers Act ( 1975) Allows different political entitles to join Joint Powers Loans from Farm Loan Board Some towns and counties have together to finance and operate public FLB. a FLB is restricted (FLB)a difficulty cooperating Small- facilities through a Joint Powers Board to $60 million in er towns lack manpower to outstanding loans prepare detailed applications. Wyoming Government Royalty Grant program for communities in areas Mineral Leasing Act of FLB Grant funds extremely limited. Impact Assistance Account of mineral development 1920, as amended b competition keen ( 1976)

1/ Wyoming Water Development Encourage optimal development of 1 2 -percent excise tax Water Development Requires feasibility study. Program ( 1975) human, Industrial, mineral, agricul- on coal Commission, Dept authorizing legislation, and tural, water, and recreational Revolving loan account, of Economic Plan- vote to approve any public resources through projects and up to $100 million can nlng and Develop- debt (such as bonds) before facilities for water storage, be outstanding ment, FLB, local construction can begin. distribution, and use agencies Coal Tax Revenue Account Grants to political subdivsions in areas 2-percent severance tax FLB $160 million will probably be (1975) Impacted by coal development for on coal expended before synthetic Public facilities. 50 percent must Maximum cumulative tax fuel development occurs go for streets and highways revenues limited to $160 million

Capital Facilities Revenue Permanent capital facilities by legislative 1 1/2-percent excise tax Capital Facilities Used mostly for major State Account ( 1977) appropriation, 30 percent for school on coal, trona, and Commission facilities (university, prison), district capital construction uranium approval of bonds needed for entitlements, formula allocation to Maximum tax revenues school construction community colleges, remainder limited to $250 million for highways Wyoming Community Develop- To provide funds for private mortgages Mortgage monies gener- Wyoming Community Program delayed by litigation. ment Authority ( 1975) at low interest through mortgage ated through issuance Development only recently implemented lending institutions of bonds Authority Authority granted for up to $250 million in bonds c alhe Farm Loan Boaro conssk of [he Governor secrelarv of slate aud!lor treasurer artd slate SuDer(fltefldefll of oubl~c /nstruct(on bsee .eKt for a OIScusslon O! Federal flnanclal ass!slance ~r09rdmS ‘The 1980 Wfomlng Ieqlslalure oas under conslderalton rdtstoq lms amount 10$750 mltl{on SOURCE O!flce of Technology Assessment over 90 percent allocated to the four counties has caused some discontent in the oil shale of Mesa, Garfield, Rio Blanco, and Moffat. region where expenditure of the full amount (See table 95.) Most of the remainder has would accelerate preparations for growth. gone for the State’s support services. As a re- Because the trust fund is disbursed by legisla- sult, the region is prepared for reasonable tive appropriation, intrastate political differ- growth and is awaiting expanded oil shale de- ences also come into play. The General velopment. However, the ability of existing Assembly has greater representation from strategies to deal with a large or sudden pop- the eastern, more densely populated, urban ulation influx, such as might occur with a parts of the State; thus western slope Sena- rapid expansion of the industry, is as yet un- tors and Representatives can be outvoted. Im- tested. Although the State has ambitious pro- pact mitigation, in this case, is subject to the grams, the General Assembly has adopted a political compromises of the Colorado appro- cautious approach to the expenditure of the priation process. Oil Shale Trust Fund monies. While not required to do so, JBC has elected to retain a Utah and Wyoming have not been prepar- principal of $60 million in the trust fund. This ing extensively for oil shale development im- .

438 ● An Assessment of 0il Shale Technologies

Table 95.–Allocation of Oil Shale Trust Funds, For example, Douglas and Wheatland in Fiscal Years 1975-80 Wyoming have experienced few of the nega- Percentage of total appropriation tive effects identified in the literature as County or agency FY 1975-79 FY 1980 boomtown impacts. Rock Springs and Gillette, Garfield County – 285 – 619 on the other hand, appear to be at the op- Mesa County 130 124 posite end of the spectrum, with the former Moffat County 11 2 06 being the classical example of a town dis- R IO Blanco County 400 243 - rupted by energy development. Yet these four Subtotal–oil shale region 927 992 communities are undergoing the same types a Delta County 01 0 of industrial growth (primarily coal, oil, and Jackson County 005 0 Routt County 37 0 gas prospecting and production) and have the Subtotal–all counties...... 966 992 same kinds of impact assistance available to 17 Division of Energy and Mineral Impact 21 0.6 them. A conclusion from these cases is that CWACOG 12 01 the capability of adapting to rapid growth ap- Total 100 100 pears to be highly site specific.

dThe 1979 Gepera( Assembly adopted Ihe policy 10 allOCa[e trust funds Oflly tO Ihe counties In Ihe Immediate 011 shale vtctnlly

SOURCE OTA bdSW on data for FY 197579 from Summary and Status Report of the Mineral Federal Programs Lease and Severance Tax Fund Second Annual Report to the Colorado Stale Legisla- ture, Department of Local Affairs 1979 and FY 1980 from State Appropriation Act for FY 19791980 (S B 525) Only a few of the over 1,000 existing Feder- al programs are designed to deal with socio- pacts. Both States, however, have had to economic impacts. A 1978 Report to the Presi- come to grips with other energy industry ex- dent38 lists 160 that were judged “potentially pansion, and presumably could use programs applicable to energy impact issues. ” They are similar to the ones now established for coal administered by 20 departments or other Fed- and uranium mitigation to adjust to oil shale eral agencies. About two dozen programs growth. They emphasize a more centralized that are of importance to the Western States process with State government playing a have been identified by Murdock and Leis- larger part in the determination of needs and triz.39 (See table 96. ) Only those that contrib- the allocation of assistance. Utah may be ute to the alleviation of negative impacts from limited by a lack of funding, although the oil shale development are examined in detail bonus payments from the U-a and U-b lease here, Federal programs can be placed in two sales—now being held in escrow pending the broad categories: financial and technical outcome of the ownership question—should assistance. be available in the future. The State may experience difficulty from a lack of adequate local infrastructures capable of handling Financial Assistance rapid growth. Evaluation is complicated for Section 35 of the Mineral Leasing Act of Utah as it is for Colorado by similar uncer- 1920 40 is a major source of Federal financial tainties about the future timing, pace, and assistance. This legislation originally pro- size of the industry. Wyoming has many provided for the Federal Government to return grams that could be adapted for oil shale im- 371/2 percent of the revenues it receives from pact mitigation. At present, its funding levels mineral leases on public lands to the States in appear to be adequate. which those lands are located; these monies No State facing social and economic prob- were to be used by the legislatures of the lems from energy development is able to an- States for support of public schools and ticipate which communities will be able to ad- roads. In 1976, this section was amended by just to growth and which may be disrupted. the passage of the Federal Coal Leasing 41 Whether towns will suffer from rapid growth Amendments Act and the Federal Land Pol- 42 or take it in stride depends on a unique set of icy and Management Act (also known as the complicated factors within each community. Bureau of Land Management Organic Act or Ch. 10–Socioeconomic Aspects ● 439

Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effects of Energy Development’

Name of program Implementing agency Objectives Comments Assistance in planning and growth management Comprehensive planning Community Planning and Strengthen planning and declslon-making Urban orientation overall, smaller cities assistance Development, HUD capabilities of States, local governments, and counties receive funding through HUD 701 program and areawide planning organizations States Funds allocated on basis of past National Housing Act of population which IS a disadvantage to 1954, as amended (40 rapidly growing communities U S C 461) Some State and local concern over recent decline in funding levels — Community development block Community Planning and Assist communities in providing decent Primarily for urban areas, most funds grants–small cities Development, HUD housing and a suitable Iiving environ- allocated by formula Some discretionary Housing and Community ment, expand economic opportunities funds for special-purpose grants to small Development Act of 1974 communities Title I (42 U S C Provides 100-percent funding that can be 5301-531 7) used as local matching contribution for other programs Can also be used for facility construction as well as for planning Economic development– Economic Development Foster multicounty planning and Criteria for project selection makes it dif - planning and technical Administration (EDA), Implementation capability, solve prob- ficult for energy-impacted communities assistance Commerce lems of economic growth through project to obtain funding Public Works and Economic grants, feasibility and other studies, and Competition for funds is keen. Development Act of 1965, management and operational assistance as amended (42 U S C 3151, 31 52) Title III Technical assistance– Off Ice of Personnel Aid in problem-solving and delivering Few communities appear to have taken personnel sharing Management Improved services by sharing profession - advantage of program. Intergovernmental Person- al administrative, and technical Time involved in Iocating and negotiating net Act of 1970 (5 U S C expertise. for an individual may be a constraint for 3371-3376) small counties and communities Water quality planning Office of Water and Waste Develop water quality management plans Funds limited to planning only sec 208 grants Management, Environmental Clean Water Act, as Protection Agency (EPA) amended (33 U S C 1251 et seq. ) . Assistance in expanding public facilities and servicesc Water and waste disposal sys- Farmers Home Administration Provide amen! ties, alleviate health Sewer and water systems cannot serve terns for rural communities (FMHA), Agriculture hazards promote orderly growth of rural areas with a population in excess of Consolidated Farm and areas by providing new and Improved 10,000 population, priority is given to Rural Development Act, water waste disposal facilities communities of less than 5,500 in - sec 306 (7 U S C 1926) habitants Community facilities loans FmHA Agriculture Construct, enlarge, or Improve community Targeted for areas with Iow-income rural Consolidated Farm and facilities residents Rural Development Act, Priority to projects enhancing public safety sec 306 (7 U S C 1926) (fire, pollee, rescue services), health care facilities needed to meet life/safety codes, public buildings and courthouses, recreation facilities, new hospitals Construct Ion grants for Office of Water and-Waste Assist in construction of municipal sewage Funds allocated to States on a wastewater treatment works Management, EPA treatment works population-based formula No funding of Clean Water Act as collector systems in ‘‘communities not in amended (33 U S C 1251 existence” in October 1972 et seq ) Some difficulty allocating funds on a timely basis ..- —..——. Economic development and EDA, Commerce Assist State and local governments to Targeted to communities experiencing adjustment assistance arrest and reverse long-term economic economic decline but funds are available Title IX– EDA deterioration, address dislocations from to energy-impacted areas Public Works and Economic Federal actions, from compliance with Flexibility an advantage Development Act of 1965, environmental requirements, and from as amended (42 U S C severe changes in economic conditions 3121 et seq ) — — — 440 . An Assessment of Oil Shale Technologies

Table 96.–Selected Federal Programs Used by Western States for Assistance With Social and Economic Effects of Energy Developmenta—continued

Name of program Implementing agency Objectives Comments Outdoor recreation Heritage Conservation and Financial assistance for planning, Limited funding restricts the number of ‘‘ BOR program’ Recreation Service, Interior acquisition, and development of outdoor projects that can be supported Land and Water Conserva- recreation areas and facilities A popular program tion Fund Act of 1965, et al. (16 U .S. C. 1-4 et seq. ) Planning and site acquisition FmHA, Agriculture Assist in developing plans for growth Newly Implemented, Sec. 601 program management and housing and in Currently Iimited to coal and uranium Power Plant and Industrial acquiring sites for housing and public Impacts, Fuel Use Act of 1978 facilities (Public Law 95-620) Assistance for housing Rural housing loans FmHA, Agriculture To assist rural families through guar- Loans are regarded as a ‘ ‘source of last Housing Act of 1949, as anteed/insured home loans resort to be used only if commercial amended. Title V, sec. lending Institutions cannot finance 502 (42 U.S. C. 1471 et housing. seq., 42 U.S. C. 1480; 42 U.S.C. 1472) Rural housing site loans FmHA, Agriculture Assist public or private nonprofit Priority given to housing for low- and Housing Act of 1949, as organizations to acquire and develop land moderate-income families amended. Sees. 523 and to be subdivided on a nonprofit basis for 524. (42 U.S. C. 1490c homes. and 1490d) Rural rental housing loans FmHA, Agriculture Provide economically designed and con- Housing Act of 1949, as structed rental and cooperative rental amended. Sees. 515 and housing for rural residents, 521. (42 U.S.C. 1485, 1490a) dThe ~rogram~ l,~fed are ,Ilus(rdtlve of the types of aid avadable In Western States no attempt has been made to Include all possible Federal Pro9rams used by lmPacted communities bGeneral ~ategor[es are based on the format used by Murdock & Le!slr[tz Errergy L7eve/opmerrf Irr Ihe b$’es(e~rr Umled S/aleS–hnPaC/ On Rural Areas (A y prae9er Publishers 1979)

C R evenue ~har, ng acts suc~ as the Local Government Funds Act (publlc Law g4.5fj5) are not Included see [ext for a discussion of the Mineral Leasing Act Of 1920 aS amended

SOURCE Office of Technology Assessment

FLPMA). The Federal Coal Leasing Amend- cent interest, from these proceeds. The lan- ments Act increased the States’ share of guage of the Coal Leasing Amendments Act royalty and lease proceeds to 50 percent, and that allows broader use of the funds and spe- specifically directs the legislatures, when cifies their application to affected areas is distributing these proceeds, to give priority to also extended to the loans.44 those subdivisions of the State where leasing occurs under the Act. At the same time, the Section 601 of the Power Plant and Indus- purposes for which the funds could be used trial Fuel Use Act of 197845 established the were broadened to include “planning, . . . Energy Impacted Area Development Assist- construction and maintenance of public fa- ance Program (popularly, the sec. 601 pro- cilities, and . . . provision of public serv- gram). Its objective is to “help areas im- ices."43 FLPMA further amends the 1920 Act pacted by coal or uranium development activ- to authorize the Secretary of the Interior to ities by providing assistance for the devel- make loans to States and their political sub- opment of growth management and housing divisions. The amounts of the loans are not to plans and in developing and acquiring sites exceed the revenues anticipated by the States for housing and public facilities and serv- or their jurisdictions for any prospective 10- ices. 46 The lead agency designated to admin- year period. Loans are to be repaid, at 3-per- ister the section is the Farmers Home Admin- Ch. 10–Socioeconomic Aspects ● 441

istration (FmHA). The Governor of a State the Environmental Protection Agency (EPA). wishing to participate must designate energy- Senior staff members of these agencies make impacted areas and prepare a State invest- up an Intergovernmental Committee that ment strategy for allocating the funds. Grant assists the Energy Impact Office. applications for impact aid must be consistent with the State investment plan. Local gov- Dissemination of information and inter- ernments, councils of local governments, and agency coordination are the main functions of State agencies are among the eligible appli- the Federal programs. Several examples can cants. Grant funds will pay 100 percent of the be cited. FRC has a representative in the Oil costs of developing plans for managing Shale Environmental Advisory Panel (OSEAP) growth and/or plans for new housing, and up who serves as contact with this group. The to 75 percent of the cost of acquiring or devel- Federal Assistance Program Retrieval Sys- oping sites for housing, public facilities, or tem (FAPRS) is a computerized information services. bank, keyed to programs described in the Cat- alog of Federal Domestic Assistance. The En- Three criteria are specified for designation ergy Impact Office uses it to help communi- as an impacted area. First, employment in ties identify various Federal assistance pro- coal or uranium development activities must grams and determine their eligibility for aid. have increased, or be expected to increase DOE’s Office of the Regional Representative, over 3 years, by 8 percent or more from the Region VIII, in cooperation with FRC, pub- preceding year. Second, the increased em- lishes an annual Regional Profile—Energy Im- ployment must result in a housing shortage or pacted Communities47 that collates data on inadequate public facilities and services. the energy impacted areas. Third, the available State and local financial resources must be inadequate to meet the current needs or those projected for the fol- OFFICE OF THE AREA OIL SHALE SUPERVISOR lowing 3 years. Within the oil shale region, The Office of the Area Oil Shale Super- the purchase of land by the city of Meeker for visor of the U.S. Geological Survey (USGS) the construction of low- and moderate-income also provides technical assistance to commu- housing was included as a priority project in nities by serving as a clearinghouse for in- the 1979 Colorado investment strategy. formation about social and economic impacts and programs for their alleviation. Technical Assistance Summary of Federal Support Initiatives THE FEDERAL REGIONAL COUNCIL The Energy Impact Office of the Federal At the present time, there is no single Fed- Regional Council (FRC), Region VIII, oversees eral policy with respect to the social and eco- Federal technical assistance programs. The nomic effects of energy development. At the Office was created early in 1978 to coordi- regional level, the Federal point of view is nate the response of Federal agencies to local best expressed in the Region VIII DOE Region- needs. In addition to the development of an al Profile. The edition of March 1979 reiter- improved system of service delivery, the FRC ates a position taken in earlier volumes: efforts are designed to evaluate Federal legislation for impact assistance and to collect im- The Region VIII office maintains the posi- pact data and related information. The agen- tion that local communities and counties cies comprising the Federal Regional Council must take the initiative to become involved in assessing, planning for, and mitigating ad- are the Departments of Agriculture; Com- verse energy related impacts. To effect a merce; Energy (DOE); Health, Education, and team effort involving industry, Federal, Welfare; Housing and Urban Development State, and local government, the initiative (HUD); the Interior; Labor; Transportation; and follow-up must first be taken by local the Community Services Administration, and leadership,” 442 ● An Assessment of Oil Shale Technologies

Several programs are operating that ad- ernment need not be involved with their ame- dress limited aspects of socioeconomic ef- lioration. This viewpoint, opposing Federal in- fects but, at present, none directly addresses volvement, also contends that specific Fed- the impacts that may come with synthetic fuel eral mitigation programs would increase bu- development or the specific consequences of reaucracy, and cites the public’s growing dis- accelerated shale oil production. A wide vari- pleasure with the perceived intervention of ety of assistance is available through avenues Federal agencies in the daily life of the citi- not specifically designed to deal with energy zenry as a reason for not expanding Federal development impacts. These various Federal activities. On the other side is the position programs have different emphases and that national requirements are the root modes of providing help, and impacted com- causes of the local impacts, therefore an ex- munities must compete with everyone else for panded Federal role is appropriate. Several the limited funds available. Western States contend that because ex- These regular Federal programs usually panded domestic energy production is a na- require elaborate proposal development but tional goal, for reasons of equity the Federal small towns with limited manpower often do Government should assume a more direct role not have the expertise to prepare grant ap- in the alleviation of negative impacts from this development. plications. Furthermore, many programs have lengthy review processes before deci- Assuming additional Federal involvement sions are made, which can be a disadvantage is desired, how can the Government most ap- for boomtowns. For example, EPA grants for propriately assist impacted communities? sewer facility upgrading take about 3 years One position is that providing financial from the time of application to the time of assistance is sufficient programmatically and decision; if a community does not get a grant, only the amounts need to be increased; new this time is lost entirely and the town can only programs and regulations are not desirable. fall further behind in its effort to keep up with Another position is that Federal regulation its growth. In addition, although the specific could be used to mitigate impacts by, for ex- programs may be adequately meeting the ample, pacing industry’s growth rate through needs for which they were designed, their leasing policies. A third position is that the limited nature means that the cumulative im- Government should be substantially involved pacts of all types of industrial development in mitigation programs that use Federal are not being addressed. funds. Part of this issue includes the question At present, the major role of the Federal of when and where the Federal Government Government is providing revenues for mitiga- might to be involved. The provisions of the tion; these monies come primarily from the Powerplant and Industrial Fuel Use Act sug- Mineral Leasing Act of 1920, as amended. A gest that it should step in only when State and somewhat expanded Federal impact mitiga- local governments cannot handle impact tion role is found in section 601 of the problems. A similar position is that Federal Powerplant and Industrial Fuel Use Act of participation should be confined to areas re- 1978. The extent and nature of any additional quiring long-term commitments, such as hous- Federal involvement in impact mitigation are ing, sewer, and water systems. Another pos- controversial. On the one side, it can be sible Federal approach could be to help speci- argued that social and economic impacts are fic groups (such as retired persons on fixed State and local problems. They should be incomes or young adults seeking to enter the viewed as the inevitable consequences of in- job market) who may be particularly hard hit dustrial development, and the Federal Gov- in boomtowns. 49 Ch. 10–Socioeconomic Aspects ● 443

Possible Consequences of Oil Shale Development General Effects of ever, local governments should benefit from Rapid Population Growth the increased tax base resulting from energy development. The recent development of energy resources has caused large numbers of people Local governments need help in the early to move into established rural communities stages of rapid growth. One traditional within short periods of time. All parts of a means of raising the needed funds is by issu- community are affected by this kind of ing bonds. While this remains important, ex- growth. Local government agencies are perience indicates that it is far from ade- pressed to provide additional services. A ma- quate. First of all, State law usually places jor difficulty is that the expanded facilities limits on the amounts of indebtedness that and services are needed before new tax reve- counties and communities can incur through nues can be realized. A 3- to 5-year lag ap- bond issues. Second, the assessed valuation pears to be the average between the time the upon which bonding limits are based in- increased services and facilities are required creases over the life of a project but funds and the time additional revenues can be gen- are needed during the early stages when the erated. (See figure 71. ) In the long run, how- population is growing rapidly. Third, local

---- 4 ._ — 444 . An Assessment of Oil Shale Technologies

Fiqure 71 .— Energy-Related-. Employment, Tax Revenues, and Need for Public Services in an Area Affected by a Large-Scale Energy Development

EMPLOYMENT PUBLIC SERVICES

CONSTRUCTION I OPERATION PHASE I PHASE I I TAX REVENUES

I Energy-Related Employment I L I

TIME

SOURCE S H Murdock and F L Leistritz. Energy Development in the Western United States, 1979, Praeger Publishers residents are often afraid to approve bond Finally, the ability of local governments to issues because of the instability of the boom respond may be complicated because the de- cycle. People who have moved in during con- velopment and the population growth may be struction, and who are among those needing in different places. When the project is in one new services and infrastructure, usually taxing jurisdiction and the community in a leave at the end of the construction period. different one, there is a jurisdictional mis- Longtime residents are fearful that they will match. In this case, the town that must pro- be left to discharge debts incurred during this vide increased facilities and services cannot period. Consequently, voters in many of the look forward to larger revenues from taxes most severely impacted communities have re- on the new industry. jected bond issues. Similar difficulties are In the private sector, housing can be a ma- found with loan and loan-guarantee pro- jor problem. It usually is in short supply; its grams. In this instance, the statutory or con- prices are often greatly inflated; and land stitutional limits on the debt that rural com- may not be available for new construction be- munities can incur is an obstacle to the use of cause of terrain, price, or public ownership. the loans to meet front-end funding needs. Shortages of construction financing and Yet another statutory limitation can be a mortgage money are common and, in some ceiling on the expansion of local government cases, new employees may not qualify for budgets. For example, in Colorado most small mortgages. The need for temporary housing towns are prohibited from “the levying of a for construction workers can exacerbate greater amount of revenue than was levied in these problems. Mobile homes often fill this the previous year plus seven percent . . ."50 need but their siting and providing services to The practical effect of this restriction on mill the sites add to the difficulties faced by local levy increases is to limit municipal and coun- government. Industry has, in several in- ty budgets to a 7-percent-per-annum growth. stances, sought to assist by supplying capital Ch. 10–Socioeconomic Aspec!s ● 445

for housing construction. Because public and may have difficulty attracting and keep- housing is statutorily limited to low- and mod- ing personnel. The number of public safety erate-income groups, Federal Government professionals often is limited. Sheriff’s offices agencies cannot provide much help. and town police departments seldom have large forces; fire protection is usually pro- Other affected parts of the private sector vided by volunteer departments. Recreation are the local retail trade and service indus- facilities may be lacking. Social welfare serv- tries. These businesses often anticipate in- ices may depend on itinerant professionals, creased income from energy development. such as a public health nurse or social work- What may not be expected are increases in er who visits the communities periodically. labor costs, taxes, and competition. In some cases, this sector has not been able to meet The functions of a community’s social in- the new demands; business failures have frastructure often are carried out through in- been the most extreme consequences. More formal social networks. In rapid growth situ- common have been difficulties in getting and ations, these networks can break down sim- keeping help, providing the goods that cus- ply because of the increased number of new- tomers want, and expanding stores and shops comers. If there are no established formal to keep up with the increased business. Like structures, then the services cannot be pro- local governments, retail businesses should vided. For example, in many rural commu- profit in the long run from energy devel- nities the school is the center of recreational opment; their dislocations occur during the activities, and there are few structured pro- early periods of rapid growth when services grams. Increased demands to use the school cannot keep up with the new demands. gym cannot be met because there aren’t Those parts of the community that provide enough hours in the day or enough basketball services to the residents also are affected. In courts to accommodate the large number of many areas, this support sector is inadequate new players, Established informal recreation prior to any sudden growth. For example, patterns can thus be disrupted and nothing doctors and dentists are not readily available takes their place until a formal community in many rural regions. School systems, while program can be set up. The effects of rapid established, cannot offer broad curricula, population growth on the various aspects of 446 ● An Assessment of 011 Shale Technologies

Photo credit OTA staff Adequate recreational areas are often lacking in boomtowns the existing community support systems are expanded ninefold as alcoholism, suicide among the more ubiquitous social impacts of attempts, and divorce rates soared. energy development activities. ● Local government was overwhelmed with difficulties. Costs for capital con- Rapid growth inevitably causes social struction of public facilities, such as changes; those communities experiencing ex- water and sewer treatment plants, were cessive strains on their social structure from greater than the communities’ borrow- sudden growth have been called modern 51 ing capacity, and demands for public boomtowns. A well-documented example is services, such as fire and police protec- the Rock Springs—Green River (Sweetwater 52 tion, were beyond the available re- County) area of Wyoming. Here the popula- sources. tion grew from 18,391 in 1970 to 36,860 in ● Schools could not keep up with the pupil 1974. Among the consequences were: increases. The school districts were al- ● Housing availability fell far short of de- ready bonded up to the legal limit and mand. In 1974, between 4,500 and 5,000 were not able to provide the needed ad- families were living in mobile homes, ditional services. many on scattered, isolated tracts in un- ● As a result of the boomtown conditions, incorporated parts of the county. industry was unable to recruit and re- ● These housing areas often lacked ade- tain employees. Employee turnover in quate water, sewer, and other facilities. 1973 ranged from 35 to 100 percent, and ● productivity declined. Cost overruns re- Health care became a major problem. 53 sulted from construction delays. An estimated 40 percent of the residents had to seek medical care outside the It is difficult to determine whether a com- county; the mental health clinic caseload munity will be able to respond adequately to Ch. 10–Socioeconomic Aspects Ž 447 the pressures of growth; however, some gen- and in-migrants, and shifts in personal inter- eralizations have been drawn from case action patterns such as the deterioration of studies of towns like Rock Springs and Green longtime friendship patterns, At the social in- River. Boomtowns have been described as stitution level, dramatic realinements of po- having the following characteristics:54 litical party membership, and an atmosphere of uncertainty about the future that under- ● a small population base, usually under mines established systems of social control 10,000 residents; 58 ● have been documented. On the other hand, a geographic isolation from urban areas; comparison of the experiences of four Colora- ● rapid population growth; ● do boomtowns found a picture of resilience a shift in economic activities away from and adaptability suggesting the “hope that agriculture, trade, and services to con- people can adjust to changes instead of being structing and operating energy-related overwhelmed by them . . . ."59 industries; ● demand for temporary and permanent housing that exceeds supply, with ac- Anticipated Growth in the companying price escalation; Colorado Oil Shale Region ● increased symptoms of social stress such as crime, truancy, child abuse, As a sparsely populated, rural region, alcoholism, and suicide; western Colorado is vulnerable to boomtown ● inability of the public sector to provide, conditions. The three oil shale counties had a in a timely fashion, services and facil- population of 90,748 at the time of a special ities such as streets, water, and sewers; census in 1977. Growth between 1970 and ● dislocations in the private sector such as 1977 ranged from 5 percent for Rio Blanco business failure, labor shortages, and County to 27 percent for Garfield County; the cost increases; largest growth (58 percent) was in Moffat ● strain on health services from increased County, to the north of the oil shale region. need for access to professionals and fa- (See table 97.) None of the communities in the cilities; immediate area had a population over 3,000, ● high employee turnover with accompa- (See table 98.) There are 2 to 19 persons per nying decline in productivity; and square mile and a high proportion of older ● in the early stages, a lack of community residents. (See table 99. ) Sixteen percent of concern for planning and growth man- the residents of the oil shale communities in agement. Rio Blanco and Garfield Counties are over 65 years old, which is over sixty percent higher Alterations in human relationships under- 60 55 than the national average. lie the changes accompanying rapid growth. Some social and behavioral scientists con- The first step in attempting to forecast tend that these are among the most pervasive whether there might be disruption is to gauge and significant consequences of growth and the magnitude of possible migration to the are the basic causes of boomtown symp- area. As indicated earlier in the chapter, toms.56 Among the alterations that have been identified in the social roles individuals must Table 97.–Population Growth of Colorado Oil Shale fill are increased anonymity, impersonaliza- Counties 1970-77 tion, and specialization. At the institutional level, greater bureaucratization, centraliza- Population Population Percent County 1970 1977 change tion, and orientation of community units R IO Blanco 4,842 5,100 5.3 toward systems outside the local social struc- Garfield 14,821 18,800 26.8 ture have been found.57 Among the psycho- Mesa 54,374 66,848 22.9 logical factors identified in boomtowns are Moffat 6,525 10,303 579 value conflicts between established residents SOURCE U S Bureau of Census data 448 . An Assessment of 0il Shale Technologies

Table 98,–Population of Colorado Communities housing data took this into account and Apt To Be Affected by Oil Shale Development, 1977 Rangely’s figures were adjusted downward; Location Population but because these revisions are not reflected Rio Blanco County in all of the projections, discrepancies can be Meeker ., ., ., 1,848 found between different sets of data. Rangely 1,871 Garfield County Each year, CWACOG prepares for the re- Glenwood Springs 4,051 gion an official set of projections to the year Grand Valley, . : ., 377 New Castle 543 2000, based on the following information: Rifle. ... 2,244 ● slit : : : ., 859 baseline population data from the 1970 Mesa County regular and a 1977 special U.S. census; De Beque ,. 264 ● energy company employment projections Grand Junction ., ., 25,398 Moffat County with a family multiplier (2.0); Craig ,. 6,677 ● support industry worker multipliers with Dinosaur 347 accompanying family multipliers (2.5); ● SOURCE 1977 special census base worker distributions assigned by county and community; and Table 99.–Selected Demographic Indices of ● cohort survival factors. Oil Shale Counties of Colorado, July 1975 Three population projection scenarios are de- Number of people Percent aged rived using these factors: County per square mile 65 and over R IO Blanco 2 8.3 Scenario I— Natural population growth with- Garfield 6 105 out energy development; Mesa 19 119 Scenario II— Growth with energy industry de- Moffat ., : : ., . : ., 2 83 velopment, as presently planned; SOURCE Bureau of the Census City and County Data Book 1977 Scenario III— Growth with energy development including shale oil ‘production of 500,000 bbl/d in 1990 and 750,000 CWACOG has a growth-monitoring system bbl/d in 1995and 2000. that provides projections of future growth. The first scenario is a conservative esti- Because this organization serves the day-to- mate of growth with a population induced day needs of the individual counties and com- from non-energy-related employment figures. munities, the projections are frequently mod- Its major benefit is to provide a lower limit ified in an attempt to reflect the current situ- against which to compare the growth sce- ation. To an outsider, there appear to be sev- narios. The second scenario, growth with eral sets of data none of which coincide since energy development, contains base worker it is possible for a town to be using one set of projections from 18 companies including 6 projections to plan for additional housing, that expect to proceed with oil shale develop- another to determine water and sewage ment. These are the developers of tracts C-a treatment requirements, and a third to esti- and C-b, Superior, Union Oil, Paraho, and Col- mate the costs of providing public services. 61 ony (Atlantic Richfield and TOSCO). This Although this arrangement creates some con- scenario has been selected by the CWACOG fusion as to which projections are the most Board as the officially endorsed set of projec- accurate, it is important to modify projections tions because it reflects the stated plans of when the assumptions change. As an illustra- companies active in the region. The third sce- tion, Rangely’s projections have been over- nario illustrates an upper limit generated by estimated in the past because they have as- assumptions for a rapidly deployed oil shale sumed a new road would be built from the industry. town to tract C-a. Since the road was not being constructed when the most recent hous- The latest official CWACOG projections ing projections were made, the CWACOG for the oil shale counties, published in Novem- Ch. 10–Socioeconomic Aspects • 449 ber 1979, show that Rio Blanco and Garfield The projections for Scenario III, assuming Counties are expected to have sharp popula- an industry producing 500,000 bbl/d of shale tion increases under the energy development oil by 1990 and 750,000 bbl/d by 2000, dis- scenario. (See table 100 and figure 72. ) The close exceptionally high growth for the re- number of people in Rio Blanco County is fore- gion. By 1985, Rio Blanco County is projected cast to be, by 1985, four times the 1977 spe- to have almost 8 times the number of people cial census count, while the number in Gar- counted in 1977; Garfield is forecast to have 1 field County is seen as nearly tripling. Moffat 3 /2 times its 1977 count. Mesa and Moffat County is projected to have a large increase Counties are not forecast to have such spec- in the early 1980’s but this growth is attrib- tacular growth, although Mesa County’s pop- uted to coal and electric generation devel- ulation is seen as growing to almost 3 times opment, not to oil shale, Mesa County is ex- the 1977 figure by 2000. pected to grow without extreme fluctuations, The populations of Rifle, Meeker, and but the number of people is projected to near- Rangely are projected to increase from ly double by 1990 over the 1977 figure. around 2,000 to over 22,000 by 1985, with a CWACOG prepares projections for individ- net increase of approximately 18,860 resi- ual communities as well as for the counties. dents for Rifle. Like the counties, the biggest (See figure 73.) For the energy development increments for the towns occur in the early conditions (Scenario II), these figures reveal: years, between 1980 and 1985. Under Sce- nario HI, the projected growth for these three Rifle’s population is projected to grow by 1985 to over six times the 1977 count. communities exceeds 500 percent in the period between 1980 and 1985. (See table 101. ) Meeker’s population is projected to grow by 1985 to over seven times the 1977 count. Needs Arising From Anticipated Growth Rangely’s population is projected to grow by 1985 to over three times the The projections are used by the counties 1977 count. and communities to prepare plans for their

Table 1OO.– Population Projections by Development Scenario for the Oil Shale Counties of Colorado

— RIO Blanco Garfield Mesa Moffat 1977 Actuals a 5,100 18,800 66,848 10,303 1979 Estimatedb 5,580 22.000 75,000 10,925 1985 c Scenario I 51779 28,181 101.005 11,509 Scenario II 22,809 50.559 107,855 15,306 Scenario Ill 40,501 66,820 128.460 18,892 1990 Scenario I 6,177 32,080 121,091 13,311 Scenario II 19,522 56,909 128,308 17.090 Scenario Ill 35,881 71,621 147,583 24,302 2000 Scenario I 6,973 45,344 161,266 16,914 Scenario ll 20,318 83,012 169,882 20,693 Scenario Ill 44,303 95,365 190,484 27,905

aFrOrn a 1977 spec[al U S census

bEnd of {he ~ea[ ~sf(mate prepared (n July 1979 Dy the Colorado West Area COUflCll of Governments cBdsed on (he followlng Scenar!o I – Natural poputal(on growth w,thoul energy development Scendrlo 1: - Growth with energy development accordng to employment forecasts from 18 lnduslr,es acflve (n the region io!tlclal 1980 CWACOG projec- hons I Scenarto III –Energy development lncludlng shale 011 production of 500000 bbl d m 1990 and 750000 bbl d In 1995 and 2000 SOURCE Colorado Wesl Area Council of Governments 450 ● An Assessment of Oil Shale Technologies

Figure 72.—Population Projections for Colorado Oil Shale Counties by Development Scenario, 1980-2000

110,000 100,000

90,000 / 80,000 z 70,000 /’ 0 / ~ 60,000 -1 z 50,000 : 40,000 //- /, 30,000 20,000

10,000 1 1 1 I I 1977 1980 1985 1990 1995 2000 19771980 1985 1990 1995 2000 RIO BLANCO COUNTY GARFIELD COUNTY

32,000 200,000

28,000 175,000

24,000 150,000 z 6 Q 125,000 F % ~ 16,000 + 100,000 CL 8 12,000 L : 75,000 8,000 50,000

4,000 25,000 J I 1 I 1 1 I I 1 I 1 1977 1980 1985 1990 1995 2000 1977 1980 1985 1990 1995 2000

MOFFAT COUNTY MESA COUNTY

KEY POPULATION 1977 SPECIAL CENSUS SCENARIO I—WITHOUT ENERGY DEVELOPMENT SCENARIO II—WITH PRESENTLY PLANNED ENERGY DEVELOPMENT SCENARIO III—WITH PLANNED ENERGY DEVELOPMENT AND OIL SHALE INDUSTRY OF 500,000 bbl/d IN 1980 AND 750,000 bbl/d IN 1995 AND 2000 OFFICIAL 1980 CWACOG PROJECTIONS

SOURCE Colorado West Area Council of Governments Ch. 10–Socioeconomic Aspects ● 451

Figure 73.— Population Projections for Selected Oil Shale Communities in Colorado by Development Scenario, 1980-2000

18,000 17,000 17,000 16,000 16,000 15,000 15,000 E 14,000 14,000 E 13,000 12,000 11,000 I 11,000 10,000 10,000 E 1’ ~- I 9,000 9,000 8,000 8,000 /“ / ‘ -x” ––––– x 7,000 7,000 I 1/ : )% 6,000 IJ , - x— — — — — —x 5,000 E // 4,000 // 3,000 — 3,000 // ;/ n 2,000 n o 2<000 –e . F a) - 1,000 — 1,000 k i I 1 1 I 1977 1980 1985 1990 1995 2000 1977 1980 1985 1990 1995 2000

MEEKER RANGELY

26,000 — KEY 24,000 — .0 #@~ @ POPULATION 22,000 — 9%. /*”” 1977 SPECIAL CENSUS 20,000 — o 0 SCENARIO I—WITHOUT ~ 18,000 — fi ‘-0” ““ ENERGY DEVELOPMENT ~ 16,000 . If A x— —x ——x SCENARIO II—WITH ~ 14,000” — / /- PRESENTLY PLANNED / /- ~ 12,000 — ENERGY DEVELOPMENT / - - : 10,000 — /x- - ‘ ●-- - SCENARIO III—WITH *---O 8,000 — If / PLANNED ENERGY DEVELOPMENT AND OIL SHALE INDUSTRY 6,000 — ;/ OF 500,000 bbl/d IN 1990 4,000 — o m AND 750,000 bbl/d IN 1995 2,000 —e . AND 2000 I I I 1 I BASED ON JULY 1979 PROJECTIONS 1977 1980 1985 1990 1995 2000

RIFLE

SOURCE Colorado West Area Council of Governments growth. There are over 20 documents that Table 101 .–Projected Population Growth of identify specific needs expected to arise in Selected Oil Shale Communities, 1979-85 the period between 1980 and 1985. * Exam- Projected Projected ples in the following discussion have been population population Percent taken from these various planning docu- Community 1 979’ 1985b Increase merits. ”Z Rifle ., 3,200 22,060 589 Meeker : 2,250 16,745 644 Needs for the entire region are mainly in Rangely 1,900 14,088 641 the areas of health and education; over 90 aEsllmale at end of year percent of them are for improving schools bCWACOG Scenario Ill (does not Include tnnge areas around each town) and upgrading hospital facilities. Technical SOURCE OTA based on projections from the Colorado West Area Councd ot Governments assistance for CWACOG is also included. Compilation of regional requirements is com- *13ec:ausc the needs appear in plans prepared by different plicated by overlapping or differing jurisdic- groups al different tlmtx, a v[{ rle tv of CL I’ACOG pro j ert i ons tions for a number of services. For example, hate been emploved (see discussion at the beginning of the preceding sect ion). E’or this re:)son, i t is di ffirul t to I ink speci fir re- the Valley View Hospital, located in Glen- (lu i remen ts di re( t Iv t o the CL$’ A (;(X; populo t ion scenarios. wood Springs, in a recent needs assessment 452 ● An Assessment of Oil Shale Technologies included as a service area the central part of ficult, and local planners do not try to do so. Garfield County. This portion of the county The following discussion emphasizes oil shale encompasses Rifle, site of the Clagett Memo- development while recognizing that it will oc- rial Hospital, and overlaps the Grand River cur in the larger context. Hospital District in which the Rifle hospital is placed. School districts, although not overlap- Mesa County ping, encompass a number of different communities, which makes it difficult to separate The effects on Mesa County depend on the their requirements from those of the munici- location of development. At present, between palities. Sanitation and recreation districts 30 and 40 percent of the employees at Logan with differing boundaries add to the compli- Wash facilities operated by Occidental Oil cations. Shale, Inc., live in the Grand Junction area, and further development along the southern For Garfield County, planning documents rim of the Piceance Basin would add to these contain over two dozen projects needed be- direct effects in the county. Otherwise, they tween 1979 and 1984: 41 percent of them are are likely to be indirect, taking the form of in the area of education; 19 percent in the demands on the transportation and service health and medical services; 15 percent in sectors, both public and private, and on sup- public services, especially water supply proj- port industries. Benefits, such as increased ects; 11 percent each in mental health and revenues and cash flow, will occur when public facilities, the latter primarily roads; shale workers go to Grand Junction to pur- and 3 percent for welfare services. chase goods and services. Rio Blanco County and its communities, Meeker and Rangely, expect large growth De Beque is the Mesa County community from expanded shale development. For the now experiencing direct effects of oil shale period from 1980 to 1985, planning groups development activities. It is the nearest com- have identified five categories of needs for munity to Logan Wash and exemplifies sever- the county. About half are for public facilities al of the problems associated with boomtown growth. It is located in Mesa County, while and services: roads, highways, and bridges; Logan Wash is in Garfield County; thus tax airport improvements; trash compactors; a revenues from the energy development ac- public safety building; and similar projects. crue to a jurisdiction different from the one Educational necessities, hospital improve- receiving the impacts. De Beque has had dif- ments, recreational projects, and support for ficulty preparing for increased growth, par- the planning infrastructure make up the re- ticularly in dealing with the effects of infla- mainder. tion. A 1976 study detailed the improvements needed by the water supply system. It Needs From Oil Shale Development estimated the costs at $608,000; when bids were opened in 1978, they came to $787,000; Several different kinds of energy industry but only $500,000 was available. The city activities are taking place in the region. was unable to assume any additional debt Unless it is rapid, the expansion of the oil and had to turn to the State for help. When shale industry, in and of itself, may not completed, the facilities will be adequate for disrupt the communities of western Colorado; the present population but would have to be combined with accelerated coal development, expanded if a large number of new residents oil and gas exploration and production, the were to be accommodated. installation of electric generation plants, and the possibility of other synthetic fuel activ- Garfield County ities, the effects could be devastating. Sepa- rating the potential consequences of shale In 1975, the Colony Development Operation development from the combined effects is dif- proposed that a new residential community, Ch. 10–Socioeconomic Aspects ● 453

to be called Battlement Mesa, be constructed for planning purposes, and city officials feel south of the Colorado River near Grand Val- this number could be accommodated within ley. The Garfield County commissioners the next 3 to 5 years. Over 40 projects have granted zoning approval for the development been identified as needed between 1979 and of 7,000 housing units for up to 21,000 resi- 1984 to ease the effects of this expected dents, to be constructed over a 10- to 15-year growth. About half of these are for public fa- period. Colony invested a little over $3 million cilities, mostly water supply projects and in land acquisition and related activities for public buildings. About 10 percent are for Battlement Mesa. The new town was de- roads, and another 10 percent for public signed to serve the Colony shale activities on services, such as a new fire-rescue vehicle. Parachute Creek; actual development of the Educational expansion, including programs site was suspended when the company chose and buildings, account for another 10 per- not to move ahead with its plant. It is prob- cent, with housing, health, and recreation able the new town will be constructed in the projects representing the remainder. 1980’s. Rifle is beginning to display some symp- RIFLE toms of boomtown stress. The incidence of re- Rifle is the community displaying the most ported spouse and child abuse is increasing. visible effects of shale development activities. Statistics maintained by the police depart- It is estimated to have grown by about 1,000 ment show a rise both in the number of juve- residents from the 1977 census figure of nile crimes and in cases of substance abuse; 2,244. Using the increase in the value of alcohol abuse is the biggest problem. Mental building permits as an indicator, it has grown health personnel note an increase in the num- about 45 percent in the past 2 years, A pop- ber of individuals having problems in their re- ulation of 10,000 has been used as the target lations with other people. Consistent data col-

Photo credit OTA staff

View of Rifle, Colo. 454 ● An Assessment of Oil Shale Technologies lected over several years are not available in expanded. Because the expected growth did these categories, but what has been obtained not come to pass, the school is presently points to the emergence of increasing social operating below capacity; and the citizens, and psychological stress.64 while desiring it, view current promises of development with some skepticism.65 Like Silt A large number of retired persons live in and New Castle, Grand Valley has had to the area, and more than 20 percent of the place a moratorium on new building because population is estimated to be over 60 years the water and sewer systems are operating old. A number of programs have existed for at, or beyond, capacity. The town applied for several years for these residents, and they an EPA construction grant for a new sewage themselves are active advocates for their in- treatment facility in 1976 but did not know if terests. Should the current rate of inflation it would receive the funds until 1979. In the be compounded by increased costs from rap- interim, it tried to obtain money from the Col- id growth those who live on fixed incomes orado Department of Health, but was unsuc- would suffer even more than they are now. cessful. Although the EPA grant, plus assist- For some time, Rifle has had severe traffic ance from the Oil Shale Trust Fund, has now congestion. The main highway to the north been received, the site had not been approved goes through the middle of town, passing the in mid-l979. elementary and high schools. Dust and ex- Silt is one of the fastest growing commu- haust fumes, particularly from trucks, have nities in the valley. The population doubled polluted the downtown area. It has taken a between 1970 and 1977—from 434 to 859— long time to correct the problem because of and the town planner believes it was close to the necessity to coordinate plans with the 66 1,000 at the end of 1979. The CWACOG pro- State highway department. City services have jections estimate 1,211 by the end of 1980 been hampered by a lack of adequate office under energy development conditions (Sce- space. Rifle is in the first stage of a planned nario II). Current plans call for public facil- three-stage water expansion project. The en- ities to accommodate 2,800 residents by the tire project will accommodate 10,000 resi- mid-1980’s. These facilities include an im- dents, in increments of 3,000 to 3,500 per proved water supply and an expanded sewer stage. The sewer system is also currently system. The sewer system improvements are being upgraded. currently in the design phase and the water Sufficient land is available for about 1,700 system is already being upgraded. Like many new housing units; construction has been small communities, the town lacks sufficient underway in recent years. The junior high skilled manpower. There is only one police of- school building is being expanded and, on ficer and no budget for additional personnel. completion of the addition, will become a Only two people are in the public works de- combined junior-senior high school, A new partment, and they cannot keep up with the elementary school is needed and the city has increased workload. applied to the State for assistance in its con- In New Castle, ultimate growth probably struction. The hospital needs to expand its will be limited by the availability of land, outpatient facilities. The nursing home is since the town is located in a fairly narrow operating almost to capacity, and will soon part of the Colorado River valley. The official require repairs and renovation. CWACOG energy development projections estimate a population of 1,055 in 1985 and OTHER GARFIELD COUNTY COMMUNITIES 1,608 by 2000. The city is now improving its Grand Valley reflects the types of diffi- water supply and distribution system to per- culties faced by communities living with the mit additional growth; a moratorium on new uncertainties of energy development. Several water taps was necessary after a new ele- years ago, in anticipation of growth from in- mentary-junior high school facility was creased oil shale development, the school was opened. A revitalization of coal mining in the Ch. 10–Socioeconomic Aspects ● 455 area could combine with oil shale develop- cal; if the C-a tract begins production and the ment to add to growth pressures in the town. road is not available, permanent employees will choose to live in Meeker or Rifle, both of Because Glenwood Springs, the county which are now closer. Without this access, seat, is located in the eastern part of Garfield the opportunity to allocate some of the coun- County, the community will experience more ty’s growth to the Rangely area will be for- secondary than direct effects. The city has feited. been growing mainly from recreational development in the Aspen and Vail areas. If the MEEKER communities down the Colorado River valley are unable to cope with rapid growth, the Meeker grew about 15 percent between 1970 and 1977; its estimated population in consequences will extend to the Glenwood 67 Springs area. 1979 was 2,250 to 2,300. The community’s physical infrastructure (e.g., water, sewer, In sum, Garfield County has received most streets), when current improvements are of the growth so far from oil shale develop- completed, could support between 4,000 and ment. This growth has been combined with 5,000 residents; this figure may be reached in the expansion of other industries and, as a 1982 or 1983. However, the growth rate could result, the county has been pressed to meet accelerate. For instance, the draft EIS for the the needs of the new populace. All the com- proposed Superior development, in projecting munities in the area have increased popula- cumulative growth for its own and seven tion, and three have had to place moratori- other energy projects,68 places Meeker’s pop- ums on new construction because of inade- ulation at 5,077 in the first year of operation, quate water and sewer systems. Rifle should a doubling of the present estimated popula- be able to accommodate a population of tion in one calendar year. Even this projection 10,000 if current plans can be completed, but could be low, since there are more than this is already beginning to experience some of number of possible projects under considera- the symptoms of boomtown conditions. If action by different industries for the area. celerated growth occurs, Rifle will need additional funds in order to make public facilities Of the needs identified by local officials, 55 and services available to the new residents, percent are for public facilities and services, and will have to increase its efforts to prevent 15 percent for the schools, 19 percent for rec- social and individual stress. reational projects, 9 percent for day care and senior citizens’ support, and 2 percent are for Rio Blanco County hospital projects, Housing so far has kept up with demand. In the immediate area, four In anticipation of future growth, a signifi- subdivisions are under construction, and a cant planning effort has been underway for a mobile home park has been approved. Under half-dozen years, zoning and other growth- review, but not yet approved (in late 1979), control laws have been enacted, and support were another mobile home park and a num- for these measures appears widespread. ber of smaller subdivisions, none of which is Roads have been a longstanding need but presently within the Meeker water service their cost has proven a barrier to construc- area. Furthermore, the town is presently tion. Extension of County Road 24 from the committed to the subdivisions now being built C-a tract site to Rangely was proposed by the for 100 percent of its available water taps. developers in their early plans (see figure 74); Although the streets within the large subdivi- however, the State legislature has been reluc- sions will be built by the developer, the town tant to appropriate funds for construction, A must provide the main arteries to those feasibility study of 10 alternatives was made areas. The wastewater treatment plant is and 1 was recommended to the State: plan- committed almost to capacity, and planning ning for it is now underway, Timing is criti- has started for its expansion. 456 ● An Assessment of Oil Shale Technologies

Figure 74.— Area of Proposed Road From Rangely to Oil Shale Tract C-a

I "-=-- ~L---/ PROPOSED ACCESS ROAD I TO RANGELY

(

KEY

------Proposed extension of County road 24 for direct access to Rangely

-_. -' --. Electric transmission line

------Buried telephone cable

Pipeline

SOURCE 1977 Ad Addendum to the RIO Blanco Oil Shale Project Social and Econmic Impact Statement. Ch. 10–Socioeconomic Aspects ● 457

The construction of water and sewer facil- approval of the State DLA but an application ities is an example of the kinds of projects re- for an exemption filed by the city in 1976 was quiring adequate leadtime. If Meeker fails to turned down. A manpower shortage plagues begin preparing to expand its water supply the city government. During the summer, and sewage treatment capacity now, it will when demands for labor are highest, the not be able to absorb increased growth in 3 to town has used inmates from the jail for assist- 5 years. These kinds of improvements also ance. According to the town manager, all of serve as examples of the financing difficulties the municipal government staff but two are faced by rural towns. In constructing its pres- paid salaries lower than the HUD poverty ent water system Meeker created a $2.4 mil- guidelines for rural Colorado.70 lion debt that requires an annual debt service Overall the incidence of symptoms of social equivalent to 20 mills of the property tax levy. stress has not been increasing at the rate seen in other towns. A shift in the types of crimes committed has been noted, with increases in thefts, bad checks, and drug-related incidents; and a rise in the number of runaways has occurred in recent years. The number of cases reported by the police has increased at a faster rate than the population growth. ” The hospital outpatient services are operating at capacity; an additional emergency room and laboratory are pressing needs. The school district is operating below its total capacity but some of the individual schools are full. A new elementary school will be needed between 1981 and 1982. Attitudes about growth have been divided. In a survey conducted in 1974, 35 percent of the respondents agreed and 53 percent dis- Photo credit: OTA staff agreed with a statement that the majority of growth from resource development should oc- Approximately $760,000 will be required to cur in Meeker. The town manager said in expand the storage capacity of the water sys- 197972 that he felt the community wishes tem and $2.5 million to upgrade the waste- enough growth to pay the indebtedness in- water treatment plant. Thus, the city is fac- curred by construction of public facilities and ing a potential additional debt of over $3 mil- to provide new amenities such as a larger su- lion in the next 3 to 5 years. permarket and expanded recreation facil- Meeker also reflects some of the adminis- ities. trative difficulties faced by growing towns. Colorado’s statute, which restricts spending RANGELY by municipalities (except home-rule cities) to Rangely finds itself in the paradoxical posi- a 7-percent increase over the annual proper- tion of desiring additional growth but foiled in ty tax revenues,69 means for Meeker that the its efforts to obtain it. The biggest difficulty maximum the town can increase its spending has been gaining improved access to oil shale is about $3,000 per year. Recently, the annual activities. The proposed road to tract C-a was inflation rate has approached 16 percent, discussed above.Rangely’s - - ‘earlier - - experi- which makes such a small increase essential- ences with oil and gas booms have made the ly nil in real revenues. The statute does pro- town receptive to energy development and vide for some administrative relief with the the residents feel that growth from an ex- 458 ● An Assessment Oil Shale Technologies panded oil shale industry would be benefi- town is unable to attract more families, the cial. expansion of the schools will leave the buildings half-full and the remaining residents In addition to the access road, a dozen proj- burdened with the debt of the expansion. The ects are judged to be needed by 1985. Half of optimism of the citizens is reflected in their these are for public facilities, such as a water willingness to approve construction of a new supply pipeline to areas of new home con- indoor recreation facility that opened in the struction. With improvements, the water sys- late spring of 1979. tem could serve a population of about 11,000 and the sewer treatment facilities are ade- The Rangely area has a strong feeling of quate to serve 10,000 people if the sewer identification with eastern Utah. The town is mains can be upgraded. Because of the need located about 15 miles east of the border. It is for these improvements, however, the capaci- a little over 45 miles to Vernal, Utah, less ty of the town between 1985 and 1990 is esti- 73 than the distance to Meeker (57 miles) and to mated at only 6,000 residents. Like most Grand Junction (85 miles). The road to Grand rural health care facilities, the Rangely Junction goes over Douglas Pass (8,628 ft), Hospital has had to defer some maintenance making the route less appealing than the flat- and equipment needs in order to meet oper- ter highway to Utah. For these reasons, it is ating expenses but will have to take care of easier for Rangely residents to travel to Ver- them before services can be provided for a nal. Colorado officials have sometimes acted larger clientele. in a way that the residents view as reinforc- Recent school construction has provided ing their links with Utah; it took about 40 sufficient capacity to absorb more pupils, but years to get the State to build the road over this again reflects Rangely’s paradox. If the Douglas Pass. If the region experiences rapid

Photo credit OTA staff

Recreational facility in Rangely, Colo. Ch. 10–Socioeconomic Aspects • 459 growth from oil shale development, the feel- ble 102. The table shows clearly where the ings of being ignored could add to other nega- local leaders see the greatest constraints on tive impacts. Moreover, if the oil shale activ- growth: water supply systems for the munici- ities are in Utah but the workers live in Col- palities, schools, and medical and health orado, a prime example of the problems of ju- services and facilities. Several towns in- risdictional mismatch will occur. dicate a need for more personnel. Rifle and Meeker are the communities with the largest In sum, Rio Blanco is the least populated number of priorities. Assuming that the proj- county with the most limited highway system. ects now underway are completed, Rifle Planning is well advanced with provision for should be able to absorb, between 1985 and extensive community participation. Some ur- 1990, up to 10,000 people, The other Garfield gent needs, such as improved access to the County communities in the oil shale vicinity Federal oil shale tracts, have not been met could accommodate about 7,000 and the with as rapid a response as the local citizens rural areas between 1,500 and 2,000 per- might have wished; the State legislature has sons. If construction were started immediate- been reluctant to appropriate the large sums ly, the new town of Battlement Mesa might necessary for these projects. Rangely desires house 2,500 people by 1985. In Mesa County, growth but will not receive much if a road to De Beque might be able to accommodate a tract C-a is not constructed; Meeker is less in- total of 700 to 1,000 but most workers from clined to have more growth than it has al- the southwestern part of the Piceance basin ready gotten from coal development, yet may will probably reside in the Grand Junction have to absorb new population from oil shale area. In Rio Blanco County, both Meeker and activities. Rangely are judged to be capable of providing for 6,000 persons apiece, ” A total of 2,000 Summary people might live in the rural areas. Alto- The socioeconomic consequences of oil gether, by 1985 Garfield County could accom- shale development depend, among other modate about 21,000 and Rio Blanco about things, on the location of the activities. In- 14,000, for a total of 35,000 residents. (See creased development of the private lands table 103, ) along the southern rim of the Piceance basin Other than the planning efforts of will lead to growth in Garfield and Mesa CWACOG, no systematic evaluation of the Counties and the communities of the Colorado full range of consequences for the entire re- River valley. Additional activity on the Fed- gion is being undertaken. For example, the eral lands in Rio Blanco County will mostly af- draft EIS for the proposed Superior Oil Co. fect Meeker and Rangely, although Rifle project 75 discusses, in the section on cumula- could grow as well from this expansion. In tive impacts, seven other activities that might Moffat County, Craig could be influenced by interact with the Superior development. How- activities in the northern section and, if devel- ever, a total of 30 energy-related projects are opment occurs in Utah, Dinosaur and Rangely identified by CWACOG and impact studies as would be directly affected. Growth will tend possibly affecting the region. Similarly, plan- to concentrate in established communities ning documents give attention to individual where services are already available. The counties or communities but do not address limited surface transportation system will areawide problems in detail. For instance, also foster concentration. In Rio Blanco Coun- the relationships and responsibilities of local, ty it is encouraged by a zoning policy that is State, and Federal government agencies are intended to direct growth to Meeker and critical for communities facing boomtown Rangely. conditions, but they are not dealt with in any The needs by county and community be- of the plans. Jurisdictional mismatches also tween 1980 and 1985 are summarized in ta- are seldom addressed. Development on pri- 460 ● An Assessment of Oil Shale Technologies

Table 102.–Priority Needs Identified by Oil Shale Counties and Communities, 1980-85’

Source of request Regional ... ., . . . ● ● Mesa County ● ● ● ● ● De Beque ● Garfield County ..... ● ● ● ● ● ● ● Grand Valley ● ● ● ● ● New Castle ● Rifle ● ● ● ● ● ● ● ● ● ● ● Silt ● ● ● ● ● ● Rio Blanco County ● ● ● ● ● ● ● Meeker. ● ● ● ● ● ● ● ● ● ● ● ● Rangely. ● ● ● ● ● ● ● ● ● Me//at County ., ● ● ● ● ● ● ● ● ● ● Dinosaur ● ●

‘See ref 62 for Iwhng of sources of needs blnclude~ ~uppofl for plannlng Infrastructure dfld personnel needs of local a9encles

SOURCE Olflce of Technology Assessment

Table 103.–Actual and Projected Population and Estimated vate oil shale holdings in Garfield County Capacity of Oil Shale Communities in Colorado could cause rapid growth in Mesa County, Population and workers in Utah could reside in Colorado; 1977 1980 1985-90 neither problem has been systematically ana- Location a census b projected capacityd lyzed. Garfield County Rifle 2,244 4,362 10,000 Silt 859 1,211 2,800 New Castle 543 831 1,000 Potential Effects of Accelerated Grand Valley 377 589 3,000 Battlement Mesae — 198 2,500 Development Other, – – 1,700 Subtotal f ., ., 4,023 7,191 21,000 The response of a given community to Rio Blanco County growth depends on a number of elements. Meeker 1,848 2,779 6,000 Among these are: Rangely : : 1,871 2,223 6,000 Other 1,381 1,542 2,000 ● the absolute numbers and abruptness of Subtotal 5,100 6,544 14,000 the population influx; Total 9,123 13.735 35,000 ● the attitudes of both long-term residents aDoe~ not Include Mesa or Moffal Coun!les both of wh[ch are more distant from the area of devel and newcomers; opment ● past experiences with boom and bust bActua[s from a special U S census cEnd 01 (he year projecl(ons by [he Colorado wt’Sl Area COUIICII Of Governments cycles; OTA dEs(lma!ed by from various plannlng and needs asSeS5Menls documents assumes comPle- ● Ilon of cu{renlly planned projects (e g hous[ng water and sewer system expansions street the ability of local political structures to and road (mprovemenls elc ) prepare for population growth; and eA new [own construc[jon anticipated 10 begin In fhe early IWO s ● f(ncludes only the lmmedlate 011 shale ~lclnlty the availability of assistance—financial SOURCE Olf(ce of Technology Assessment and other—for mitigation of impacts. Ch. 10–Socioeconomic Aspects ● 461

Whether the consequences of growth are fa- Oil shale development has been and will vorable or unfavorable depends on whether continue to take place concurrently with the people can adapt to the stresses accompa- other activities, especially energy-related nying change. This ability is unique to each ones, such as coal, uranium, oil, and gas pro- community and must be viewed as part of a duction. Dealing with the cumulative effects dynamic set of complex events. Conclusions of all the growth may prove difficult. In addi- about the possible effects of future oil shale tion, the nature of new oil shale ventures is development must recognize the complex and unclear, Factors of particular importance for changing nature of the different communities social and economic adjustment will be the: and of the events impinging on them. ● number—how many new oil shale devel- Industrial expansion in western Colorado opments occur; will have positive as well as negative conse- ● size—how large the facilities will be; quences, In the economic sphere, a primary benefit will be increased economic activity. ● location—where shale mining and proc- The direct effects of increased employment, essing activities take place; higher wages, and stimulation of support in- ● timing—when each is built and how this dustries and services would be felt through- relates to other development; out the region. Both the public and private ● rapidity—how quickly any new ventures sectors would benefit from industrial and are built; and services expansion. Towns and counties should enjoy a broader tax base. A sense of ● type—the nature of the technology and identity and pride, combined with an antici- ancillary processes chosen. pation of the advantages of growth, have already been manifested. Planning activities, The position of the State regarding both oil such as the preparation of the master plan shale development and social and economic for Rangely, have contributed to the public’s impact mitigation is also not certain. Until expectations for the future. The successful more is known about these factors, the exact operation of the task forces that propose solu- nature of the population in-migration that will tions for growth problems is tangible evi- accompany new development cannot be ade- dence of increased sociological and psycho- quately projected, nor can the full dimensions logical cohesion. The confidence that many of the consequences, both positive and nega- local officials express in their community’s tive, be forecast. So long as oil shale devel- ability to deal with growth is also an indica- opment continues according to the plans tion that, to date, the social consequences of already laid, the people of oil shale country oil shale development have been positive. The should be able to adjust to the resulting involvement of the oil shale developers in growth. Only if expansion occurs suddenly or growth management efforts shows industry’s to a greater degree than now planned will responsiveness to the social effects of its ex- boomtown consequences occur. (See ch. 3 for pansion. a further discussion.) 462 • An Assessment of Oil Shale Technologies

Issues and Policy Approaches Summary of Issues definitions of the two classes are rarely spelled out. As an illustration, concepts such Identifying and Evaluating Social and as the “degradation of the quality of life” are Economic Impacts used; and a variety of indices, like an increase in the number of visits to a mental In the usual course of economic develop- health clinic, are cited to support the finding ment, Government assistance in coping with of “degradation.” Yet there is hardly ever the consequences of growth is not a prime verification of the causal chain presumably concern. One question underlying energy de- linking rapid population influx to the indices velopment is the distinction between effects and thence to perceived changes in the quali- that can be handled by local communities— ty of life. that is, those that can be considered a normal concomitant of development; and those that Finally, several of the most important are problems because they cannot be readily boomtown consequences are hard to measure solved by local resources—boomtown effects. (for example, the ability of newcomers to ad- An example of criteria used to make this just to an established community); and the distinction is found in section 601 of the changes in the social structure may not be Powerplant and Industrial Fuel Use Act of manifested immediately. A question that has 1978. These include increased employment of not received great attention is whether the 8 percent or more per year in coal or uranium long-term basic changes are more important activities, a resulting or projected housing than the immediate ones occurring at the shortage, and inadequate State and local fi- onset of a boom. nancial resources to meet needs over a 3-year period. The debates about oil shale development include conflicts involving these kinds of Thus far, Federal agencies have assisted in value judgments. On the one hand is the need the identification of boomtown conditions for synthetic fuel production; on the other are mainly through data-gathering and informa- the boomtown consequences for communities. tion-sharing activities. With respect to eval- Who participates in the definition of positive uation, the position is that “local communities and negative impacts and in the resolution of and counties must take the initiative to be- the value conflicts that emerge is an impor- come involved in assessing, planning for, and tant issue. At present, in Colorado, local mitigating socioeconomic impacts . . . .“76 groups play a large part in this evaluation. They identify the impacts they believe will af- The process of evaluating impacts involves fect their communities, decide which ones are their classification as either positive or severe enough to require corrective action, negative. This requires making value judg- and participate in the decisions to allocate ments about what is good or bad for particu- resources for mitigation. Federal programs lar individuals, communities, regions, and the designed to assist communities must recog- Nation. Often there are conflicts—what is nize what has been done to date and face the seen as good for the Nation may entail diffi- issue of the allocation of responsibility for culties for individuals or disruptions of com- these decisions. munities. Additionally, what is judged as a positive impact for one group may appear as a negative one for a different group. Determining a Maximum Growth Rate The process is further complicated be- How rapidly can the communities expand? cause the basis for distinguishing positive How much growth can be accommodated be- from negative impacts is seldom clearly de- fore a community breaks down? The social lineated, and the assumptions underlying the and economic impacts of oil shale develop- Ch. 10–Socioeconomic Aspects ● 463 ment will depend on the total number of newcomers, the rapidity with which they come into the area, the size of the industry’s expansion, its location within the oil shale region, and the ability of the communities to prepare. The maximum amount of growth the different growth. areas can accommodate without incurring boomtown consequences is a critical ques- The Mitigation of Impacts tion. Solving the problems Attempts to determine a maximum rate volves local, regional, State, and Federal have discovered that generalizations are dif- agencies. Questions about the role of the ficult to derive and that the capability to ad- Federal Government fall into two categories: just to rapid growth turns out to be highly site specific. Whether communities will suffer ● the extent to which the Federal Govern- from rapid growth or take it in stride depends ment should be involved, and on a unique set of factors within each indi- ● the form the involvement might take. vidual community, for example, the threshold The first category raises the fundamental when negative impacts outweigh positive question of whether the Federal Government ones. Since the positive and negative impacts should be involved at all. The extent and may vary from one town to the next, estab- nature of Federal involvement in impact miti- lishing this threshold is highly dependent on gation are controversial. On the one hand it is local conditions. In the past decade, identify- argued that social and economic impacts are ing and measuring the social changes that ac- State and local problems which should be company rural energy development have reviewed as the inevitable consequences of in- ceived increasing attention. The results have dustrial development. On the other hand is been an expansion of the factual base de- the position that national requirements are scribing these changes, and a more system- the root causes of the local impacts, therefore atic framework for seeking to explain them. an expanded Federal role is appropriate. Sev- To date, however, there are neither sufficient eral Western States have taken the stance facts nor theories to understand fully why that expanded domestic energy production is one town becomes vulnerable to boomtown a national goal and thus, for reasons of equi- impacts but a similar one does not. ty, the Federal Government should assume a No systematic study of the factors deter- more direct role in the alleviation of negative mining a maximum growth rate is being car- impacts from this development. ried out for the oil shale communities. The The second category deals with the nature groups presently involved in growth manage- of Federal involvement. One position states ment and planning would benefit from a de- that present programs are sufficient but that termination of thresholds of growth for their the amount of money they provide needs to be individual communities and policy makers increased. Another is that Federal regulation could use this information when considering could be used to mitigate impacts by, for ex- the rate of future development. The popula- ample, pacing industry’s growth rate through tion of the Colorado oil shale region was leasing policies. A third position is that the about 10,000 in 1977 and is projected to be Government should be directly involved in about 14,000 by the end of 1980. OTA esti- mitigation programs that use Federal funds. mates that the communities could accommodate up to 35,000 total residents during the The question of the effectiveness of mitiga- period from 1985 to 1990. This assumes that tion programs arises as well. Some observers construction of the new town of Battlement contend that the success of oil shale mitiga- Mesa in Garfield County is started in the near tion processes to date is proof of their effec- 464 ● An Assessment of Oil Shale Technologies

tiveness. Others maintain that the processes Background have never been adequately tested because rapid, large-scale development has not yet oc- The initial action responsible for consid- curred, and that existing programs could eration, in public policy decisions, of the so- break down under such circumstances. Most cioeconomic effects of Federal projects was the National Environmental Policy Act of questions about the effectiveness of the proc- 77 esses relate to intrastate issues. For example, 1969 (NEPA). It requires Federal agencies to it can be questioned whether the legislative consider environmental factors in decisions approach to disbursement of the Oil Shale involving “major Federal actions significantly affecting the quality of the human environ- Trust Fund deals adequately with the desires 78 of the oil shale counties. The Federal Govern- ment. “ The broad wording of the Act has led to a considerable amount of litigation. In ment could respond to such questions by, for 79 example, providing funds directly to the com- these court cases, NEPA has been inter- munities. The desirability of such an action is preted as granting authority for the imposi- a topic of current debate, however. tion of conditions to mitigate adverse social as well as environmental impacts. As a result Increased Federal assistance probably will of the litigation, and subsequent regulations be required if the region experiences sus- issued under NEPA, socioeconomic consid- tained rapid growth. This could come about erations have of late received greater em- from accelerated oil shale development, but phasis in the preparation of EISs. is more likely to be the consequence of com- The Coastal Zone Management Act bined growth from several industries. Aside 80 from the planning efforts of CWACOG, which Amendments of 1976 set up a program of are limited to northwestern Colorado, no sys- assistance for communities experiencing im- tematic evaluation of the full range of effects pacts from Outer Continental Shelf (OCS) from an increase in all types of industrial energy development. Loans, loan guarantees, growth on the entire region is being under- and grants are available to States and com- taken. Thus, it is difficult to determine which munities where an energy facility planning process has been established under the types of Federal assistance might be the most 81 productive. Coastal Zone Management Act of 1972 (CZMA). Site plans must include the identification and mitigation of anticipated adverse Policy Approaches impacts from OCS-related development. The program is tied closely to land use planning Confronting the social and economic effects of an expanding domestic energy indus- mechanisms that State and local governments try involves policies for all parts of the Na- are required to develop if they participate in tion. Concern for the consequences of oil the coastal zone management program. The shale development, however, for the time impact assistance portion depends upon the initiative of the States in meeting the CZMA being centers only on northwestern Colorado, east-central Utah, and southwestern Wyo- requirements; Federal involvement is there- ming. In addition, although the impacts them- fore indirect, in the sense that the policy makes Federal funding contingent upon the selves are basically similar regardless of the establishment of State and local land use geographic region, the responses of particular communities can differ significantly de- planning processes. pending on the State and location involved. In March 1978, DOE published for the En- Flexible policies are best, given this situation. ergy Impact Assistance Steering Group a Re- The following discussion is concerned with port to the President—Energy Impact Assist- policies that bear most directly on the effects ance.82 The Steering Group, composed of rep- of a larger oil shale industry. resentatives from Federal, State, local, and Ch. 10–Socioeconomic Aspects ● 465

Indian Tribal governments, was established viding funds to the States and improving the following a meeting of several Governors with delivery of existing Federal programs (e.g., the president in mid-1977. At that time the the establishment of a “one-stop shopping Governors expressed concern for potential center” where local officials can go to deter- adverse results from the 1977 National Ener- mine whether their towns are eligible for the gy Plan. Four policy options were presented many Federal programs already available). representing “different points along a con- tinuum ranging from minimal new efforts to A recent departure from this theme is undertaking major program reform and in- found in the Energy Impacted Area Develop- vestment of substantial new Federal funds, ] ment Assistance Program that was enacted (See table 104.) in the Powerplant and Industrial Fuel Use Act of 1978 (sec. 601).86 This program, admin- In an effort to pull together the various istered by FmHA, is designed “to help areas Federal programs that can assist communi- impacted by coal or uranium development ac- ties, the Region VIII FRC has created an tivities by providing assistance for the devel- Energy Impact Office. Its establishment was opment of growth management and housing a direct response to recommendations of the plans and in developing and acquiring sites National Governors Conference and of the for housing and public facilities and serv- General Accounting Office (GAO) .8’ A GAO ices. ” The probability of greater Federal in- report, published in 1977, concluded that at volvement in the direct amelioration of im- that time the need for additional Federal as- pacts is reflected in the amendments to the sistance to impacted communities had not Powerplant and Industrial Fuel Use Act con- been demonstrated, Among its conclusions, sidered during the fall of 1979. A review of the report stated: the problems, legislative issues, and propos- Rocky Mountain State and local govern- als being considered by the 96th Congress is ments should be primarily responsible for available in a Congressional Research Serv- providing facilities and services prior to or ice (CRS) study titled Energy Impact Assist- concurrent with population increases , . . ance: A Background Report prepared for the It is not industry’s responsibility to pro- Senate Committee on Energy and Natural Re- vide the facilities and services needed be- sources.87 cause of energy resource development. But industry does have a strong and continuing In general, the Western States have responsibility to communicate its plans to adopted policies that supplement and fill gaps State and local governments, as soon as pos- in Federal programs. Colorado provides sible, and to establish and maintain a con- funds, from Federal revenues and a State sev- tinuing liaison with these governments, erence tax, and technical assistance to coun- The Federal Government should continue ties and towns with growth problems. The to provide some assistance ., . (but) the need State’s position is that local initiative must be for additional Federal assistance at this time central in the mitigation process. As a result, has not been demonstrated. sentiments are strong among leaders in Col- GAO believes there should be some assur- orado’s oil shale communities that local gov- ances that impacted communities will re- ernment should play a significant part in the ceive funds available to mitigate the socio- control and management of growth.88 For a economic impacts of energy resource devel- 85 number of years, because of the delays in oil opment. shale development, these leaders were skep- A theme running through each of these tical about its eventual occurrence; now they Federal policy documents is that the Federal are fearful that a national crash program role regarding the social and economic ef- might ignore the plans that they have so care- fects of energy development should be pri- fully laid and cause a population surge that marily indirect assistance. Examples are pro- the communities could not absorb. Utah has 466 ● An Assessment of Oil Shale Technologies

Table 104.–Selected Policy Options, 1978 Report to the President

Option A Option B Option C Option O Modification and expansion of Expansion of industry role and Enhancement of State, local, and existing programs to assure modification/reprioritization of Tribal capabilities through new greater Federal share of New Federal grant program Need areas existing programs initiatives and programs long-term costs to pay long-term costs

. . , . , ,. A . , , .- Information implementation or national energy Opation A, plus nave appropriate Option B, plus establishment Option C information systems by DOE Federal agencies give prior noti- by DOE of a new information with State/local/Tribal access fication to State/localities, and system to gather and dis- to certain NEIS data Tribes of BLM, OCS Ieasing seminate impact assistance Encourage States to require in-m- plans, decisions and other data related data from energy de- industry release of employment, related to industry projects pro- velopers ($1 5 million). population, and siting data for posed to Federal agencies, im- proposed projects as precondi- prove conformance with NEPA tion for receipt of certain State/ and A-95 review processes local permits (water, construction, etc )

Participation in Continued ad hoc efforts by Issue Presidential Executive order Option B, plus establishment Option C decision making State/ local governments and requiring Federal agencies to of due process mechanism to Tribes to impact Federal deci- provide for State/local/Tribal in- review appeals of Gover- sion processes on energy re- volvement m all energy develop- nors/Tribal officials. source development and project ment decisions affecting their siting. jurisdictions, and to provide for consideration of the findings of the impact assessment teams prior to final decisions.

Planning and Conduct joint Federal/State/lo- Option A, except Incorporate new Option B, plus require all Option B management cal/Tribal impact assessments planning monies into proposed Federal energy decisions to ● Establish Federal/State Provide Federal technical assist- comprehensive State energy be compatible with approved assessment teams as ance and information to commu - planning and management bill, State impact mitigation specified. mties which are now, or ex- and specifically target new strategies ● Federal assistance to pected to experience energy de- funds to support State/local/ State to develop facility - velopment Tribal participation on assess- siting mechanisms and to Increase funding under selected ment teams and ongoing im- provide intial and sec- existing planning program by pact-related capabilities. A set- ond-round planning $20 million and target to energy aside of funds for Tribes would grants ($1 5 million). impact areas be provided. Also, bonus funds Ž Federal compatibility re- for States with energy facility - quirement siting mechanisms. Coordination of Expand the role of the Federal Option A, plus designate DOE as Option B, plus issue Execu- The Federal agency desig- assistance pro- Regional Councils in coordinat- lead agency to oversee and sup- We order mandating appro- nated as the lead assess- grams ing and packaging assistance port coordination of programs at priate Federal agencies to ment agency would be re- funds to energy-impacted areas, the regional level through an in- support FRC efforts and to sponsible for coordinating make greater use of joint fund- interagency board give priority consideration to all relevant Federal pro- ing authority. funding requests channeled grams, through this mechanism

Financing Modify requirements of selected Establish Federal loan and loan- Option B, plus increase EDA Establish a new program to existing programs to provide for guarantee programs in EDA with funds by additional $50 mil- provide grants to the eligibility and priority for funds forgiveness provisions and com- lion and authorize grants as States for. to impact areas (within existing petitive interest rates to be used well as loan/guarantees. –State revolving funds statutory Iimits) by States, communities, and ln- ($125 million plus$60 mil- ($200 million) Increase funding of selected pro- dian Tribes ($75 million) lion for 306). Priority to –Highways construction grams by $30 million to offset Fund sec. 306 of the proposed States, etc , with Increased and railroad grade sepa- reduction in funds for other pri - Coal Conversion Act ($60 mil- commitment of State/local/ rations. ority needs (e g , urban pov- lion) Tribal revenues and facility –Mismatches ($10 million) erty) Give priority to States, etc , with siting procedures. (Interstate and State/ Give priority to States, etc , energy facility-siting mecha- Suboption Tribal) securing industry cost-sharing nisms Consolidate Coastal Energy –Loan guarantees ($15 Possible amendment to Federal Impact Program and sec. million). tax code to encourage prepay- 306 program into EDA to Fund housing support in ment of taxes by Industry create single, flexible pro- sec. 306 but expand and gram to relet Infrastructure augment to cover energy needs m all States facility construction and 011 shale development ($60 million).

Annual $50 million $160 million $212 million $300 million authorization SOURCE Department of Energy DOE /lR-0009, UC 13. Ch. 10–Socioeconomic Aspects . 467 been faced with rapid growth from coal and to several reviews of existing policies and to uranium development, and has not planned suggestions of ways to achieve a more unified extensively for oil shale activities. The State policy. Congress has had before it proposals created a Community Impact Account in 1977 for a comprehensive inland energy impact as- to provide loans and grants to areas impacted sistance program, but to date none has been by mineral resource development. Because it enacted. Up to the present, return to the is the only funding source in the State de- States of portions of the lease, rental, and signed to respond to problems associated bonus payments for development on Federal with energy development, requests for help lands has been the major Federal contribu- have far outstripped the available monies. tion to mitigation efforts. Wyoming does not anticipate consequences Colorado has an ambitious set of policies from shale development in the near future, and programs to assist with impact mitiga- The State has an array of mitigation pro- tion. Overall, these efforts have been suc- grams dealing with other energy industry im- cessful in helping the oil shale counties and pacts that could be adapted to growth prob- municipalities to get ready for shale develop- lems from accelerated oil shale activities. ment. The ability of existing policies to deal with a large or sudden population influx, Evaluation of Existing Policies such as might occur with the rapid expansion The diverse nature of present policies, Fed- of the oil shale industry, is as yet untested. eral and State, makes their overall evaluation The uncertainties about the specific growth difficult. State policies vary: Colorado places of the industry make it difficult to evaluate emphasis on local initiative and advocacy, whether any policies—Federal or State—will whereas Utah and Wyoming emphasize more be adequate to deal with the effects of rapid centralized State determination of needs and expansion of the industry. allocation of funds. At the present time, there is no single Federal policy with respect to the Approaches to Impact Mitigation social and economic effects of energy produc- There are three approaches available to tion. Some programs are operating that ad- Congress when considering the social and dress certain aspects of these effects but, at economic effects of oil shale development. present, none speaks directly to the general The impacts can be viewed: impacts that may come with synthetic fuel development nor to the specific effects of accel- ● as part of the consequences of all kinds erated shale oil production. A limited amount of energy development; of assistance is available through avenues Ž as an aspect of specific energy initia- not specifically designed to deal with energy tives; or development impacts, but these Federal pro- • as the result only of shale development. grams each have different emphases and From the perspective of the first approach, modes of providing help. While they may be oil shale impacts would be included along adequately fulfilling their policy mandates, with the problems accompanying all domestic the specific nature of the mandates means energy efforts. As noted above, Congress has that the entire range of problems is not being recently considered bills providing compre- addressed. Additionally, even though steps hensive assistance for these problems, and have been taken to consolidate the frag- programs for oil shale could be in such legis- mented nature of Federal programs, effective lation. The second approach would place implementation of a more uniform set of prac- shale impacts along with those from other tices has yet to reach the oil shale commu- major national efforts. Proposed amendments nities. to the Powerplant and Industrial Fuel Use Act An increasing recognition of the problems of 1978 are illustrative. These amendments caused by national energy decisions has led are directed to the adverse effects of major 468 ● An Assessment of Oil Shale Technologies energy developments, which could include oil ing levels. The fragmentation of programs, shale. They authorize grants, loans, loan now viewed by some States and localities as a guarantees, and payments of interest on barrier to efficient delivery of Federal aid, loans, and propose an expediting process for probably would not be reduced. present Federal programs as well as an interagency council to coordinate Federal assist- INCREASED FEDERAL INVOLVEMENT IN ance. The third approach sees the effects as GROWTH MANAGEMENT the result of oil shale development alone. In This option would emphasize regulation. this case, specific language dealing with so- Present Federal revenue sharing would con- cioeconomic impacts could be included in tinue. Several possibilities exist for increased bills providing for the development of oil growth management participation. consid- shale resources. eration of social and economic effects on adjacent communities could be made a part of Regardless of the approach adopted for oil executive agency criteria when selecting shale, there are three options that Congress Federal lands for energy mineral leasing. In can consider to address social and economic this case, given natural resource deposits of impacts. approximately equal value, leases would be made available only in areas where the socio- CONTINUATION OF PRESENT PROGRAMS economic impacts could be minimized. Also, Under this option, Federal assistance the number and timing of leases could be ad- would continue to emphasize revenue sharing justed to take into account the ability of near- and technical assistance. Funding through by communities to absorb growth. Finally, the existing channels, such as the Mineral Leas- lease provisions could include mandatory ing Act, as amended, would be the major participation of lessees in mitigation efforts. mechanism. Certain other existing Federal Greater involvement of Federal agencies in programs, not now designed to deal specifi- monitoring socioeconomic impacts and in pro- cally with socioeconomic impact mitigation, viding assistance to mitigation efforts is could be redirected. For instance, EPA water another alternative. For example, the regula- and sewer grants could be accelerated, with tory activities of the Area Oil Shale Super- additional appropriations made available visor’s Office could be expanded to include and limited to impacted communities. Restric- monitoring social and economic indices in off- tions on existing programs could be modified. tract communities. Attention could be given An example is Federal housing programs, to difficulties not now being systematically now restricted to projects for low- and faced, such as interstate jurisdictional prob- moderate-income families, that could be pro- lems between Utah and Colorado. The Region vided to rural communities undergoing rapid VIII Energy Impact Office could have a field growth regardless of local income levels. representative permanently stationed in oil The advantages of this option are that it shale country to provide the services of FRC would require only minor adjustments to ex- locally. This representative could provide isting laws. Mechanisms for delivery are technical assistance to area planners and already in place. Flexibility would be main- could address problems they are too busy to tained since the focus would be on already consider now, such as anticipating the post- established programs designed to meet a va- boom period. Increased technical assistance riety of needs. The disadvantages include the could also address the problems of defining possibility that the amount of aid might not be and identifying boomtown conditions. A de- adequate to meet the demands of severely im- termination of the maximum growth commu- pacted communities. In this case, appropria- nities could sustain without experiencing tions would have to be increased for some severe disruption would be valuable for pol- programs now being held at particular fund- icymakers at all levels. Ch. 10–Socioeconomic Aspects • 469

Identifying and evaluating social and eco- adopted. The Powerplant and Industrial Fuel nomic impacts, determining a maximum Use Act of 1978, section 601 program, is the growth rate for specific sites, and coor- obvious candidate for extension. Under this dinating Federal programs are needed in all Act,89 Federal assistance was provided for parts of the country experiencing energy- areas experiencing rapid growth from coal or related growth, Thus, actions to deal with uranium production. The assistance is aimed these problems would be of nationwide value, at improved planning for growth manage- For this reason, R&D could be undertaken by ment, and for land acquisition for housing any of several agencies on a national basis, and public facilities development. Expansion and would not necessarily have to be limited of the program would include areas affected to the oil shale region. by growth from industries other than coal and uranium producers, and could encom- Among the advantages of this option is that pass a wider range of problems than growth it would supplement existing mitigation pro- management planning and land acquisition. grams already established by local and re- A bill to expand the section 601 programs is gional entities. It would provide a link be- currently under consideration. * tween Federal decisionmaking bodies and State and local agencies responsible for The advantages of this option are that it growth management. Access to Federal pro- expands an already existing program. The grams would be enhanced. Among the disad- mechanisms for implementation are in place vantages are the increased bureaucracy and have already been operating under the needed to implement the option, and the pos- present law, Disadvantages include the need sibility that local individuals would perceive for increased appropriations to fund the vari- the Federal efforts as increased infringement ous elements of the program and expansion of on their lives. Energy development companies the Federal bureaucracy to carry out the would most likely object to additional lease Act’s provisions. Some flexibility may be lost restrictions and to required participation in as uniform standards are applied to all States mitigation programs. Executive agencies wishing to participate in the expanded pro- might find implementation burdensome. gram.

EXPANSION OF FEDERAL PROGRAMS FOR IMPACT MITIGATION Under this option, programs already enacted would be expanded or new ones *S. 1699. —- —.

470 ● An Assessment of Oil Shale Technologies

Chapter 10 References

1For a discussion of current controversies ing Office, 1978). See also Colorado Department about the early inhabitation of the North Ameri- of Agriculture, Agricultural Land Conversion in can continent, see Graham Chedd, “On the Trail Colorado (Denver, Colo.: Resource Analysis Sec- of the First Americans, ” Science 80, vol. 1, No. 3, tion, 1979). March/April 1980, pp. 44-51. For general informa- ‘Bureau of the Census, Congressional District tion, see Handbook of North American Indians Data Book, 93d Cong. (Washington, D. C.: Govern- (Washington, D. C.: The Smithsonian Institution, ment Printing Office, 1973). 1979). ‘) Frank G. Cooley, “The Growing Awareness of 2Angelico Chavez (tr.), Ted J. Warner (cd.), The Oil Shale’s Impact on Communities in Western Dominguez-Escalante Journal: Their Expedition Colorado, ” Rocky Mountain Association of Geolo- Through Colorado, Utah, Arizona and New Mexico gists—1974 Guidebook to the Energy Resources of in 1776 (Provo, Utah: Brigham Young University the Piceance Creek Basin, Colorado, 171-3. Press, 1976). ‘[’Altogether, more than 20 studies were pub- This was Powell’s second expedition to the lished between 1970 and 1977 dealing with one or Rockies. It followed a trail pioneered by Berthoud another aspects of oil shale development. See, in 1861; Jim Bridger served as guide. Powell’s e.g., Oil Shale Regional Planning Commission and wife accompanied the group and was the only the Colorado West Area Council of Governments, woman to spend the winter. Powell made a trip in Profile of Development of an Oil Shale Industry in November, which he nearly didn’t complete, to get Colorado (Rifle, Colo.: CWACOG, 1973), and Col- supplies at Green River City, Wyo, Powell’s Park, orado West Area Council of Governments, Oil a few miles west of Meeker, Colo., was the site of Shale and the Future of a Region: A Summary Re- the “Meeker Massacre” in 1879, Here, a group of port (Rifle, Colo.: CWACOG, 1974). Ute Indians shot and killed Nathan Meeker and 11Alys Novak, “Oil Shale—1976/1977, ” Shale several other workers at the Indian Agency. See Country, vol. 2, No. 12, December 1976, pp. 2-6. Robert Emmitt, The Last War Trail: The Utes and 12Rio Blanco Oil Shale Project, Social and Eco- the Settlement of Colorado (Norman, Okla.: Univ. nomic Impact Statement—Tract C-a (Gulf Oil of Oklahoma Press, 1954) and Marshall Sprague, Corp. - Standard Oil Co. (Indiana), March 1976); Massacre: The Tragedy at White River (Boston, an Addendum was published in May 1977. Mass.: Little, Brown & Co., 1957). ‘ ] C-b Oil Shale Project, Oil Shale Tract C-b 4The Ute Indians signed four treaties with the Socio-Economic Assessment, 2 vols. (Ashland Oil, United States: in 1840, 1863, 1868, and 1880, See Inc. - Shell Oil Co,: March 1976). Gerald T. Hart, Leroy R. Hafen, Anne M. Smith, 14Colony Development Operation, An Environ- and the Indian Claims Commission, Ute Indians II mental Impact Analysis for a Shale Oil Complex at (New York, N. Y.: Garland Publishing, Inc., 1974) Parachute Creek, Colorado (Denver, Colo.: 1974). 15 and George E. Fay, Land Cessions in Utah and Col- Jonijane Paxton, “Whither Now, Battlement orado by the Ute Indians, 1861-1899 (Greeley, Mesa?” Shale Country, vol. 2, No. 6, June 1976, Colo.: Univ. of Northern Colorado, Museum of An- p.15, thropology, Misc. Series No. 13, 1970). See also 16Western Environmental Associates, Inc., Emmitt, Supra No. 3. Baseline Description of Socio-Economic Conditions 5Range wars erupted in the latter part of the in the Uinta Basin and Socio-Economic Impact 19th and early decades of the 20th centuries Study of Oil Shale Development in the Uinta Basin when sheep and cattle raisers fought over the use (Denver, Colo.: White River Oil Shale Corp., 1975). of the rangelands. See James H. Baker and LeRoy 17The five studies are: R. Ha fen (eds.), History of Colorado (Denver, Colo.: a. Department of the Interior, Final Environ- Linderman Press, 1927). mental Statement for the Prototype Oil 6In 1901, Roosevelt spent 5 weeks hunting Shale Leasing Program, 6 vols. (Washing- mountain lion near Meeker; the party killed 14, of ton, D. C.: Government Printing Office, which the largest weighed over 220 lb and was 1973), over 8 ft long. In 1905, he returned for a bear hunt b. Rio Blanco Oil Shale Project, Social and in the area south of New Castle. Economic Impact Statement—Tract C-a 7Bureau of the Census, County and City Data (Gulf Oil Corp. - Standard Oil Co. (Indiana), Book, 1977 (Washington, D, C.: Government Print- March 1976), including 1977 Addendum, Ch. 10–Socioeconomic Aspects ● 471

c. C-b Oil Shale Project, Oil Shale Tract C-b 31U.C.A. 1953, 53-7-1 and 2; 65-1-64 and 65; and Socio-Economic Assessment, 2 vols. (Ash- 65-1-115. land Oil, Inc. - Shell Oil Co., March 1976). 32U.C.A. 1953, 73-10-8 and 73-10-23. d. Department of the Interior, Final Environ- 33W.S. 35-12-101 through 121, mental Impact Statement: Proposed Devel- 34W.S. 9-1-129 through 136. opment of Oil Shale Resources by the Colony 35W.S. 39-6-412. Development Operation in Colorado, 2 vols, 36Personal communication, Dr. James Thompson (Washington, D. C.: Government Printing Of- to OTA, Oct. 16, 1979. An example of an imagina- fice, 1975). tive program is the Wyoming Human Services e. Western Environmental Associates, Inc., Project (WHSP). The WHSP program trained hu- Baseline Description of Socio-Economic Con- man service personnel at the University of Wyo- ditions in the Uinta Basin and Socio-Econom- ming campus and then placed the students in ic Impact Study of Oil Shale Development in Wyoming boomtowns for field experience. After the Uinta Basin (Denver, Colo.: White River completing the program, many students found Oil Shale Corp., 1975). jobs in the communities and stayed to continue 18Rio Blanco County Ordinances, sec. 1003; their service. See Judith A, Davenport and Joseph 1974. Davenport, III, Boom Towns and Human Services 19See Steve H. Murdock and F. Harry Leistritz, (Laramie, Wyo.: Univ. of Wyoming, 1979). Energy Development in the Western United 37Personal communication, Dr. James Thompson States—Impact on Rural Areas (New York, N. Y.: to OTA, Oct. 16, 1979. See also Stan L. Albrecht, Praeger Publishers, 1979). “Socio-Cultural Factors, “ in Mohan K. Wali (cd.), 20It is difficult to place a dollar value on the con- Mining Ecology. tributions of industry, In Wyoming, the Missouri “Department of Energy, Report to the Presi- Basin Power Cooperative (a consortium of REA dent—Energy Impact Assistance (Washington, electric cooperatives) estimates that it spent $21 D. C.: DOE/IR-0009, UC-13; March 1978). million in mitigation efforts in conjunction with 39Supra No. 19. Under Public Law 95-238, DOE the construction of the 1,500-MW Laramie River has awarded grants to Colorado and Utah for so- Station in Platte County. This included in-kind cioeconomic planning. Also, grants have been services; direct grants and revenue guarantees to given to Rio Blanco and Garfield Counties and the towns, counties, and agencies; bond guarantees; the Northern Ute Indian Tribe. and similar assistance. The cooperative believes 40Supra No, 22. it saved approximately $50 million in costs by re- 4190 Stat. 1083 1976), amending 30 U.S.C. sec. ducing employee turnover and by allowing the 201 et seq. (1976). plant to be constructed on schedule. Furthermore, 4290 Stat. 2743 (1976), 43 U.S.C. § 1701-1782 they anticipate recovering all but about $3 million (1976). of the $21 million outlay as the bonds are paid and 43Supra No. 41. other revenues become available. Eventually the 44For a number of reasons, the loan program au- amount spent for mitigation probably will fall be- thorized by FLPMA has yet to be implemented. tween one-half and 1 percent of the total cost of 4592 Stat. 3323 (1978). the plant. (Personal communication from Dr. 46Ibid. James Thompson to OTA, Nov. 5, 1979.) ‘department of Energy, Regional Profile—Ener- 21 CO1. Gen’1 Ass’y, H.B. 1200 (1974, 2d sess.). gy Impacted Communities—Region VIII (Denver, 2241 Stat. 437 (1920), as amended and supple- Colo.: TIC-1OOO1, UC-13; 1979). mented, 30 U. S. C., sec. 181 et seq. (1976), 48Federal Energy Administration, A Report— 23C.R.S. 1973,34-63-104. Regional Profile—Energy Impacted Communities 24C.R.S. 1973, 34-63-104 (l). (Denver, Colo.: Region VIII Socioeconomic Pro- 25C.R.S. 1973.34-63-104 (2). gram Data Collection Office, July 1977) pp. 5-6. 26C.R.S. 1973, 34-63-101 and 102, as amended. 49For a complete discussion of alternatives, see 27C.R.S. 1973, 34-63-102 and 39-29-110. Economic Impact of the Oil Shale Industry in 28C.R.S. 1973, 39-29-101 through 114 (Supp. Western Colorado, hearing before the Subcom- 1977). mittee on Public Lands of the Committee on Interi- 29Personal communication, Stan L. Albrecht to or and Insular Affairs, U.S. Senate, 93d Cong., 2d OTA, Oct. 16, 1979. sess., Jan. 19, 1974; Inland Energy Development 30U.C.A. 1953, 63-51-1 through 4. Impact Assistance Act of 1977 (S. 1493), hearings 472 Ž An Assessment of Oil Shale Technologies before the Subcommittee on Regional and Commu- ‘)] The complete list of developments includes: nity Development of the Committee on Environ- C-a Rio Blanco Oil Shale project (Gulf and ment and Public Works, U.S. Senate, 95th Cong., Standard) 1st sess., August 1977 (ser, No. 95-H28); and Ener- C-b Cathedral Bluffs Shale Oil Co. (Occidental gy Impact Assistance Act of 1978 (S. 1493), hear- and Tenneco) ing before the Subcommittee on Energy, Nuclear Paraho (oil shale) Proliferation, and Federal Services of the Commit- Snowmass/Anschutz (coal) tee on Governmental Affairs, U.S. Senate, 95th Mid-Continent Garfield I/Mid-Cont. Mesa II Cong., 2d sess., Aug. 18, 1978. (coal) 50C.R.S. 1973, 29-1-301 and 302. Superior (oil shale and minerals) 51For an introduction to the boomtown litera- Colowyo (coal) ture, see Charles F. and Jane Archer Cortese, Utah International (coal) “The Social Effects of Energy Boomtowns in the Colorado Ute (powerplant) West: A Partially Annotated Bibliography, ” Coun- Empire (coal) cil of Planning Librarians Exchange Bibliography Moon Lake (coal) No. 1557 (Monticello, Ill. ) June 1978; and P. B. GEX CMC (coal) Allison, “A Bibliography of Bibliographies Con- Sheridan (coal) necting Energy and the Social Sciences, ” Social Energy fuels (coal) Science Energy Review, vol. 1, No. 2 (New Haven, Union Oil (oil shale) Corm.: Yale University Institution for Social and Storm King (coal) Policy Studies), spring 1978,61-70. Colony/Atlantic Richfield and Tosco (oil shale) 52John S. Gilmore and Mary K. Duff, Boom Town Northern Minerals (coal) Growth Management: A Case Study of Rock 62The complete list of documents consulted in- Springs—Green River, Wyoming (Boulder, Colo.: cludes: Westview Press, 1975). 1980 Oil Shale Trust Fund Request 53Ibid., passim. 1979 Oil Shale Trust Fund Request 54Adapted from Ross M. Bolt, Dan Luna, and Housing Plan for Meeker, Colorado, 1979 Lynda A. Watkins, “Boom Town Financing Northwest Supplemental Report—A Supple- Study, ” in Financial Impacts of Energy Develop- ment to the Northwest Colorado Coal Regional En- ment in Colorado—Analysis and Recommenda- vironmental Statement, Colorado tions (Denver, Colo.: DLA, 1977), pp. 11-12. Development Guide for Meeker, Colorado—A 55Study of these changes necessitates the com- Working Draft bination of theory and data from several disci- Development Guide for Rifle, Colorado—A plines: sociology, psychology, anthropology, eco- Working Draft nomics, and political science. Such a combination CWACOG New Housing Unit Needs, 1979 is difficult to accomplish given the differences be- Rifle Needs Assessment tween the disciplines. In addition, applied science Meeker Five Year Capital Improvements Needs of this kind is often viewed with a measure of dis- Grand Valley School District No. 16—Esti- dain by some professionals within each field. mated Needs 1980-1985 ‘()’’ The Social Impacts of Energy Development in Meeker School District RE-1 Projected Needs the West: A Symposium, ” The Social Science Jour- Meeker Regional Library Projected Needs nal, vol. 16, No. 2, April 1979. Pioneer Hospital, Rio Blanco County, Projected “Charles F. Cortese and Bernie Jones, “The So- Needs ciological Analysis of Boom Towns, ” Western So- Five Year Capital Improvements Projection— ciological Review, vol. 8, No. 1, 1977, pp. 76-90. Rio Blanco Criminal Justice 58Ronald L. Little, “Some Social Consequences Rangely District Hospital Projected Needs of Boom Towns, ” North Dakota Law Review, vol. Colorado Northwestern Community College 53, No, 3, 1977, pp. 401-425. Long Range Plan 59William R. Freudenburg, People in the Impact Grand River Hospital District Zone: The Human and Social Consequences of En- Rifle—Water Facility Needs (1980 - 1984) ergy Boomtown Growth in Four Western Colorado Garfield County School District (Projected Communities (unpubl. doctoral dissertation, Yale Needs) Univ., 1979). Silt Projected Needs 60CWACOG, Oil Shale Trust Fund Request (Ri- Roaring Fork School District RE-1—Five Year fle, Colo.: Nov. 1978), p. 6. Needs Assessment/Capital Improvements Plan Ch. 10–Socieconomic Aspects Ž 473

Valley View Hospital Needs Assessment 75Supra No. 68. 63Personal communication, Dan Deppe (city 76Supra Nos. 47 and 48. manager) to Dr. Donald Scrimgeour and Miss 7783 Stat. 852 (1970), as amended by 89 Stat. Ellen Hutt, July 1979. 424 (1975), 42 U.S.C. 4321-4347. 64Donald P. Scrimgeour and Marilyn Cross, De- 78Ibid. velopment Patterns and Social Impacts: A Focus 79See, for example, Calvert Cliffs Coordinating on the Oil Shale Region (Denver, Colo,: Quality De- Committee, Inc. v. U.S. Atomic Energy Commission, velopment Associates, July 1979). 449 F.2d 1109 (D.C. Cir. 1971), cert. denied, 404 65Discussion with Mr. Floyd McDaniel, Chair- U.S. 942. man, Planning Commission, Grand Valley, August 8090 Stat. 1013 (1976), 16 U.S.C. 1451-1464. 1979. 8186 Stat. 1280 (1972), 16 U.S.C. 1451-1464. 66Personal communication, Peter Kernkamp 82Supra No. 38. (town planner) to Dr. Donald Scrimgeour and Miss 83Ibid., pp. 59-81. Ellen Hutt, July 1979. 84Rocky Mountain Energy Resource Develop- 67Personal communication, Bob Young (town ment: Status, Potential, and Socioeconomic Issues manager) to Dr. Donald Scrimgeour and Miss (Washington, D, C.: GAO, July 1977), EMD-77-23. Ellen Hutt, July 1979. 85Ibid., pp. 5-7. 68Department of the Interior, Draft Environmen- 86Supra No. 45. 87 tal Statement: Proposed Superior Oil Company Energy Impact Assistance: A Background Re- Land Exchange and Oil Shale Resource Develop- port, printed at the request of the Committee on ment (Denver, Colo.: BLM, August 1979) pp. 77-90. Energy and Natural Resources, U.S. Senate, 96th 69Supra No. 50. Cong., 1st sess., October 1979 (publ. No. 96-34) 70Supra No. 67. (committee print). 71Supra No. 64. 88For a spirited elucidation of this position, see 72Supra No. 67. Raymond L. Gold, “On Local Control of Western 73Personal communication, Mr. William Bren- Energy Development, ” The Social Science Journal, nan to OTA, January 1980. vol. 16, No. 2, April 1979, pp. 121-127. 74Ibid, 89Supra No. 45. Appendixes APPENDIX A Description and Evaluation of the Simulation Model

To evaluate quantitatively the alternative in- time. Alternatively, the user can input all real val- centives, a computerized model was used, devel- ues (as OTA did) which implicitly indexes the oped by Tyner and Kalter1 that captures the prob- floor price. However, this solution causes some abilistic attributes of the oil shale development distortion in the tax calculations. With inflation, process through Monte Carlo simulation tech- income increases in nominal value, but the niques. The core of the model is a discounted cash amount of depreciation deducted for tax purposes flow algorithm computing the after tax profit. remains constant. Thus, in real terms, the value of In computing aftertax profit, the model uses a depreciation decreases with inflation. However, conventional discounted cash flow algorithm in since the model does not account for this real de- which the net cash flow for each year (i. e., reve- crease when the user inputs all real values, the nues less costs and taxes) is discounted to the be- model underestimates the amount of tax pay- ginning of the project. These discounted cash ments. This distortion was not considered serious, flows are then summed to arrive at the aftertax given the short depreciation period and the higher net profit. fraction of depreciation claimed in early periods. With the model, the user can input probability Second, the model has a limited capability with distributions of prices and costs instead of single respect to purchase agreements. To model a pur- value estimates. The model then constructs a chase agreement for the entire production, the probability distribution for aftertax profits using user can input the purchase price in place of the the Monte Carlo method. With this method, the market price for oil. However, the model cannot model makes repeated runs in which profit is cal- directly handle purchase agreements for only a culated. In each run the model randomly selects portion of the output in a given year. To evaluate values from the input distributions. The resulting a partial purchase agreement, the user must per- profit calculations are then cumulated into prob- form offline calculations to obtain an average of ability y distributions characterized by an expected the market and purchase agreement prices, value and standard deviation, The expected value weighted by the proportion of output sold for each gives the average profit for all the Monte Carlo price, A similar calculation must then be per- runs and the standard deviation provides a meas- formed for the standard deviation of the price ure of dispersion or variation about this average distribution. value. The model also totals the number of Monte Third, the model has no capability to simulate Carlo runs that results in positive profits and the effects of production tax credits. It does allow plots a histogram of the frequency distribution of for a price subsidy, but this subsidy is not a tax the profit outcomes, From this output the user can credit. Unlike a tax credit, the subsidy increases compute the probability that a loss will be in- taxable income and hence income tax payments. curred. Because of this limitation, the model was not used Although the model was designed to test the ef- to perform the necessary calculations for the fects of alternative mineral leasing systems on $3/bbl tax credit. To estimate the increase in ex- profits and Government revenues, it incorporates pected profit, the per barrel tax credit was multi- several financial incentives, including construc- plied by each year’s production. The total annual tion grants, price supports, purchase agreements, credits were than discounted to the present and investment tax credits, depletion allowances, and summed. The same procedure was used to calcu- variable depreciation schedules. Indeed, its au- late the expected cost to the Government, except thors used an earlier version to evaluate the ef- that the Government discount rate was used in fects of some of these incentives on the profitabili- the calculation. To evaluate the effect on risk, it ty and risk of oil shale development. ’ was assumed that the standard deviation would However, because the model was not designed not change as a result of the tax credit. This specifically to test incentives, it has several lim- assumption follows because the tax credit does itations. First, it does not provide for inflation in- not alter costs or prices; these alterations deter- dexing of the floor price under a price support mine the standard deviation. Because the stand- program. Thus, if the user inputs nominal (i.e., ard deviation is the same for the tax credit as it is gross of inflation) values into the model, the real with no incentive, it was possible to transform the (i.e., net of inflation) floor price will decline over histogram computed for the no-incentive case into

477 478 ● An Assessment of Oil Shale Technologies a histogram for the production tax credit case. Table A-1 .–Calculating Change in Expected Profit and Cost to With this new histogram an estimate could be the Government for a Low-Interest Loan made of the percentage of cases falling below the zero profit level. Finally, the breakeven price was Assumptions ● The average total construction cost is $1.7 billion calculated by subtracting the production tax • 70 percent of one-fifth of the total construction cost, $238 million, is credit from the breakeven price with no incentive. loaned at the end of each of the 5 years of construction Fourth, the model is not able to simulate the ef- Ž Interest IS calculated on the principal from the moment the first loan is fect of low-interest loans. Although the user could made ● The loan principal plus interest is amortized over 20 years adjust the discount rate downward to account for ● The interest rate is 3 percent in real terms the low-interest loan, this method has several limi- ● The firm market borrowing rate is 6 percent in real terms tations because it fails to account for all the terms ● The Government’s discount rate is 10 percent in real terms of the loan. In particular, this method is not sen- Calculations sitive to the time when the loan is received and Result the time when it must be repaid. Moreover, the Step ($ million) 1. Calculate annual loan amounts (1 ,700x .7x 2), ., ‘ 238/yr ‘ approach is based on very restrictive and unreal- 2 Calculate the future value in year 5 of five payments of istic assumptions about the structure of debt fi- $238.00 (3-percent Interest) . . 1,264 nancing for the project.3 3. Calculate the annual principal and Interest payment to the Accordingly, the model was not used to perform Government (years 6-25) based on the future value in the calculations for the low-interest loan. The step 2 (3-percent Interest) 85/yr 4. Calculate the present value to the firm year 5 of the steps for the low-interest loan computations are payment from step 3 (6-percent Interest) 974 referenced in table A-1, The actual cash flows 5. Calculate the present value to the firm in year O of the (both loan payments and repayments) to the firm value from step 4 (6-percent Interest), 726 were set up based on the Government’s lending 6. Calculate the present value to the firm in year O of the annual loan amount from step 1 (6-percent Interest). 1,003 rate and the structure of the loan. These cash 7. Calculate the change in profit for the firm (1 ,003-726) 277 flows were then discounted using the borrowing 8. Calculate the present value to the Government in year 5 of rate for the firm on the open market (assumed to the payment from step 3 (l O-percent interest) ., 723 be 3-percentage points higher than the Govern- 9. Calculate the present value to the Government in year O of ment lending rate), A similar calculation was per- the value from step 8 (l O-percent Interest) 448 10, Calculate the present value to the Government in” year O of formed to estimate the expected cost to the Gov- the annual loan amounts from step 1 ( 10-percent ernment. As with the production tax credit, it was interest) 401 assumed that the standard deviation of the distri- 11. Calculate the net cost the Government (901-448) 453 bution of profits would not change, since the loan SOURCE :Office of Technology Assessment does not alter any of the costs or prices in the model. With the estimated mean for the profit distribution and the standard deviation, the histo- by the model. This is so because, except for small gram of profit distribution from the no-incentive tax payments to State governments, all the mone- run was subsequently used to estimate the prob- tary exchanges occur between the Federal Gov- ability of a loss. The price increment was then ernment and the firm. If the discount rates are the computed, which, when multiplied by the produc- same, the present value of the exchanges to both tion for each year, yielded a discounted value entities is the same, Therefore, since a lo-percent equal to the estimated increase in expected prof- Government discount rate has been assumed, the its. The price increment was then subtracted from net cost to the Government of each incentive is the breakeven price with no incentive to yield the equal to the net gain in profitability to the firm breakeven price under the low-interest loan pro- calculated at a lo-percent discount rate. The only gram. exception occurs with the Government loan. Be- Finally, the model does not directly calculate cause it has been assumed that the real interest the net cost to the Government. However, if the rate on debt financing for firms is less than 10 Government and the firm use the same discount percent, the present value to the firm of the low- rate, the cost to the Government exactly equals interest loan is less than its cost to the Govern- the gain in expected profit to the firm calculated ment. Appendix A–Description and Evaluation of the Simulation Model Ž 479

Appendix A References

1Wallace E. Tyner and Robert J. Kalter, “A Simula- Foundation, April 1975. tion Model for Resource Policy Evaluation, ” Cornell Ag- 3tewart C. Meyers, “Interactions of Corporate Fi- ricultural Economic Stuff Paper, September 1977. nancing and Investment Decisions—Implications for 2Wallace E. Tyner and Robert J. Kalter, An Analysis Capital Budgeting, ” in Modern Developments in Finan- of Federal Leasing Policy for Oil Shale Lands, prepared cial Management, Hinsdale, Ill.: Dryden Press, 1976. for the Office of Energy R&D Policy, National Science APPENDIX B Assumptions and Data for Computer Analyses

Most of the assumptions used in the computer simulation analyses are embodied in the input data displayed in table B-1. All cost and price data in the exhibit are in constant 1979 dollars.

Table B-1 .–Data Used for Quantitative Analysisa

Data item Value used Explanation costs Capital cost distribution Maximum capital cost, $2.0 billion The capital cost data apply to all the capital equipment needed to mine and retort shale and hydro- Most probable capital cost: $1.7 billion treat the raw shale oil product, the costs do not Include land acquisition or interest charges, Data Minimum capital cost $1.4 billion were based on recent industry cost estimates, Operating and maintenance (O&M) cost distribution. Maximum O&M cost. $17/bbl Operating costs include hydrotreating costs. Data were based on recent industry cost estimates Most probable O&M cost : $12/bbl Minimum O&M cost $ 9/bbl Operating cost Increase 4 percent/year Operating costs were assumed to increase 4 percent per year in real terms (I e., net of inflation) to account for probable Increases in labor costs due to expansion of shale Industries in sparsely populated areas Assumption was based on expectations expressed to OTA by industry sources Construction period 6 years A 6-year construction period (i. e , a l-year delay between the fourth and fifth years) decreased expected profits by $117 million for the no-incentive, 12-percent discount rate case. Fraction of costs occurring each year during construction Year 1 ., 10 Year 2 25 Year 3 ., : : : : : 30 Year 4 ., 25 Year 5 00 Year 6 ., 10 Prices Initial oil price (1979) ., ., $35/bbl Based on the price of imported oil, which at the time of the analysis ranged from $33 to $37/bbl. Mean annual 011 price increase 3 percent The assumed 3-percent real increase in oil prices accounts for increasing scarcity as cheap domestic supplies are exhausted, and is midway in the range (2-4 percent) used by DOE planners Standard deviation of annual oil price change distribution 3 percent Based on historical trends from the American Petroleum Institute, Basic Petroleum Data Book, 1976. Taxes and transfers Federal corporate tax, ., 46 percent Current Federal corporate income tax rate, State corporate tax 3 percent Colorado corporate income tax rate. State severance tax ., 4 percent Colorado severance tax on 011 shale reserves, Investment tax credit, 10 percent Investment tax credit of 10 percent applies to all investments, an existing additional 10-percent credit for energy-related Investments was ignored because it is to expire in 1982, Depletion allowance 15 percent Depletion allowance computed on 011 shale revenues and deducted from taxable income. Royalty ., 1 percent Current royalty is 12.5 cents per ton of mined shale; this is equivalent to a royalty on 011 revenues of less than 1 percent. Depreciation Iifetime 12 years Based on discussions with industry sources. Annual rent ., $2,600 Based on a 50-cent-per-acre rent on Federal shale leases of 5,200 acres, Depreciation method Sum-of -years Provides the most rapid tax writeoff, digits with switch- over to straight Iine Production Maximum output of facility ., 50,000 bbl/d Size of typical commercial facility, Production lifetime ., ., ., 22 years Based on production lifetime of 20 to 30 years in industry cost estimates. Annual output Year 1 15,000 bbl/d 2-year buildup accounts for probable startup difficulties. Year 2 ..., : ...... 35,000 bbl/d Years 3 to 22, ., ., ., 50,000 bbl/d a All monetary values in constant 1979 dollars SOURCE :Office of Technology Assessment

480 APPENDIX C Oil Shale Water Pollutants

Introduction

The types and amounts of water contaminants that are likely to be produced by major kinds of oil shale facilities are discussed here,

Water Pollutants Produced by Major Oil Shale Processes

Types and Origins of Pollutants ● Dissolved inorganic will be found in mine drainage water and retort condensates be- The following summarizes the major sources of cause these streams leach sodium, potassi- each class of waterborne contaminants found in um, sulfate, bicarbonate, chloride, calcium, and magnesium ions from the shale that they oil shale facilities. 3 ● Suspended solids will occur primarily in contact. In addition, some inorganic vola- water from the dust-control systems used in tilize and may be captured from the gas shale mining and crushing operations. Mine phase in the retort, Of the heavy metals pres- drainage water will also contain suspended ent in raw oil shale, cadmium and mercury solids, as will a retort condensate stream (probably as their respective sulfides) are ex- that picks up fine shale particles as it pected to be present in the gas condensate in trickles down through the broken shale. In low concentrations.’ An analysis of TOSCO II aboveground retorts, some fine shale may be gas condensate water showed the presence entrained in the retort gas and captured in of cyanide, sodium, calcium, magnesium, silica, and iron ions, with only trace amounts of the gas condensate, but levels should be low, 5 thus should not be a problem to treat, Cooling some of the heavy metal elements. water will pick up dust from the atmosphere, ● Dissolved organics arise largely from the or- particularly if the cooling tower is near a ganic compounds in the raw oil shale, which shale crushing or disposal site. Precipitated may be altered during pyrolysis and end up salts and biological matter may also be pres- in the retort, gas, or hydrotreater conden- ent in the cooling tower blowdown. sates. The types of organics in each conden- ● Oil and grease will be present in the retort sate will probably depend on the volatility condensate water that is removed from the and volubility of the organics and the tem- in situ retort together with the product oil. perature at which the wastewater is con- Some oil remains in the water after product densed. No data are available on this subject recovery and must be removed prior to fur- but it is known that a wide range of com- ther treatment. Part of the oil forms an emul- pounds, particularly carboxylic acids and sion in the water and its removal may be dif- neutral compounds, can be expected.6 Many ficult. 1 Volatile hydrocarbons leave with the of the individual compounds should be biode- retort offgas and condense in the gas conden- gradable, but studies have shown that less sate water. Tests indicate that the oil in the than 50 percent of the organic matter can be gas condensate occurs in well-defined drop- removed by conventional biological oxida- lets that can be separated without difficulty.2 tion. This poor performance is attributed to Oils in the coker and hydrotreater conden- the effect of toxic compounds on waste-treat- sates are expected to be similar to those in ment bacteria. Both inorganic and organic the gas condensate. toxic substances may be responsible. The ● Dissolved gases include all of the NH3 and specific types of toxic pollutants will differ

some of the CO2 and H2S formed in the retort- with the retorting process and with raw ing process. These gases dissolve in the re- shale composition. 789 ● tort and gas condensates. Any NH3 and H2S Trace elements and metals are not expected that are formed during upgrading will ap- to occur in large concentrations in the major pear in the hydrotreater condensates. waste streams except those streams dis-

481 482 ● An Assessment of Oil Shale Technologies

cussed under dissolved inorganics.10 11 stances, have been reported for various Chromium was used for corrosion control in types of oil shale processing wastes. Any tox- older cooling-water systems but other agents ic substances present in the wastewater are now available and should be used to streams will be removed along with the trace avoid the problem of chromium contamina- organics or inorganic substances. It is not ex- tion of blowdown streams. If trace element pected that thermal oxidation, which is often and metal removal is required, chemical employed to destroy hazardous organic com- treatment, specific ion exchange, and mem- pounds, will be required for the wastewater brane processes are available. streams, although it may be considered for Trace organics are toxic or hazardous or- concentrates or sludges. However, the pres- ganic compounds present in low concentra- ence of toxic substances may interfere with tions. They may occur in the retort and gas biological oxidation processes used for bulk condensate streams and in the wastewater organic removal. If this is a problem, the stream from the upgrading section. These substances could be removed in any of sever- constituents can generally be removed to- al conventional pretreatment steps. gether with other dissolved organics by ultrafiltration with carbon adsorption for final ● Sanitary wastes in “domestic” and service cleaning (“polishing”). waste streams can be kept separate and Toxics, including carcinogens, mutagens, treated in commercially available package priority pollutants, and other hazardous-sub- biological treatment units.

The Amounts of Pollutants Produced

Table C-1 indicates he principal contaminated MIS process. It is similar to the design proposed process streams and their flow rates for four by Occidental and Tenneco for tract C-b. The commercial-scale [50,000 bbl/d)* oil shale facil- “MIS/aboveground” plant combines Occidental’s ities. These facilities correspond to the plants for MIS process-with Lurgi-Ruhrgas indirectly heated which water requirements are estimated in chap- aboveground retorts. It is similar to Rio Blanco’s ter 9. The “aboveground direct” plant uses di- design for tract C-a. rectly heated aboveground retorts like the Paraho The flow rate estimates were derived from direct or gas combustion. The “aboveground in- tables 71, 74, and 75. (See ch. 9.) Estimates have direct” uses indirectly heated retorts like TOSCO been added for the internally recycled gas wash- II. It is similar to the design proposed by Colony ing and hydrotreater wash streams that were not Development. The “MIS” plant uses Occidental’s considered in chapter 9. (The water availability

*Barrels per stream day.

Table C-1 .–Flow Rates of Contaminated Streams in Oil Shale Facilities Producing 50,000 bbl/d of Shale Oil Syncrude (acre-ft/yr)

Aboveground Aboveground direct redirect MIS MIS/aboveground Cooling tower blowdown 1,550-1,820 1,320-2,070 1,040-1,280 910-1,130 Boiler blowdown ... 325 370-405 370 350 Boiler feedwater treatment wastes 165 190-210 185 180 Gas washing condensate ., 1,070-1,190 (a) 3,320-3,640 2,270-2,500 Gas condensate (net). . 490-540 730-800 2,160-2,370 1,480-1,630 Retort condensate, . . . . (a) (a) 1,240-1,370 850-940 Coker condensate. ., 60 60 60 60 Hydrotreater wash condensate 875 875 875 875 Net hydrotreater condensate 40 40 Excess mine drainage (a) (a) 0-10,000 0-10,000

a)@glecfed for processes designs or sites considered SOURCE R F Probstem H Gold and R E Hicks, Wafer Reqwernenfs Po//ufIorI Mecfs and Cos/s of Waler Supply arrd Treafrnerd for (he 0(/ Sfra/e /n- dus(ry. prepared for OTA by Water Purlflcahon Associates October 1979 Appendix C–Oil Shale Water Pollutants ● 483 analysis presented there deals only with streams value is shown for the MIS retort condensate that cross the project boundaries.) These addi- because of unavoidable condensation in the tional streams are of significance for water quali- lower portions of the MIS retorts. The value ty analysis because they contain all of the NH3, for MIS/aboveground is a weighted average most of the CO2, and some of the H2S that is re- of Lurgi-Ruhrgas (no condensate) and MIS moved from gas streams in the plants. Flow rate (large quantities of condensate). ranges are shown in some cases to account for the ● Large values are also shown for gas conden- expected variations in shale grades and plant de- sate and gas washing condensate in all sys- signs, as discussed in chapter 9. The following tems except the aboveground indirect. In the points should be noted with respect to the flow aboveground direct and the two MIS oper- rate estimates. ations, large quantities of moist retort gas ● Cooling tower blowdown varies substantially must be treated, resulting in large volumes of among the plants, largely because of differ- condensate. Much of the moisture is a com- ent modes of power generation. bustion product. In contrast, the above- ● Boiler blowdowns are fairly uniform because -ground indirect has no combustion within the it is assumed that boilers will generate steam retort and produces less gas that must be for use in the upgrading units, which are cooled and cleaned. identical for all four plants. In table C-2, estimates are presented of the con- ● For the same reason, all four plants have the centrations of contaminants in the condensate same flow rates for coker condensate, hydro- streams. It is important to note that extensive treater wash condensate, and net hydro- data on contaminant concentrations are not avail- treater condensate. able for the process condensate streams and that ● Excess mine drainage is indicated for the published measurements show considerable vari- MIS and MIS/aboveground plants because it ation. Only the estimate for the aboveground in- was assumed that they would be located in direct gas condensate is based on extensive field the ground water areas of the Piceance ba- measurements.13 The other values are consistent sin. The other two plants were assumed to be with material balance calculations and informa- located in drier areas (e.g., in the Uinta basin tion from the literature but they are at best ap- or along the edge of the Piceance basin), proximate. Moreover, only concentrations of ma- ● No retort condensate is shown for the AGR jor contaminants are shown. Trace contaminants, plants because it was assumed that conden- including most toxic elements, are not indicated sation in the retort would be avoided by ad- because information on their occurrence is even justing the operating temperature. A large more limited, Although toxic elements are not ex-

Table C-2.–Contaminant Concentrations in Oil Shale Process Condensate Streams (mg/1)a

Gas condensate Retort condensate Hydrotreater condensate Contaminant Aboveground direct Aboveground redirect MIS or MIS/aboveground MIS or MIS/aboveground All plants NH3 17,990C 5,150 21 ,330C 720 41 ,000c c C — C H 2 S 206 810 118 18,000 b C C CO2 32,400 6,150 41 ,800 9,940 None Calcium : Lowd 6 Low 20 Low Magnesium. Low 2 Low 17 Low Potassium Low 04 Low 100 Low Sodium Low 5 Low 3,600 Low Chloride Low 5 Low 280 Low Fluoride Low 0.3 Low 39 Low Boron, Low Low Low 25 Low Sulfate Low Low Low 1,200 Low Organic carbon — 6,100 — — — BOD e ., 10,000 10,000 2,200 2,220 10,000 alrace elements and organlcs for which data are unavailable are flOl shown bBlcarbonafe and carbonate concentrations reporled as CO, e(lulvalenf cln Internal acid wash before gas separation and wash recYcle dBa5ed on avadable dala or estlmales eBlochemlcal oxygen demand estimated al one half of the fheorellcal oXY9en demand SOURCE R F Probstem H Gold and R E Hicks Wafer l?equ~rerneflfs, Po//ufIorI Ef/ecK and Cos/s of Waler Supp/y and Treafrnefll for rhe 0// Shale /ndustry prepared tor OTA by Waler Punflcaf!on Associates October 1979 484 ● An Assessment of Oil Shale Technologies

Table C-4.–Production Rates for Principal Pollutants pected to be present to any significant extent in a the gas condensates, some could be present in the From MIS Retort Condensates (ton/d) MIS retort condensate. ” Type of facility The hydrotreater condensate concentrations MIS MIS/aboveground were developed for Colony’s upgrading unit, but Contaminant NH ., 349 2.40 they should be typical of values for any facility 3 — — H 2 S (MIS or aboveground) that processes Green River co, : : 48,2 33.1 shale oil. A retort condensate is shown only for Calcium 0.10 0.07 the MIS and MIS/aboveground facilities, for rea- Magnesium. . 008 0.06 sons mentioned previously. Significant differ- Potassium. . 0.49 0.33 Sodium 17.5 12.0 ences are indicated for the three gas condensate Chloride 1,36 0.93 streams with respect to NH3, H2S, and CO2 concen- Fluoride 0.19 013 trations. The aboveground indirect stream is Boron. : . 0.12 0.08 much lower in CO and NH because of the lack of Sulfate . 5,82 3.99 2 3 Biochemical oxygen demand ., 10.07 7.32 combustion (which produces soluble CO2 and NOx day for production of 50000 bbl/d shale o!! syncrude gases) in the retort. H2S concentration is higher in aTOn~ per stream the aboveground indirect stream because there is SOURCE R F Probstem H Gold, and R E Hicks Wafe/ Requ(rernerrts Po//ul(on E//ec(s and Cosls o/ Waler Supp/y arrd Trealmen/ for /tre 0// Sha/e /rrdus/ry prepared for OTA by little oxygen available in the retort to oxidize the Water Purlflcahon Assoclales October 1979

H 2S to SO2 A lack of data prevents evaluation of process-related effects on concentrations of other in MIS retorting. It is assumed that retort conden- contaminants. sates are produced only with MIS processing. In table C-3, the likely rates of pollutant produc- These condensates leach inorganic salts from tion are shown for the gas condensate streams. shale in the retort, as indicated by the contaminant production rates shown. Table C-3.–Production Rates for Principal Pollutants Table C-5 shows the production rates for the a in Gas Condensate Streams (ton/d) principal contaminants in the process waste waters generated in the upgrading portion of the Type of facility Colony design. This is the only plant for which an Aboveground Aboveground MIS/ Contaminant direct Indirect MIS aboveground upgrading section has been described in the literature. Since shale oils produced by different NH, 75.6 147 276 189 b retorts are not markedly different in their nitro- H 2 S 0.87 2.3 15 1.1 co, 136 17,5 541 371 gen and sulfur contents, it is reasonable to apply BOD C ., : : 19.2 28.5 185 127 the pollutant production estimates for the TOSCO aTons per stream day for production of 50000 bbl/d shale oll syncrude H upgrading section to all of the facilities con- bAddltlonal SUIIIJr IS recovered dlreclly from the retofl 9as sidered. cBlochemlcal oxygen demand In table C-6, the pollutant production rates for SOURCE R F Probsteln H Gold and R E Hicks Waler I?equlrenrerrfs, Po//utIon Ef/ec/s and COSIS of Waler Supp/y and Trea/nrenl for Ihe 0// Stra/e /rrdustry prepared for OTA Dy all of the process condensate streams are com- Waler Purlflcatton Assoclales October 1979 bined. It can be seen that the biochemical oxygen demand (BOD) does not have a wide range be- The values shown were obtained by multiplying tween facilities. This is in large measure a result the flow rates in table C-1 by the pollutant concentrations in table C-Z. Only a single value is shown for each contaminant in table C-3 and in the other Table C-5.–Production Rates for Principal Pollutants a pollutant production-rate tables that follow. The in Upgrading Condensates (ton/d) rates shown were calculated for average stream Waste stream flows wherever a range is shown in table C-1. This approximation is justified because the uncertain- Contaminant Hydrotreater condensate Coker condensate

NH 3 ., . . ., 133 1.15 ty in pollutant concentrations is larger than the b H 2 S ., . . . . 58.6 0,18 relatively narrow range shown for the flow rates. co2 o 1.37 These uncertainties result from a paucity of pub- Biochemical oxygen demand 1.49 2.23 lished data, and also because large differences aTons per stream day for production of 50,000 bbl/d shale 011 syncrude Based on a TOSCO II can occur in some plants with different feed process design Similar values anticipated for the other process models waters and process designs. bAddltlonal sulfur IS recovered dwecfly from fhe refofl 9as Table C-4 indicates the pollutant production SOURCE R F Probsfeln, H Gold, and R E Hicks Wale{ Requwemerrfs Po//u(ion Effects, and Costs of Waler Supp/y and Treaonen( for (he 0// Sha/e /rrduslry, prepared for OTA by rates for the retort condensate streams produced Water Purlficatlon Assoclales, October 1979 Append/x C–Oil Shale Water Pollutants ● 485

Table C-6. –Sum of the Production Rates for Principal Pollutants manufactured in the upgrading section when ni- a in Retorting and Upgrading Condensates (ton/d) trogen is removed from the crude shale oil by hydrotreating. Differences in BOD yields are not sta- Type of facility —— tistically significant, given the lack of precision in Above-ground Aboveground MIS/ Contaminant direct indirect MIS aboveground the data base. - In order to calculate pollutant concentrations NH, 210 149 414 326 H@ 597 61 1 603 599 in cooling tower blowdown and waste streams Co, c 137 189 591 405 from boiler feedwater treatment, it is necessary BODd 229 322 329 237 to know the raw water composition to the plant. Table C-7 shows the raw water compositions alons per stream day for procfucl Ion of 50 000 bDl d shalemi Syncrude bAddiflond. sulfur IS recoverec dlrecf y frOm the retofl 9as assumed for this assessment. The surface water Clhls does not represen[ iota I CO, p-oducflon CO, IS also generated In combustion and Iosl up flue gds stacks as n TOSCO II tnd~recl process dnd In steam and power production quality is that of the Colorado River near Cameo, dBloc~emlcal oxyqen demand Colo., and the mine drainage water is a composite SOURCE R F Probslelr H Gold and R E Hicks Wafer Requremeols PoIlufIon Ef(ech and of the expected quality of water to be drawn from Cosls of Wafer 5WPIJ am Tredlme[)( for !ne 011 .SOde Iodu.slrp prepared ‘or OTA t)y 15 Waler Purll[cahon Assocla!es Oc!ober 1979 the bedrock aquifers of the Piceance Basin. * The raw water compositions are only approximate. of the BOD concentrations assumed. The H2S pro- Table C-8 presents the estimated composition duction, which represents about a third of the of the cooling tower blowdown of four facilities total sulfur recovered in the plant, varies little among the different facilities. This is reasonable, since the amount of sulfur removed per unit of shale oil produced should be similar for the different processes. However, this H2S includes only Table C-7.–Composite Water Quality Data for Colorado River that amount that dissolves in the condensate Water and Mine Drainage Water in the Piceance Basin (mg/l) streams; it does not include the gas that goes directly to the sulfur recovery units. Source of process water The most striking estimate in table C-6 is the ex- Contaminant Surface water Mine drainage water NH — 1.2 tremely high CO2 production rate for the MIS fa- 3 cility. The rate for the aboveground indirect facil- ‘Bicarbonate 168 750 Boron — 3 ity is lowest because decomposition of carbonate Calcium 72 50 minerals to CO2 is much less at the lower retorting Carbonate — 50 0 0 temperatures (about 900 F or 500 C) than in the Chloride 205 20 0 — higher temperature (about 1,500 F or 800° C) Fluoride 15 Magnesium 19 60 MIS or aboveground direct processes. The rate is -3 Phenol — 25 x 10 highest for MIS because the shale remains at high Silica 7 15 temperatures for a long time, thus allowing nearly Sodium 153 300 complete decomposition of the carbonates. The Sulfate 158 350 combined MIS and AGR facility shows a corres- Total dissolved solids 734 1,350 pondingly lower value—a weighted average of SOURCE R F ProDstem H Gold and R E HICKS Water Requ/rewmff Po IIUW? t ‘fecf~ ,MO MIS and Lurgi-Ruhrgas rates. It should be empha- Cosls O( Warer SJpLW and Trealmenf (or /he 011 Shd e Iflctisfr) preparecl for OTA OY Water Punflca:(on Assoctales October 1979 sized that CO2 is also produced by combustion in the indirect AGR plant, which does not show up in the condensate streams because it is lost directly Table C-8.–Estimated Concentrations of Principal Contaminants in Cooling Tower Blowdown (mg/l) up flue gas stacks, However, even if this gas were included, the ratio of CO2 produced in MIS or Type of facility aboveground direct to that in indirectly heated AGR with MIS retorting with mine retorting would still be large. Contaminant surface water supply drainage water supply

Differences in NH3 production rates also result Calcium, 215 200 from combustion in MIS and directly heated Chloride 615 80 aboveground retorts. The aboveground indirect Fluoride — 60 process produces the least NH because it is Magnesium 60 240 3 Sodium 460 1,200 essentially one of pyrolysis in which the nitrogen Sulfate 840 1,400 is mostly obtained from the organic matter in the shale. In fact, almost all of the NH that will be SOURCE R F Probstein, H. Gold and R E Hicks Waler Reqwrernenrs Po//uflon E(/ecrs and 3 Cosls O( Wa[ef Supp)y and TreaVneflf for rhe 01/ Sha/e /ndus(fy prepared for OTA by produced in the indirectly heated AGR will be Wafer Purlhcahon Assoclales Ocfober 1979 486 ● An Assessment of Oil Shale Technologies considered, based on an average of three cycles water by ion exchange to obtain a high-quality of concentration for AGR (surface water supply) water for boiler feed. The estimates assume the and four cycles of concentration for MIS retorting removal of all the calcium, magnesium, and sul- (mine drainage water supply). The relatively low fate ions from the supply water. Most of the other numbers assumed for concentration cycles are ions will also be removed but only the principal based on the assumption that all of the blowdown ones are shown for the waste streams. The waste water is needed for solid waste disposal. Under volume is about 7.5 percent of the water treated. this assumption there is no advantage to the more This corresponds to a fairly efficient ion ex- costly procedure of using a larger number of change treatment system. Boiler blowdown waste cycles. composition is not shown because the quality of Table C-9 gives the estimated composition of this water is usually equivalent to that of the raw the waste streams from treating the raw supply water entering the plant. It can therefore be mixed with the raw water and used as a makeup source. Table C-9.–Estimated Concentrations of the Principal Table C-10 gives the estimated pollutant pro- Contaminants in an Ion Exchange Regenerant Waste Stream duction rates in the cooling tower blowdown and From Boiler Feedwater Treatment’ (mg/l) boiler waste treatment streams based on the compositions of tables C-8 and C-9. Also shown are the Type of facility total production rates from these two sources; the AGR with MIS retorting with mine Contaminant surface water supply drainage water supply streams would usually be combined in the plant and used for solid waste disposal. There is not a Calcium 950 660 Chloride : 2,400 790 great deal of difference in the total quantities of Magnesium 250 4,600 pollutants produced by the facilities considered, Sodium ., 990 2,200 In table C-1 it was assumed that oil shale mines Sulfate 2,080 3,460 in ground water areas might result in production avo]ume 01 regenerant wastewater assumed to be approximately 75 Percent ot the volume of of from O to 10,000 acre-ft/yr of excess mine treated water drainage water for a 50,000-bbl/d in situ facility. SOURCE R F Probsteln H Gold and R E Htcks Wa/er Ileqwrernen(s Po//u/IorI E/(ec/s am-l At this time, it is not known whether the water COSM of Waler Supply and TrealmerU for (he 0(/ S/ra/e /frdus/(y prepared Ior OTA by Waler Purlflca[ton Associates October 1979 will be treated for discharge to surface streams,

Table C-10.–Production Rates for Principal Pollutants in Cooling Tower Blowdown and Boiler Treatment Wastes (ton/d)

Contaminant Aboveground direct Aboveground indirect MIS MIS/aboveground Cooling tower blowdown Calcium. 1 35 1,36 0.86 076 Chloride 385 3.88 035 0.30 Fluoride . . . — — 0.26 023 Magnesium 038 0.38 1.04 0,91 Sodium. 2.88 290 5.18 4,55 Sulfate 5.26 529 604 5.31

Boiler treatment wastes Calcium . 0,58 0.71 0.45 0.44 Chloride 1,47 1 79 0.54 0,53 Magnesium 015 0.19 3.16 3.08 Sodium. 061 0.74 1,51 1.47 Sulfate 1 28 1.55 2.38 2,32

Total Calcium. 193 2.06 1.32 1.20 Chloride 533 5,66 089 083 Fluoride — — 0.26 0.23 Magnesium 0,53 056 4.20 3.99 Sodium : 349 3.64 6.69 6.02 Sulfate 654 6.84 8.42 7,63 Total. 17.82 1876 21.78 19,90

SOURCE R F Probstein H Gold and R E Hicks, Waler r7e9u/remerr/s Po//u/lon Effec/s and Cos/s of Waler Supp/y and Trea/merrl /or (he Od Sha/e /ndusVy prepared for OTA by Water Purlflcatlon Associates Oclober 1979 Append/x C–Oil Shale Water Pollutants ● 487 or reinfected into the aquifer from which it was Table C-1 1.–Rates of Pollutant Production From Treatment drawn. The question has economic as well as en- of 10,000 acre-ft/yr of Excess Mine Drainage Water vironmental implications. If it is to be discharged, for Surface Discharge then it must be treated, and wastewater streams Regulatory scenario will be produced that will require management ‘ ‘More strict ‘ and disposal. The level of treatment is not known ‘‘Less strict’ 0 at present. In DRI's analysis of the costs of envi- Contaminant —. /0 Removal Ton/d O/O Removal Ton/d 3 ronmental protection, “less strict” and “more NH 85 004 91 7 004 Bicarbonate 77 21 47 943 2630 strict” pollutant discharge criteria were as- Boron 70 008 982 011 sumed.’” In table C-1 I their estimates are given Calcium 99 184 999 1 86 for the total quantities of pollutants produced by Carbonate 90 1 67 958 1 78 treatment for surface discharge of 10,000 acre- Chloride 94 070 996 074 ft/yr of excess mine drainage water of the quality Fluoride 90 050 99.0 055 Magnesium 99 221 999 223 shown in table C-7 for the less strict and more Silcia 83 046 967 054 strict regulations. These quantities could be ap- Sodium 94 10.49 997 11 12 propriately scaled down or up for different rates Sulfate 97 1262 999 1300 of drainage-water production. The effect of the Total 5208 5827 different standards on the total quantity of pollut- SOURCE Adap!ed from T D Nevens et al ~ DRI Wafer PunfIcaIIon ASSOCldlE+S and Slone dnd ants produced is not large. However, the costs of Websler Englneerlng ) Predcled Cosfs of ErIti/?OflrWh!dl Conffos for a Comr~lerc)d 011 achieving the “more strict” criteria would be Shale /ndustry Vohme / An Engfneerfng Analys/s Depa:tmenl of Energy July 1979 much higher.

Appendix C References

1D, S. Farrier, Division of Environmental Sciences, “G. W. Dawson and B. W. Mercer, “Analysis, Screen- Laramie Energy Technology Center, Department of En- ing and Evaluation of Control Technology for Waste- ergy, Laramie, Wyo., personal communication, July water Generated in Shale Oil Development, ” Quarterly 1978. Reports, Battelle Pacific Northwest Laboratory, Rich- ‘R. F. Probstein, H. Gold, and R. E. Hicks, Water I?e- mond, Wash,, January 1977-March 1979. quirements, Pollution Effects, and Costs o.f Water Sup- ‘]Water Purification Associates, A Study of Aerobic ply and Treatment for the Oii ShaJe Industry, prepared Oxidation and Allied Treatments for Upgrading In Situ for OTA by Water Purification Associates, October Retort Waters, contract No. EW-78-C-20-0018 with Lar- 1979, p. 81. amie Energy Technology Center, Department of Energy, ‘Environmental Protection Agency, A Preliminary As- Quarterly Status Report, August 1979. sessment of the Environmental Impacts From Oil Shale ‘“E. F. Bates and T. L. Thoem (editors), Pol)ution Con- Development, prepared by TRW and DRI under control Guidance for Oil Shale Development, Revised Draft tract No. 68-02-1881 (EPA-600/7-77-069), July 1977. Report, Environmental Protection Agency, Cincinnati, ‘J. P. Fox, K. K. Mason, and J. J. Duvall, “Partitioning Ohio, July 1979. of Major, Minor, and Trace Elements During Simulated ‘l Supra No. 4, In Situ Oil Shale Retorting in a Controlled-State Re- 12 Supra No. 5. tort, ” Proceedings of the Twelfth Oil Shaie Symposium 1‘Ibid. (J. H. Gary, cd.), Colorado School of Mines Press, ‘%upra No. 4. Golden, Colo., 1979, pp. 58-71. “Denver Research Institute, Predicted Costs of Envi- ‘F. C. Haas, “Analysis of TOSCO II Oil Shale Retort ronmental Controls for A oil ShaJe Industry; Vo]ume l— Water, ” paper presented at ASTM Symposium D- An Engineering Analysis, prepared for the Department 199.33 on Analysis of Wastes Associated With Alterna- of Energy under contract No, IZP-78-S-O2-51O7, July tive Fuel Production, Pittsburgh, Pa., June 4-5, 1979. 1979. ‘Ibid. “Ibid, ‘E. W. Cook, “Organic Acids in Process Water From Green River Oil Shale,” Chemistry & Industry, May 1, 1971, p. 485. APPENDIX D Technologies for Managing Point Sources of Wastewater

Introduction

This appendix describes the wastewater streams that will be produced in oil shale facilities, including leachates from solid waste disposal. The physical, chemical, and biological treatment devices and systems are then described, Finally, developer plans are reviewed to show how water supply, wastewater treatment units and systems, and methods of disposition might be combined into comprehensive water management schemes for commercial-scale oil shale facilities.

Oil Shale Waste Streams That Will Require Treatment

The major point source streams that will re- wastes and can easily be handled in commercially. quire treatment are: available biological u-nits. Leachate from spent or raw shale piles on the ● excess mine drainage water—principally for surface is not considered as a separate stream re- plants near the center of the Piceance basin; quiring treatment during the operating life of the ● retort condensates—especially and perhaps plant. With proper compaction and irrigation, exclusively for in situ operations; water will be either retained in the pile or lost by ● gas condensates—for all systems; evaporation. There should therefore be little ac- ● coker and hydrotreater condensates from all 1 cumulation of leachates. There will be storm and plants that have onsite upgrading or refining snowmelt runoff, but this will be in limited quan- operations; and 2 tities and will have a low salt content. The small ● streams from service operations—including quantity of water that may percolate through the boiler feedwater treatment wastes and cool- pile after intentional leaching can be expected to ing tower blowdown. be low in both organic and inorganic substances, ] The other streams are either relatively small or This water can be used for dust control in raw relatively clean and consequently require little shale crushing operations and will thus find its treatment. They include boiler blowdown, rain way back to the retort, Leachate from spent in and service water runoff, and sanitary wastes. situ retorts poses a potential problem of unknown Sanitary wastes will certainly need treatment, magnitude, Design concepts for its control are dis- but they should be similar to typical domestic cussed in chapter 8.

Individual Methods for Point Source Wastewater Treatment Physical Methods ally needed before the wastewater can be sent to sensitive treatment systems like biological ● Gravity separators are used to treat nearly all oxidizers. oily wastewaters. They are especially common ● Coalescing cartridge separators (figure D-1) in refineries and chemical plants. The simplest are more effective devices that can reduce oil are impingement-type devices such as API concentrations to as low as 1 mg/l. In this type separators, corrugated plate interceptor sepa- of separator, oily wastewater is pumped rators and parallel plate interceptor sepa- through a coarse filter medium within the car- rators. These devices are very inexpensive and tridges, causing oil droplets and some mechan- reliable but they can be used only for first- ically emulsified oil to coagulate into large stage oil removal. Additional treatment is usu- globules which float to the top of the separator

488 Appendix D– Technologies for Managing Point Sources of Wastewater ● 489

Figure D-1 .—Cartridge-Type Coalescing Oil-Water and are removed. These devices have high re- Separator moval efficiencies but tend to clog if the water contains suspended particles. They can also be fouled by growth of micro-organisms on the filter medium. ER ● Air flotation is even more effective but is relatively complex. One device—the dissolved air flotation cell—is shown in figure D-2. In this separator, air is injected into the oily wastewater as fine bubbles, The oil droplets adhere to the air bubbles and rise to the surface as a froth, which is skimmed off by a motor-driven rake, Some small suspended particulate contaminants can also be removed in the froth and others will settle to the bottom of the cell and can be removed as a sludge. Coagulant can also be added to aid removal efficiency. If lime is added, for example, it will precipitate some heavy metals and certain anions such as carbonates. OILY ● Clarification [also called coagulation/sedimen- M IXTU R E tation or precipitation/sedimentation) may be used to settle out oil, to remove suspended solids, or to precipitate toxic metals, carbonate, and other anions. A slant-tube clarifier is shown in figure D-3. Accumulation of oil droplets and particulate on the tubes greatly enhances separation of the materials compared SOURCE. Assessment of Oil Shale Retort Wastewater Treatment and Control with the performance of simpler gravity de- Technology, Hamilton Standard Division of United Technologies, July 1978, p 5-3. vices, Chemicals can also be added in an up-

Figure D-2.— Dissolved Air Flotation OILY WATER IN FLUENT WATER DISCHARGE

OVER FLOW DRIVEN SHUTOFF RAKE *a *am I I I

. . —. BACK PRESS

EXCESS o\ AIR OUT LEVEL CONTROLLER

SOURCE: Assessmentssessrnent ofOil Shale Retort Waste water Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-3.

63-898 0 - 80 - 32 490 ● An Assessment Oil Shale Technologies

Figure D-3.—Clarification and Precipitation

RAPID SEDIMENTATION AND CONTINUOUS . GRAVITY DRAINAGE

CLARIFICATION I IN LET

MIX TANK

/ /\

CLARIFIER SIPHON SLUDGE COLLECTOR SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-3

stream mixing tank to aid precipitation (such as watered sludge is periodically removed from sodium hydroxide) or coagulation (such as alum the filter medium by mechanical cleaning. Ul- or a polyelectrolyte). trafiltration, in which the wastewater is forced ● Filters can be used to remove particles and in through a membrane, is often used for separa- some cases oil. Some of the more common filter- tion of oil and water. It is generally limited to ing devices are shown in figure D-4. Pressure separation of chemically stabilized emulsions filters are generally automatic devices in which and is not suitable for mechanical emulsions. the contaminated water is sucked inwards In multimedia filters, granular materials through a series of leaves on which a filter cake such as sand forma filtering bed through which forms. The filter may be used to remove par- the wastewater is pumped. The water passes ticles from dilute wastewaters as the first stage through a series of layers with granules of in- in a treatment system, or it can be used to de- creasingly fine size, The collected solids are water the sludge products from other separa- subsequently removed by backflushing with tors. The filter cake is generally very low in clean water. This filter produces a sludge, moisture, which eases disposal problems. rather than a dry cake, which requires addi- Vacuum filtration can also be used to remove tional dewatering before disposal. The multi- suspended particles from wastewater but is media filter is generally more economical than more suitable for dewatering concentrated pressure filters for high flow rates and dilute streams and sludges. Two vacuum devices are slurries. shown in figure D-4, In the rotary vacuum filter, ● Stripping with steam (figure D-5) or with air or

a rotating drum dips into a trough filled with flue gases is used to remove NH3 and sulfide wastewater, and suction is applied to the inside gases from wastewater. The operation is car- of the drum. Water is drawn through the per- ried out in a packed column or a plate column, forated surface of the drum and solids are de- and two-stage processing is sometimes em-

posited on the outside as a filter cake. As the ployed to provide independent recovery of NH3 drum rotates, the dewatered sludge is scraped and sulfuric acid, If the stripper is part of a off and falls into a receiving trough. A filter treatment system that includes biological treat-

press is functionally similar except that the ment, some NH3 is usually left in the stripper wastewater is sucked or pumped through a product to act as a nutrient for the micro-orga- series of plate-and-frame assemblies. The de- nisms. Appendix D–Technologies for Managing Point Sources of Wastewater . 491

Figure D-4.— Filters for Wastewater Treatment

A. Pressure filter B. Rotary vacuum filter

,“.. . “. .“ . . . .

OILY OIL CO NCm NIRATa

“ . . . -. . , . : . . . . “. . ‘ . ,...... ~: ..,::,:::’ : , . . ., ...... ~,~. . . . , . . ,. . . Fmcc . . . : , ‘. . . “ “ , . wATCm “ “ . . . .- : ‘ : “

C. Ultrafiltration I

- 1’ I ) I CYCLE

---

cOAL . . ~ .,

D. Filter press AN

E. Multimedia filtration

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, “Hamilton. Standard Division of United Technologies, July 1978, PP 5-4, 5-6, 5-11, and 5-12

Adsorption is used to remove dissolved metals, . Distillation (figure D-7) is a simple process in organic compounds, and many toxic sub- which wastewater is purified by boiling. The stances. Adsorption with regenerated carbon products are a very clean steam, which can be slurries and with resin particles is shown in condensed with cooling water or in air-cooled figure D-6. Other systems use activated carbon condensers, and a highly contaminated concen- particles that are contained in a fixed bed, ei- trate. Very pure water can be obtained, but the ther without regeneration or with regeneration process has large energy requirements. Cooling within the column. In all cases, the separation water is also needed in most applications. involves physical adsorption of the contami- ● Reverse osmosis can also recover very pure nants on the surfaces of the particulate water from concentrated salt solutions. Some medium. dissolved organic materials can also be re- 492 ● An Assessment of Oil Shale Technologies

Figure D-5.—Steam Stripping through gentle agitation and thereby reduce the amount of water that must be removed in subsequent processes. ● Evaporation (figure D-1 1) is a final step for con- V A PO R S HEAT INTER- centrating solid residues. It is generally accomplished in evaporation basins, which are I simply lined ponds into which the sludge is WATER pumped and allowed to stand while the mois- w ASTE W ATE R ture evaporates, or in sludge drying beds, which contain a layer of coarse sand over a layer of fine sand over clay or perforated plastic drainage tiles. Both systems require large areas of land compared to other more compact devices such as vacuum filtration but they are inexpensive and require little maintenance. Sludge drying beds are faster but more SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control expensive. Both systems require mechanical Technology, Hamilton Standard Division of United Technologies, July 1978, p, 5-4 removal of the dried sludge, usually with a backhoe or front-loader. moved. A typical reverse osmosis system is shown in figure D-8. Each element in the separation system contains a membrane that sepa- Chemical Methods rates the clean product (permeate) from the concentrated waste or residual. The membrane ● Ion exchange is a process in which ions held by is pressurized on one side, which forces the electrostatic charges on the surface of resins pure water through the membrane and leaves are exchanged for ions with similar charges in the salt and organic contaminants on the other the wastewater. An example is a home water side. The process is very effective, but prob- softening system in which sodium ions (from lems arise if the wastewater stream contains rock salt) are exchanged for calcium ions in the very fine suspended solids (colloids) that can water supply, thereby reducing the hardness of clog the membranes and reduce their perform- the water. The process is classified as adsorp- ance. tion because the ion exchange occurs on the ● Electrodialysis cells consist of an anode and a surface of the resin particles and the ions to be cathode separated by two membranes—one removed must undergo a change of phase: from near the cathode through which cations (posi- the liquid phase of the wastewater to the solid tively charged ions) can pass and one near the phase of the resin. By this technique, harmful anode that is permeable to anions (negatively ions in the wastewater can be exchanged for charged ions). A system consisting of several the harmless ions of the resin. Ion exchange such cells is shown in figure D-9. The waste- can be used only for removing ions (such as water is pumped between the membranes. those from dissolved salts) from solution; it can- Upon application of an electric current, the ani- not be used for non-ionic contaminants such as ons migrate through one membrane towards organic compounds and suspended solids. A re- the anode and the cations migrate through the generating ion exchange system is shown in other to the cathode. The concentration of ionic figure D-12. Such a system is suitable for recov- species in the central chamber is thereby re- ery of valuable ions from dilute streams. It has duced. The concentrated streams beyond the a limited capacity, thus would not be useful for membranes are the waste products. Electrodi- first- or second-stage salt removal but would alysis is very effective in removing dissolved more likely be reserved for “polishing” a salts but it is very expensive because each treated effluent from another treatment tech- system must be specifically designed and manu- nology. factured for the particular application. ● Wet air oxidation was developed for destruc- . Thickeners (figure D-1 O) are used between a tion of organic contaminants. In this process sludge-generating step (such as clarification) (see figure D-13), wastewater is exposed to air and a sludge-dewatering step (such as vac- under elevated temperature and pressure, thus uum filtration). These concentrate the sludge causing organic compounds to oxidize com- Appendix D–Technologies for Managing Point Sources of Wastewater • 493

Figure D-6.—Adsorption Systems for Wastewater Treatment

ADSORPTION

IN FLUENT W A STEW AT E R

REGENERATED CAR BON SLUR RY TR E ATE D I EFFLUENT DEW ATE R I N G FIN ES SCREEN REM OVA L SCREEN REGENERATION STORAGE F U RN ACE

‘ i

- REGENERATE D FINES TO CAR BON WASTE SLURRY TANKS A. Carbon adsorption with external regeneration

I I TANK

B. A two-tank adsorption system

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, pp. 5-4 and 5-6 494 ● An Assessment of Oil Shale Technologies

Figure D.7.– Distillation Figure D-8.– Reverse Osmosis

CON DENsER WASTE WATER . . ● FEE D

PREPROCESSING

FEED WATER TO DISCHARGE OR REUSE

DRAIN TO WASTE TANK PRODUCT WATER (PERMEATE)

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control July 1978, p 5-7. Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-7

Figure D-9.—Electrodialysis

OUTLET OF CONCENTRATION STREAM

1- - - OIL. CATHODE COMPARTMENT ANODE COMPARTMENT STREAM STREAM

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-7. Appendix D-Technologies for Managing Point Sources Wastewater ● 495

FigureD10.-M echanical Sludge Thickening

BLADE

CON D U I T COUNTER F LOW TO MOTOR

\\ DRIVE UNIT N FLUE !

CON D OVER ALAR

PLAN

BASE HAN D R A I L

SOURCE: Assessment of Oil Shale Retort Waste Water Treatment anrd Control Technology, Hamilton Standard Division of United Technologies, July 1978, p. 5-9 496 ● An Assessment of Oil Shale Technologies

Figure D-11 .—Evaporation Systems for Sludge Drying

A. Evaporation pond

-- - _&_ - . ( - y~-

PLAN WALK

3-1 N COARSE-SAND /

F“OR

B. Sludge drying bed

United Technologies, July 1978, pp. 5-10 and 4-11. Figure D-12. —A Regenerable Ion Exchange System

UNIT

EJECTOR

O U T L E-,

SUPPORTING BED TANK TO WASTE

SOURCE Assessment of 011 Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Divlsion of United Technologies. July 1978, p 5-14

Figure D-1 3. — Wet Air Oxidation

REACTOR

SEPARATOR I

AIR

E X HAUST

HOLD I N G FEED HIGH AIR EXPANSION 7A N K COMPRESSOR ENGINE PUMP

SOURCE. Assessment of 0il Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies, July 1978, p 5-14 498 ● An Assessment of Oil Shale Technologies

pletely or at least decomposing them into forms chromic acid and cyanide. In oil shale plants, it that are more easily treated. In particular, the could be employed for removing hazardous process can be used to increase the biodegrad- organics. able properties of compounds that are normally Chemical oxidation relies on contacting waste- refractory (resistant) to biological oxidation. water with oxidizing chemicals. As mentioned The method is very effective but is costly be- previously, chemical oxidation can be com- cause the highly corrosive environment within bined with other oxidizing systems. The exam- the equipment requires expensive materials ple of ozone combined with ultraviolet light was and construction methods. mentioned above. The chemical combination of Photolytic oxidation processes (figure D-14) use ozone and hydrogen peroxide has been found to light to oxidize organic contaminants. They can work well with refinery wastes, which are simi- be used in conjunction with chemical oxidizers. lar to the expected wastes from oil shale proc- One technique that works well in many indus- essing. Potassium permanganate has been trial situations is the combination of ultraviolet tested with oil shale streams. light and ozone gas. The process has the disadvantage of requiring relatively long residence times. Biological Methods Electrolytic oxidation is similar to electrodialysis except that it can be used to oxidize or Anaerobic and aerobic digestion.-The princi- reduce dissolved contaminants to their gaseous pal anaerobic system is the anaerobic digester, forms. A typical system is shown in figure D-15. which is a closed, heated vessel in which the The method is costly to operate, and is general- microbial population is maintained under an at- ly reserved for removing very valuable or very mosphere of its own waste gases. Such systems hazardous substances, It has been used with in- have a long history of application in treatment dustrial wastewaters to remove, for example, of municipal wastes. A typical digester is

Figure D-14.— Photolytic Oxidation

MIXER

f GAS

TEMPERATURE FIRST CONTROL STAGE

SECOND TEMPERATURE STAGE CONTROL Appendix D–Technologies for Managing Point Sources of Wastewater Ž 499

Figure D-15.— Electrolytic Oxidation

CATHODE WATER 1 1

CATHODE IN F I-U EN T W ASTEWATE R

s c

SETTLING R

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies. July 1978, p 5-15 shown in figure D-16. The illustration shows a activated sludge system is shown in figure flare stack for disposal of the digester gas. It is D-1 7, also possible to use the gas for many industrial 2. Trickling filters are also commonly used for purposes. In municipal systems, the gas is used municipal wastewater treatment. One sys- as fuel for the compressors that maintain the tem is shown in figure D-18. In this process, atmosphere within the unit. Some of the com- the microbial population lives on the fixed mon aerobic biological systems, in which diges- elements of the filtering medium, and the tion takes place in an oxygen-rich atmosphere, wastewater trickles past them. Stones were are described below, a common medium in the past; plastic is 1. Activated sludge processes treat waste more common today. Extra nutrients are streams that contain 1 percent or less of sus- often added to the entering waste stream to pended solids. In this process, flocculated accelerate the biodegradation process. The biological growths are continuously circu- process requires relatively little land area lated in contact with organic wastewater in and can achieve high throughputs with the the presence of oxygen. Organic compounds proper adjustments of acidity, nutrients, and that can be decomposed include polysaccha- trace chemicals. It does not work well if the rides, proteins, fats, alcohols, aldehydes, fat- waste is chemically unstable or if it contains ty acids, alkanes, alkenes, cycloalkanes, and suspended solids. aromatics. The process is widely used for in- 3, Aerated lagoons are similar to activated dustrial wastes and is even more common in sludge processes except that the micro-orga- municipal treatment plants, It is relatively nisms are not circulated. The lagoons are inexpensive to fabricate and operate, and is essentially stabilization ponds that are usually cost effective for a variety of organic equipped with mechanical agitators and contaminants. Its major disadvantages are aerators to provide the microbial population complex control procedures and high main- with uniform conditions and with the oxygen tenance and power requirements. A typical that they need to grow. About 60 to 90 per- 500 ● An Assessment of Oil Shale Technologies

Figure D-16. —An Anaerobic Digestor

FLARE

I SUPERNATANT

SLUDGE EFFLUENT

IN FLUENT SLUDGE

HEAT MIXERS EXCHANGE R “1

SOURCE: Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Divi- sion of United Technologies, July 1978, pp. 2-12 to 2-24.

Figure D-1 7.—The Activated Sludge Process

IN F

I RECYCLED SLUDGE

the air. Biodegradation occurs very rapidly. A unique advantage of RBCs is that different strains of micro-organisms can be established on each of the disks, One strain could be established on an upstream disk to remove the organic compounds that might be harmful to another strain on a downstream disk. This could not be done in other biological systems in which all micro-organisms are exposed to essentially the same environment. Appendix D–Technologies for Managing Point Sources of Wastewater ● 501

Figure D-18.— Trickling. Filter Waste Treatment

CHEM IC A L PH ADJUSTMENT N I T ROG EN & PHOSPHORUS

RAW WASTE TRICK L 1 N G FI LTE R PR IM AR Y CLARIFIER

TR E A T E D AIR W A S T EW A T ER

SEC ON D A R Y SLU DG E CLARIFIER

SOURCE Assessment of Oil Shale Retort Waste water Treatment and Contro/ Technology, Hamilton Standard Division of United Technologies, July 1978 p 5-17

Figure D-19.—Aerated-Lagoon Waste Treatment

NUTRIENT FEED

MECHANICAL AERATORS

I N FLUENT LIQUID \

EARTH CONSTRUCTION )

C LA F? 1 F I E R

EXCESS SLUDGE

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology. Hamilton Standard Division of United Technologies, July 1978 p 5-17

Figure D-20.— Rotating Biological Contractor

SE CON DAR Y SETTLING

I J

SOURCE Assessment of Oil Shale Retort Wastewater Treatment and Control Technology, Hamilton Standard Division of United Technologies. July 1978, P 518 502 ● An Assessment of Oil Shale Technologies

Status of Point Source Water Pollution Control Methods The removal efficiencies, reliabilities, adapt- would be suitable if used in conjunction with pre- abilities, and cost features of some point source treatment and post-treatment systems. Photolytic control technologies are summarized in table D-1. methods should also work, but they are not well demonstrated. Any filtration method would re- Removal Efficiency duce suspended solids to acceptable levels. For dissolved inorganic, clarification would general- All of the systems could perform adequately for ly have low removal efficiency but could be suit- first-stage oil and grease removal, and meeting able for removing metals. Distillation would be discharge standards should be possible if a bio- very effective for salt removal. Ion exchange or logical oxidation unit is used for final cleaning. If reverse osmosis would also work well, but their not, single-stage cleaning in a coalescing filter limited capacities might restrict their use to final would be sufficient. For dissolved gases, any of removal of low-level contaminants. For sludges, the stripping techniques should be adequate sludge drying beds and evaporation basins would alone, and a biological oxidation unit could be be very effective in the semiarid oil shale region. used for final removal of any residual NH3. For re- The alternate processes would be much less effec- moval of organic compounds, carbon adsorption tive.

Table D-1 .–Relative Ranking of the Water Treatment Methods

Contaminant Technology Removal efficiency, % Relative reliability Relative adaptability Relative cost Oil and grease Dissolved air flotation 90 Very high Very high Medium Coalescing filter 99 High High Medium Clarification 80 Very high Very high High Dissolved gases Air stripping 80 High - High Medium Steam stripping 95 Very high High Medium Flue gas stripping High Medium Medium Biological oxidation High Medium Medium Low Dissolved organics Activated sludge 95 BOD/40 COD High Medium Low Trickling filter 85 BOD High Medium Low Aerated lagoon 80 BOD Medium Medium Low Rotating contactor 90 BOD/20-50 COD High Medium Low Anaerobic digestion 60-95 BOD High Medium Medium Wet air oxidation 64 BOD/74 COD Medium High Very high Photolytic oxidation 99 BOD Medium Very high Very high Carbon adsorption 99 BOD Medium High Medium Chemical oxidation 90 BOD/90 COD Very high Very high High Electrolytic oxidation 95 BOD/61 COD Medium High Suspended solids Clarification 50 High High Medium Pressure filtration 95 High High Medium Multimedia filtration 95 Very high High Low Dissolved solids Clarification Low except for metals High Medium Medium Distillation 99 Medium Low Very high Reverse osmosis 60-95 Medium Medium Medium Ion exchange High High Low High Electrodialysis 10-40 Medium Medium Very high Sludges Thickening Product 6-8% solids Very high High Medium Anaerobic digestion Low High Medium Medium Vacuum filtration Product 20-35% solids High High High Sludge drying beds Product 90% solids Medium Low Medium Evaporation basins Product 95% solids Very high Low Low Filter press Product 35% solids Very high High High Aerobic digestion Low Low Low High

BOD = biological oxygen demand COD = chemical oxygen demand Adapted from: Assessment of Oil Shale Retort Wastewater Treatment Control Technology, Hamilton Standard Division of United Technologies, July 1978, pp 2-12 to 2-24 —. —

Appendix D–Technologies for Managing Point Sources of Wastewater • 503

Reliability As shown in table D-1, all of the systems for oil and grease removal are highly adaptable. For dis- For oil and grease removal, the coalescing filter solved gases, air stripping and steam stripping has the only potentially severe reliability problem are highly adaptable; flue gas stripping is down- because it tends to clog. For dissolved gases, all of graded because suitable gases may not be avail- the stripping techniques should be sufficiently re- able. Biological systems are downgraded because liable, Biological oxidation is considered less reli- they may have problems with the high NH3 con- able because of the need for carefully controlled centrations in some oil shale wastewaters. They inlet conditions. For organics removal, chemical could probably be used only with some pretreat- oxidation should be the most reliable; the biologi- ment system. For dissolved organics, the oxida- cal systems (activated sludge, trickling filters, ro- tion systems and carbon adsorption are very tating contractors, and anaerobic digestion) should adaptable, the biological systems less so because also be satisfactory. All systems for removal of of potentially toxic substances and because they suspended solids should be highly reliable, For are sensitive to inlet conditions. All methods for dissolved solids, clarification and ion exchange removing suspended solids are highly adaptable. are highly reliable. Distillation is downgraded However, problems may be encountered with the because of its potential for corrosion; reverse removal of dissolved solids because of possible in- osmosis because of potential fouling problems; terference from high salt loadings or membrane and electrodialysis because it has a relatively clogging. The only significant problem with distil- short history of successful applications. For han- lation is its need for cooling water, which may not dling sludge, thickening, anaerobic digestion, and be readily available at oil shale sites. For sludge all of the filtration techniques should be highly handling, thickeners and filters are highly adapt- reliable, able. Sludge drying beds and evaporation ponds should have no technical adaptability problems, but they are downgraded because evaporation Adaptability would mean a loss of the contained moisture, which could be recovered with filtration systems. Few treatment techniques have been extensive- Aerobic digestion is downgraded because some of ly tested with oil shale waste streams, and most the components of oil shale sludges may resist bio- will be adapted directly from other industries. logical degradation. Physical and chemical conditions in which a device will be expected to operate may differ significantly from those for which it was originally developed and in which it is normally operated. For cost example, a method suitable for petroleum refineries may not work well in the oil shale industry Costs in table D-1 are based on experience with where it will be exposed to shale fines, organo- similar systems in other industries. As indicated, metallic complexes, or other contaminants pecu- systems with moderate capital and operating liar to oil shale wastewaters. Although a system costs are available for all of the major contami- cannot be fully evaluated until it has been tested nants, and many of the lower cost options also under commercial operating conditions, indica- have reasonable removal efficiencies, reliability, tions of the expected performance can be ob- and adaptability. The only potentially serious tained by examining how easily the technique has problem is in removal of dissolved solids, where been adapted to other new industries significant- the medium-cost systems (reverse osmosis and ly different from the one for which it was devel- clarification) have questionable removal efficien- oped. cies. 504 Ž An Assessment of Oil Shale Technologies

Integrated Wastewater Treatment Systems

Generally, no one device is able to remove all these requirements, reinfection is a costly dis- the contaminants from a process stream, Further- posal option, because deep wells would be re- more, certain process streams may be combined quired to avoid contamination of aquifers that before treatment or at different stages of treat- discharge to the surface, and an extensive piping ment to take advantage of scale economies. network would be needed. It has been suggested Treatment systems that have been proposed for that the reinfection option be used only for very oil shale wastewater streams are shown in figure objectionable and relatively untreatable wastes D-21 for mine drainage water, figure D-22 for gas and that underground disposal of the relatively condensate, and figure D-23 for retort conden- clean mine drainage water would be wasteful in a sate. These systems and their component units region where water is scarce. 17 18 are discussed below. For the option of discharge to a river, dissolved solids would have to be reduced to less than 500 mg/l, which can easily be achieved by a mem- Excess Mine Drainage Water brane process such as reverse osmosis, as shown in figure D-21. Treatment is not expected to be dif- This water can be used without treatment as a ficult, but conclusive test data are not yet avail- slurry medium for backfilling burnt out in situ able. 19 Discharge permits will probably also speci- retorts,’ but sufficient ground water may not be fy a phenol concentration of no more than 0.001 available over the lifetime of the plant for this mg/1 and a boron concentration of less than 0.75 control option. Additional water might have to be mg/1. Specific ion absorbents are available for imported from other sites. Another disposal op- these substances and can be used, as suggested in tion is reinfection, but for this purpose the water option A of figure D-21. Alternatively, a second- should be free of suspended solids and contain no stage reverse osmosis step may prove more eco- constituents that would react adversely with the nomical, as suggested in option C of figure D-21. A water in the receiving strata.5 6 7 While mine single-stage, high-pH reverse osmosis step may drainage water could easily be treated to meet also prove adequate, particularly if some of the

Figure D-21 .—Possible Treatment Options for Excess Mine Drainage

Spent Shale

Mine Option A Backfill to burned (Reference 8) water out MIS retorts -r Aerated Option B Mine Pretreatment Reverse Phenol Boron Discharge * holding pond (Reference 9) osmosis adsorption adsorption

Sodium hydroxide 1 Mine Stage 2 Aerated Option C Pre- Stage 1 reverse pH Discharge 9 osmosis m m reverse holding (Reference 9) adjustment osmosis pond stream

Option D Mine ● Weak acid Steam pH Reverse Aerated Discharge ion exchange * stripping Adjustment m osmosis ● holding pond (1-wk retention) stream

SOURCE R F Probstein, H. Gold, and R. E Hicks, Wafer Requirernents, Pollution Effects and Costs of Water Sq@y and Treafrnerrt for the Oi/ Sha/e /rrdustry, prepared for OTA by Water Purificatlon Associates, October 1979 Appendix D–Technologies for Managing Point Sources of Wastewater Ž 505

Figure D-22.— Possible Treatment Options for Gas Condensates

Option A (Reference 10)

Steam Organic Gas Oil-water stripping Biological Cooling separation 3 polishing condensate & NH oxidation (if required) Tower recovery Option B ● (Reference 11) ● ● . Stream Filter Gas stripping Chemical Biological Filter & oil-water treatment oxidation condensate & NH3 separation recovery .

Carbon Desalinization sorption

SOURCE R F Probstetn H Gold and R E Hicks, Wafer RequirementsReaufrernenfs, Po//utIorI Effects and Cosfs of Wafer Supp/y and Treatrnenf for the 0// Shale Industry, prepared for OTA by Water Purification Associates, October ’1979 dissolved salts are first removed by chemical pre- that of retort condensates and may prove to be treatment in a weak acid ion exchange degasifier more or less amenable to biodegradation. Other as shown in option D of figure D-21, processes such as resin adsorption, carbon ad- An aerated holding pond would be used in any sorption, and wet air oxidation are available for of the options to dissipate any NH3 and phenol organics control and may prove adequate in com- that are not removed in the treatment units. The bination. Preliminary laboratory investigations on pond would also serve as an equalization basin retort condensates suggest that no single process for blending in waters that can bypass the treat- (except possibly wet air oxidation) will be capable ment train. The size of the bypass stream will of controlling all the organics present. vary with the quality of the drainage water, the The use of a cooling tower as part of the treat- effectiveness of the aeration pond, and the cri- ment systems (as shown in option A of figure D-22) teria of the discharge permit. would have two advantages. First, experience with similar wastewaters has shown that some degradation of organics occurs in a properly Gas Condensate operated cooling tower circuit. 22 Second, the volume of blowdown water leaving the cooling tower This stream requires treatment for removal of is one-half to one-tenth that of the makeup water, dissolved gases and organics. Dissolved NH3 will depending on the number of concentration cycles largely be combined with CO2 in the form of am- used. Final organic polishing, if necessary, can monium bicarbonate. Both gases can easily be re- therefore be done on a smaller, more concen- moved by steam stripping. Stripping has been trated stream. Because the wastewater stream tested in the laboratory with both a synthetic am- will previously have been subjected to high-tem- monium bicarbonate solution and an actual gas perature steam stripping, air pollution by volatili- condensate. 20 21 It was found that the small zation of organics in the cooling tower is not ex- amount of oil present in the condensate was rap- pected to be a problem. This assumes that any or- idly removed in the stripping operation, but even ganics created in the biological oxidation step will if an oil-water separator is required before the be either nonvolatile or nontoxic. stripper (as suggested in figure D-22) separation Although salts are not a major contaminant in difficulties due to emulsification are not ex- the gas condensate stream, desalination by re- pected. verse osmosis could be used to remove inorganic Organic control by biological oxidation has not and organics. In option B of figure D-22, a desali- yet been demonstrated on an actual gas conden- nation step is included to provide a very clean dis- sate stream, The organic mix is different from charge stream. An effluent stream could also be Figure D-23.— Possible Treatment Options for Retort Condensates

Filter & Lime treatment Activate Option A Retort oil-water & ammonia carbon * (Reference 12) condensate* separation removal sorption

Option B Retort Thermal Boiler makeup (Reference 13) condensate> treatment sludge 1 Sludge r

Retort Option C Discharge or re-use condensate > treatment (References 14, 15) ● Concentrate I Evaporation pond

● ✎ ☛ ✌ Dissolved Option D Retort API Chemical Steam Multimedia Biological Ultra separator treatment air stripping filtration filtration flotation treatment (Reference 16) ● ●

Carbon Ultraviolet filter sterilizer I

SOURCE: R. F. Probstein, H. Gold, and R. E. Hicks, water Requirement, Pollution Effects and Costs of Water Supply and Treatment for the Oil Shale Industry, prepared for OTA by Water Purification Associates, October 1979. Appendix D–Technologies for Managing Point Sources of Wastewater • 507 taken from any intermediate stage of the treat- organics removal by only about 10 percent, indi- ment system to provide water for various reuse cating that much of the biorefractory organic options. matter is not adsorbed on carbon. Polymeric resins have been shown to facilitate removal of organics from retort condensates,26 but it is not Retort Condensate known whether the ones removed are those that are resistant to biological and activated carbon The retort condensate stream presents the treatment. most formidable treatment challenge. As dis- The inhibition of biological action by toxic sub- cussed in chapter 8, this stream is created when stances is also expected to be a problem, The tox- water and oil vapors condense within in situ ics may be either organic or inorganic, and can be retorts, and some aboveground retorts if they are expected to be different in the condensates from operated at a low top temperature. The conden- different retorts. Their characteristics and con- sate will be contaminated with oil, dissolved centrations may even change with time if retort- gases, inorganic salts, and organic substances, all ing conditions are not constant—a normal situ- of which will have to be removed. ation in MIS processes. Even with all of its poten- In the conventional treatment scheme of option tial disadvantages, biological oxidation could A in figure D-23, oil and suspended solids are first prove more economical and more effective than separated from the water. Oil-water separation other processes (such as wet air oxidation) when by API units may not be adequate because of combined with appropriate pretreatment and pol- emulsions, and some emulsion-breaking technique ishing steps. will probably be required. The techniques that Wet air oxidation removes a much wider varie- would be appropriate for oil shale wastewaters ty of organics but it is also more expensive. In this have not yet been determined. process, organic material in water is oxidized by

The addition of lime will facilitate NH3 removal air at about 500° F (260° C). The water is pressur- and will also remove calcium, magnesium, and ized to prevent boiling. The reaction takes about carbonate ions. NH3 is easily removed by steam 30 minutes and a pressure vessel is required that stripping, but unlike the gas condensate, the re- is large enough to contain the water for this tort condensate contains strong acid anions that length of time. The cost of wet oxidation is not will “fix” the NH3 as ammonium ions, which can- strongly dependent on the concentration of the not be directly stripped. Lime addition will ele- waste, and unlike biological treatment it can be 23 vate the pH and convert ammonium to NH3. The cost effective for very concentrated wastes. Wet pH elevation is also needed to prevent scaling and air oxidation also has several technical advan- fouling of the steam stripping column by carbon- tages, Because it relies on chemical oxidation, the ate precipitates. organic material that is to be destroyed does not Removal of organic substances from retort con- have to be biodegradable. In fact, biorefractory densates has not been adequately demonstrated. materials are often converted to biodegradable Activated carbon adsorption (option A in figure substances, and a biological process could be ef- D-23) would remove only about half of the organ- fectively used as a polishing step. No data have ics and would be expensive, given the high organ- been published on the performance of a wet air ic concentrations found in retort condensates.24 25 oxidation process with oil shale retort conden- Biological treatment (option D) has been sug- sates, but an investigation has been initiated.27 gested for control of organics, but complete re- Reverse osmosis membranes (option C in figure moval by biological processing may not be achiev- D-23) are also available for organics control,28 but able. The two major problems with biological recent tests have shown that considerable pretreatment are the presence of resistant (biore- treatment will be required to provide a feed that fractory) and toxic materials. It is expected that will not plug or foul the membranes, 29 In fact, a as much as half of the organic matter in retort pretreatment system similar to the treatment water will be biorefractory and that adequate re- train of option A in figure D-23 may be required moval may not be possible even with novel proc- for very dirty condensates. If this is done, then it ess modifications such as the addition of pow- is not clear that a final reverse osmosis step will dered activated carbon to the biological unit. Lab- be required to provide an effluent suitable for oratory tests have shown that the addition of pow- some of the low-quality reuse options. Neverthe- dered activated carbon to the aeration basin in an less, reverse osmosis is of interest because it also air-activated sludge biological system improves provides a means for control for some of the inor- 508 ● An Assessment Oil Shale Technologies ganic contaminants for which lime softening is not Other Wastewater Streams adequate. Ion exchange demineralization after organics removal is an alternative to reverse The two other major streams are the coker and osmosis, but its costs escalate rapidly with in- hydrotreater condensates from the shale oil up- creasing salt concentrations in the feed. grading section. Compositions of these streams It is apparent that even if the retort condensate are not known, but they should be somewhat simi- is to be treated to only the low-quality levels re- lar to the gas condensate. The exception is the quired by some re-use options, an elaborate treat- concentration of dissolved gas because, in the ment system similar to that shown as option D in absence of CO2, the NH3 will probably react with figure D-23 will be required. Even here additional H 2S to form ammonium hydrogen sulfide. Differ- treatment steps may be required. API separators ent steam stripping conditions will be required in may not be adequate, and an ultrafiltration step that more stages or more steam will be needed to upstream of the steam stripper may be needed to remove H2S. Modifications should not be extreme remove emulsified oil and large organic mole- because, unlike in the retort condensate, there cules. As discussed above, biological oxidation should be no NH3-fixing inorganic anions present. and carbon adsorption will not adequately control The treatment systems can be expected to be simi- the remaining organics, and resin adsorption or lar to any of the options shown in figure D-22. wet air oxidation steps may be required. An additional processing step to remove inorganic may also be required for some re-use options. Blowdown streams, regenerant streams, con- In view of the difficulty in treating the retort centrates, and sludge products from water treat- condensate (option B in figure D-23) in which the ment processes must also be handled. If a thermal treated water is used to raise steam for retorting sludge process is included in any water treatment is the most attractive. Volatilized organics will be train, it could be used to reduce the reverse incinerated in the retort, and other substances osmosis concentrates and ion exchange regener- can be removed in a concentrated sludge for dis- ant streams to a disposable sludge. If not, vapor position at a hazardous-waste disposal site. A compression evaporators may be used. These stripping pretreatment step may be needed to have been successfully demonstrated on a com- avoid accumulating NH3 and CO2 in the thermal mercial-scale at, for example, electric power gen- sludge device. No information has been published erating stations. Because cooling towers will on the feasibility of a thermal-sludge steam rais- probably be operated with few cycles of concen- ing process fed with retort condensates. Scaling tration, blowdown streams should not have high and fouling may be problems unless appropriate salt concentrations, and should be suitable for pretreatment steps are used. dust control and shale disposal operations.

Water Management Plans for Oil Shale Facilities

Complete water management plans must con- rein, of which about 40 percent is lost to the at- sider supply, treatment, waste recovery and re- mosphere through evaporation within the facility. moval, and ultimate disposition. Figures D-24 The rest is eventually used for dust control and in through D-26 are flow sheets that show how wa- the solid waste disposal area for spent shale ter would be used, treated, and disposed of in moistening, compaction, and revegetation. The three typical oil shale facilities. The flows into, principal components of this water are treated within, and out of the plants are indicated in gal- river water, sanitary wastes, blowdowns, runoff, lons per minute. service water, and condensates. Figure D-24 is a water management plan for an Figure 1)-25 is a plan for an aboveground in- aboveground direct facility that uses Paraho redirect plant that uses TOSCO II retorts. Because torts. The major sources of water are the Colora- the retorts are indirectly heated, and because up- do River, contaminated runoff from the facility grading facilities are included, water require- site and its associated disposal area, and gas con- ments are substantially higher than for the Par- densates from the retorting section. No upgrading aho plant. The total inflow is 7,386 gal/rein from facilities are included, so there are no upgrading the Colorado River, from surface runoff, and from condensates. The total water inflow is 2,357 gal/ gas condensates and upgrading condensates. Appendix D–Technologies for Managing Point Sources of Wastewater ● 509

Figure D-24.— Major Streams in a 50-000-bbl/d Aboveground Direct (Paraho) Oil Shale Plant (gal/rein)

Colorado River water 1883 663 686 Clarification I I (7) 17 Domestic water system BFW ~ CW / ● - treatment treatment

16 (2) Biological Steam Cooling treatment system tower BD BD @

Revegetation Dust Shale control disposal 221 791 (25) Equalization

43 water system & Oil/water 156 separation b Runoff and 138 Ieachates (29)

BFW = Boiler Feed Water CW = Cooling Water Retorting 336 307 ( ) = Losses gas treatment GC Treatment s = Sludge — \ TW = Treater Waste BD = Blowdown SOURCE R F Probsteln, H Gold, and R E Hicks, Water Requlrerrrents, Po//ufIon GC = Gas Condensate Eflects and Costs of Water SUPP/y and Treatrrrent for the 0// Shale /fldus- try, prepared for OTA by Water Purl flcatlon Associates, October 1979

About 40 percent of the water is lost through situ retorts. The system produces no liquid efflu- evaporation. The rest is eventually used for dust ent. The total net inflow is about 5,059 gal/rein, of control, or finds its way to the spent shale pile. which 34 percent is lost through evaporation and Figure D-26 is a plan for an MIS facility that is 34 percent is converted to steam for the retorts. located in a ground water area, Excess mine The rest is used to control dust and for disposal of drainage water is produced, and over 70 percent the mined raw shale. of it is reinfected. The rest is used in the plant, In summary, the aboveground direct plant will together with retort condensates, gas conden- dispose of about 604 gal/min of treated waste- sates, and surface runoff, The plant uses a ther- water and treated condensates in the spent shale mal sludge system to process the retort conden- disposal pile. An additional 22 I gal/rein of treated sate and to generate steam for injection into the in wastewater will be used for dust control. The 510 Ž An Assessment of 0il Shale Technoiogies

Figure D-25.—Major Streams in a 50,000-bbl/d Aboveground Indirect (TOSCO II) Oil Shale Plant (gal/rein)

Colorado River water

2177 2198 3937 Clarification

2400 1 BFW ~ Cw water treatment treatment system

(1191) (1630)

Biological Steam Cooling treatment system tower BD

Dust Shale Revegetation control disposal w

Retorting gas treatment upgrading GC BFW = Boiler Feed Water CW = Cooling Water ( ) = Losses 1072 ~ (53) S = Sludge TW = Treater Waste Stripping and BD = Blowdown GC = Gas Condensate NH3 recovery (6) RC = Retort Condensate

503 Organics 497 removal. (20) / 631 17 water . 37 system Oil/water 134 r separation \ Runoff and 117 Ieachates / v

SOURCE: R. F. Probstein, H. Gold, and R. E. Hicks, Water Requ/refnenrs, Pollutlorr Eflecfs afl~ COS@ of water SUPPIY and Treatment for the 0// Shale hrdustry, prepared for OTA by Water Purification Associates, October 1979. Appendix D–Technologies for Managing Point Sources of Wastewater Ž 511

Figure D-26.— Major Streams in a 50,000-bbl/d MIS Oil Shale Plant (gal/rein)

To reinfection Mine drainage water

7656 m 6539 ‘ ‘ 737 A A Clarification treatment Y 380 (5) 924 treatment treatment

14 (13) Biological Steam Cooling treatment system tower

w 14 L Revegtation Dust Shale control disposal 882 (26) Equalization - 42 water system \ Oil/water 141 separation \ 125 Runoff and 4 (68)

( ) = Losses s = Sludge

SOURCE: R.F. Probstein, H Gold, and R E Hicks, Water Requirements, Pollution Effects and Costs of Water Supply and Treatment for the Oil Shale Industry, prepared for OTA by Water Purification Associates, October 1979 512 Ž An Assessment of Oil Shale Technologies aboveground indirect plant will add about 1,827 water will be reinfected into the source aquifer. gal/rein of treated wastewater and concentrates Thus, the methods for wastewater management to the disposal pile. The MIS plant will use about and disposal are recycling after treatment, fol- 686 gal/rein of treated wastewater for raw shale lowed by disposal through evaporation, in dust disposal and 210 gal/rein for dust control An control, and in solid waste disposal areas. Excess additional 5,554 gal/rein of treated mine drainage treated mine drainage water will be reinfected.

Appendix D References

1H, P. Harbart and W. A. Berg, Vegetative Stabiliza- partment of Energy, final report, contract No. EE-77- tion of Spent Oil Shales, EPA-600/7-78-021, Industrial C-02-4534, NOV. 20, 1978. Environmental Research Laboratory, Environmental 15A. Brown, et al., Water Management in Oil Shale Protection Agency, Cincinnati, Ohio, February 1978. Mining: Volume 1, NTIS report No. PB-276085, Golder 21bid. Associates, Inc., Seattle, Wash., September 1977. ‘T. R. Garland and R. E. Wildung, “Influence of Irri- “Supra No. 5. gation and Weathering Reactions on the Composition of ‘7 Supra No, 6. Percolates from Retorted Oil Shale in Field Lysim- “R. E. Hicks and R. F. Probstein, “Water Manage- eters, ” Proceeding of the Twei~th Oil Shale Symposium ment in Surface and In Situ Oil Shale Processing, ” (J, H. Gary, cd.), Colorado School of Mines, Golden, paper presented at AIChE 87th National Meeting, Colo., August 1979. Boston, Mass,, Aug. 19-22, 1979. 4Rio Blanco Oil Shale Project, Revised Detailed DeveL ‘gWater Purification Associates, A Study of Reverse opment Plan; Tract C-a, submitted to Area Oil Shale Su- Osmosis for Treating Oil Shale Process Condensates pervisor, U.S. Geological Survey, Department of the In- and Excess Mine Drainage Water, quarterly progress terior, May 1977. report, prepared for Laramie Energy Technology ‘E. F. Bates and T, L. Thoem (eds.), PoJJution Control Center, Department of Energy, contract No. DE-AC20- Guidance for Oil Shale Development, revised draft re- 79LC1OO89, September 1979, port, Environmental Protection Agency, Cincinnati, ZOA, L. Hines, The Role of Spent Shale in Oi] SMe Ohio, July 1979. Processing and the Management of Environmental Resi- ‘B. W. Mercer, et al., “Assessment of Control Tech- dues, Department of Energy, report No. TID-28586, nology for Shale Oil Wastewaters, ” paper presented at ERDA-Laramie Energy Research Center, Laramie, Environmental Control Technology Symposium, Depart- Wyo., Apr. 1, 1978. ment of Energy, November 1978. ‘lSupra No, 19. 7N. de Nevers, et al., Analysis of the Environmental “D. J. Goldstein, 1, W. Wei, and R. E. Hicks, “Reuse of Control Technology for Oil Shale Development, Depart- Municipal Wastewater as Makeup to Circulating Cool- ment of Energy, report No. COO/4043-1, February 1978. ing Systems, ” presented at Water Reuse Symposium, ‘Supra No. 4. American Water Works Association, Research Foun- ‘Denver Research Institute, Predicted Costs of Envi- dation, Washington, D. C., Mar. 25-30, 1979, pp. ronmental Controls for A Oil Shale Industry: VoJume 1— 371-397. Also: Industrial Water Engineering, vol. 16, An Engineering Analysis, prepared for the Department No. 4, July 1979, pp. 20-29. of Energy under contract No. EP-78-S-O2-51O7, July 23Water Purification Associates, A Study of Aerobic 1979, Oxidation and AJlied Treatments for Upgrading In Situ ‘OIbid. Retort Waters, contract No, EW-78-C-20-0018 with “G. W. Dawson and B. W, Mercer, “Analysis, Laramie Energy Technology Center, Department of Screening and Evaluation of Control Technology for Energy, quarterly status report, August 1979. Wastewater Generated in Shale Oil Development, ” 24 Supra No. 19. Quarterly Reports, Battelle Pacific Northwest Labora- 25B. Harding, et al., “Study Evaluates Treatments for tory, Richmond, Wash,, January 1977-March 1979. Oil-Shale Retort Water, ” Industrial Wastes, Septem- 12A. B. Hubbard, “Method for Reclaiming Waste- ber/October 1978, pp. 28-33. water From Oil Shale Processing, ” American Chemical 2bIbid. Society, Division of Fuel Chemistry Reprints, vol. 15, No. Z7D. Vernados, I&earch and Development Depart- 1, March-April 1971, pp. 21-25. ment, Amoco Oil Co., Naperville, Ill., personal com- 13 Supra No. 9. munication, August 1979. 26 14A. E. Fry and R. S. Martin, Assessment Of pOllLItiOIl Supra No, 15. Control Costs for Emerging Energy Supply Technologies 2gSupra No. 19. —Subtask 11—Modified In Situ Oil Shale Retorting, De- APPENDIX E Acronyms, Abbreviations, and Glossary

Acronyms and Abbreviations

acre-ft —acre-feet FLPMA —Federal Land Policy and acre-ft/yr —acre-feet per year Management Act of 1976 AGR —aboveground retorting FmHA —Farmers Home Administration API —American Petroleum Institute ‘ FMSHA —Federal Mine Safety and Health AQCR —Air Quality Control Regions Amendments of 1977 ARCO —Atlantic Richfield Co, FRC —Federal Regional Council BACT —best available control technology ft —feet BaP —benzo(a)pyrene ft2 —square feet BAT —best available technology ft3 —cubic feet bbl —barrel(s) FUND —Foundation for Urban and bbl/d —barrels per day Neighborhood Development BLM —Bureau of Land Management, FWPCA —Federal Water Pollution Control Department of the Interior Act of 1972 BOD —biochemical oxygen demand gal —gallon BPT —best practicable control gal/rein —gallons per minute technology currently available gal/ton —gallons per ton Btu —British thermal unit GOREDCO —Gulf Oil Real Estate Development cm —centimeter coo cm/h —centimeters per hour HC —hydrocarbons co —carbon monoxide HEW —Department of Health, Education, co2 —carbon dioxide and Welfare

COS —carbonyl sulfide H2S —hydrogen sulfide CRS —Congressional Research Service IFS —Institute Francais du Petrol CRSP —Colorado River Storage Project JBC —Joint Budget Committee of the Act of 1956 General Assembly (Colorado) CRSS —Colorado River System Simulation mg/l —milligrams per liter Model mg/m3 —micrograms per cubic meter 2 CS2 —carbon disulfide mi —square miles CWACOG —Colorado West Area Council of MIS —modified in situ Governments mm —millimeters CZMA —Coastal Zone Management Act mmho/cm —milliohms per centimeter DDP —detailed development plan (conductivity) DEI —Development Engineering, Inc. MSHA —Mine Safety and Health DLA —Department of Local Affairs Administration (Colorado) —megawatt DNR —Department of Natural Resources µg —microgram 3 (Colorado) µg/m —micrograms per cubic meter DOD —Department of Defense NAAQS —National Ambient Air Quality DOE —Department of Energy Standards DOI —Department of the Interior NAS —National Academy of Sciences DRI —Denver Research Institute NEPA —National Environmental Policy Act EIS —environmental impact statement of 1969

EPA —Environmental Protection Agency NH3 —ammonia ERDA —Energy Research and Development NIOSH —National Institute for Administration Occupational Safety and Health

FAPRS —Federal Assistance Program NOX —nitrogen oxides Retrieval Systems NOSR —Naval Oil Shale Reserve

513 514 ● An Assessment of Oil Shale Technologies

NPC —National Petroleum Council RISE —rubble in situ extraction NPDES —National Pollutant Discharge scf —standard cubic foot Elimination System SCOT —Shell Claus Offgas Treating NSPS —New Source Performance process Standards SEIO —Governor’s Socio-Economic Impact —Nevada, Texas, and Utah Office (Colorado)

O3 —ozone SIP —State implementation plan OCS —Outer Continental Shelf SMCRA —Surface Mining Control and OMB —Office of Management and Budget Reclamation Act of 1977 OSEAP —Oil Shale Environmental Advisory SMR —standardized mortality ratio Panel so, —sulfur dioxide OSHA —Occupational Safety and Health SOHIO —Standard Oil Co. of Ohio Administration SRI —Stanford Research Institute Oxy —Occidental Petroleum TDS —total dissolved solids PADD 2 —The Petroleum Administration for TIS —true in situ Defense District 2 ton/d —tons per day PAHs —polycyclic aromatic hydrocarbons Tosco —The Oil Shale Corp. Pb —lead TSCA —Toxic Substances Control Act of p/m —parts per million 1976 POM —polycyclic organic matter UBCOG —Uintah Basin Council of PSD —prevention of significant Governments deterioration USBM —U.S. Bureau of Mines QDA —Quality Development Associates USBR —U.S. Bureau of Reclamation Quad —1 quadrillion = 1015 Btu USFWS —U.S. Fish and Wildlife Service RARE II —Roadless Area Review and USGS —U.S. Geological Survey Evaluation (Forest Service) USPHS —U.S. Public Health Service RCRA —Resource Conservation and WPA —Water Purification Associates Recovery Act of 1970 WPRS —Water and Power Resources R&D —research and development Service

Adit: A nearly horizontal opening to a mine. Calcite: The mineral calcium carbonate, found in Aquifer: An underground formation containing nature in the form of limestone, marble, or water. chalk. Aromatic hydrocarbon: A compound of carbon Catalytic cracking: A process of breaking down and hydrogen characterized by a ring of six petroleum hydrocarbons by heating them in the carbon atoms, e.g., benzene. presence of a catalyst. The products are hydro- Best available control technology (BACT): The carbons of lower molecular weight, having most advanced control technology that can be lower boiling points, e.g., gasoline. used for new sources of pollution. Required for Coking: One of the processes used to upgrade nonattainment regions (where air pollution pre- shale oil and improve its transportation proper- sents a danger to the public health) by the ties. The oil is thermally decomposed at high Clean Air Act as amended in 1977. temperatures (900° to 980° F or 480° to 525° C) Biochemical oxygen demand: A chemical measure forming coke as a solid product. of the power of an effluent to deoxygenate Criteria pollutants: Under the Clean Air Act, the water. reduction and prevention of air pollution is reg- Bitumen: The smaller (about 10 percent) soluble, ulated by measuring five criteria pollutants: organic component of oil shale. particulate, sulfur oxides, carbon monoxide, Breakeven price: The constant price at which nitrogen dioxide, and photochemical oxidants. shale oil syncrude would just earn its minimum National Ambient Air Quality Standards were rate of return. developed for six pollutants associated with the Appendix E–Acronyms, Abbreviations, and Glossary • 515

criteria pollutants. Sulfur oxides are measured Fugitive dust: Particulate matter discharged to by sulfur dioxide and photochemical oxidants the atmosphere in an unconfined flow stream. are measured by ozone and hydrocarbons, Gas oil: A liquid petroleum distillate with a viscos- Crude short: The condition when a company has ity and boiling range between kerosene and lu- limited or inadequate access to crude petro- bricating oil (450° to 500° F or 230° to 260° C). leum. Ground water aquifer: Water contained under- Dawsonite: The mineral, dihydroxy sodium alumi- ground in the interstices of soil and rock, ob- num carbonate. It is a potential source of alu- tainable through wells or springs. mina, which can be converted to aluminum. Halite: The natural mineral form of sodium Deposit: A natural accumulation, e.g., of coal, chloride (NaCl). iron ore, or oil shale. High-Btu gas: Gas with a high heating value, e.g., Deposit dewatering: The removal of ground water pure butane has a heating value of 3,200 from an oil shale deposit. Btu/ft 3. Distillates: The liquid products condensed from Hydrocarbons: Organic compounds containing vapor during distillation (as of petroleum), only carbon and hydrogen. Light distillates contain the lowest boiling Hydrocracking: The breaking apart of relatively constituents of the petroleum, from which gas- heavy petroleum hydrocarbons into smaller, oline is produced. lighter molecules by means of heat in the Middle distillates contain higher concentra- presence of hydrogen and using special tions of the high boiling constituents, from catalysts. which diesel and jet fuels are produced. Hydrologic basin: The entire area of land drained Heavy distillates contain higher concentra- by a river and its tributaries. tions of the high boiling constituents, from Hydrotreating: The hydrogenation of crude shale which lubricating and residual oils are pro- oil to convert it to -synthetic crude oil (syn- duced. crude). Distillation: A separation process in which a sub- Kerogen: The organic oil-yielding material pres- stance is vaporized, and the vapor collected ent in oil shales. It is not a definite compound after condensation as a liquid. but a complex mixture varying from one shale Diversion: A channel constructed to divert water to another, and is only slightly soluble in or- from one source or body of water to another. dinary organic solvents, Interbasis diversion-Moving water from Low-Btu gas: Gas with a relatively low heating one major hydrologic basin to another. value (about 100 Btu/ft3), e.g., producer gas, Intrabasin diversion—The redistribution of Locatable minerals: Minerals on public land that water within a major hydrologic basin. can be transferred to private ownership by the Dolomite rock: Similar to limestone but composed process of staking claims and filing for patents. mainly of the mineral, calcium magnesium car- Marlstone: A hardened mixture of dolomite and

bonate (Ca Mg (CO3)2). calcium carbonate. Electrostatic precipitator: A device that uses an Middle distillate cracking and reforming: Break- induced electrical charge to recover fine parti- ing down and converting straight chain petro- cles from a flowing gas stream. leum hydrocarbons into cyclic and aromatic hy- Environmental impact statement (EIS): The Na- drocarbons, by means of heat, pressure, and tional Policy Act of 1969 requires that an en- catalysts (usually in the presence of hydrogen). vironmental impact statement be prepared for Used to produce fuels with high octane rating “major Federal actions significantly affecting from lower grade products. the quality of the human environment.” Mining: Fischer assay: Small samples of crushed oil shale Block caving—Sections of the area being are heated to 932° F (500° C) under carefully mined are undercut and then allowed to cave controlled conditions. The oil yield by this in, thus crushing the material being mined. method is the standard measure of oil shale Continuous—A machine cuts and loads ore quality. from a mine face in a continuous operation, Fracturing: Breaking up a deposit by means of without the use of drills and explosives. chemical explosives, electricity, or injecting Long-wall—The ore seam is removed in one high-pressure air and water to increase its per- operation along a working face that maybe sev- meability to fluid flow. eral hundred yards long. The mine roof col- 516 • An Assessment of Oil Shale Technologies

lapses as the working face advances through collected runoff, e.g., a mining operation, con- the ore body. The technique is commonly used struction site, or agricultural area. for coal mining, especially in Great Britain. Olefin hydrocarbons: Unsaturated (lower ratio of Open pit—The overburden is drilled and hydrogen to carbon) compounds of carbon and blasted loose over a large area and removed to hydrogen having at least one double bond. expose the oil shale beds. These are then Onstream factor: The fraction of the time that a drilled and blasted. plant could be expected to operate at design ca- Room-and-pillar-Some shale is removed to pacity. form large rooms, and some is left in place, as Organic compounds: The compounds of carbon. pillars, to support the mine roof. These fall roughly into two classes: compounds Solution—The injection of fluids into the for- containing only carbon and hydrogen (hydro- mation to dissolve soluble salts from among the carbons), and compounds in which one or more oil shale layers, thereby creating a honeycomb hydrogen atoms have been replaced by other pattern of voids. elements or groups of elements (heteroatomic Strip—The overburden and deposit are re- compounds). moved with a dragline—a massive type of Overburden: The material overlying a deposit scraper shovel. that must be removed before surface mining. Subsidence—The mine roof is allowed to col- Paraffin hydrocarbons: Saturated compounds of lapse into the working area after the ore is carbon and hydrogen having only single bonds. removed. Particulate: Minute separate airborne particles, Mining bench: A shelf or ledge made in a mine one of the criteria pollutants under the Clean tunnel or working when an upper section is cut Air Act, back. Perfection of water right decree: Meeting all the Modular retort: The smallest unit that would be requirements under applicable law to establish used in commercial practice. Its capacity legal rights to the water—implies not only varies with the developer. ownership but also actual use. Molecular weights: The relative mass of a mole- pH: A means of expressing the acidity or alkalini- cule as compared with that of an atom of ty of a solution. At normal temperatures, pure hydrogen. It is calculated by adding up the water has a pH of about 7 (neutral); the pH of a weights of the molecule’s constituent atoms. strong acid is about 1 and that of a strong base Mucking: Removal material broken up in the min- about 14. ing process. Photochemical reactions: Chemical reactions in- Nahcolite: A mineral chemically identical to com- duced in the atmosphere by ultraviolet radia- mercial baking soda (sodium bicarbonate). tion from the Sun. New Source Performance Standards (NSPS): The Phreatophyte: A deep-rooted plant that obtains Clean Air Act requires that the Environmental water from the water table or the layer of soil Protection Agency set standards of perform- just above it. ance for major new potential sources of pollu- Placer deposit: A deposit of alluvial material tion, and that such facilities use the most ad- found along and in riverbanks, streambanks, vanced technology available for pollution con- and in beach sands. trol. Polycyclic organic compounds: A compound Nonattainment area: The air in the region does whose molecular structure contains two or not satisfy the National Ambient Air Quality more rings (usually fused) that are mostly con- Standards as established under the require- structed of carbon atoms (e.g., anthracene). ments of the Clean Air Act. Pour point: The lowest temperature at which a Nondegradation area: The air in the region is liquid will flow. cleaner than that required by the National Am- Prevention of significant deterioration (PSD): A bient Air Quality Standards. statutory program of the Clean Air Act aimed Nonmethane hydrocarbons: All the organic com- at preserving the existing high air quality in pounds of carbon and hydrogen that are not those areas having the cleanest air (nondegra- straight chain, saturated (no more hydrogen dation regions). can be added) molecules in which the carbon Pyrolysis: The breaking down of complex mate- atoms are joined to each other by single bonds. rials into simpler units by means of heat. Nonpoint source: A site from which there is un- Radionuclide: A radioactive atom. Appendix E–Acronyms, Abbreviations, and Glossary • 517

RARE II: The Roadless Area Review and Evalua- and deposited in layers by water, wind, or ice tion process being undertaken by the Forest (e.g., sandstone, limestone, shale.) Service for all potential wilderness areas in the Shale oil syncrude: A synthetic crude oil pro- national forest system. duced by adding hydrogen to crude shale oil, Refluxing: Distillation in which the liquid is con- comparable with the best grades of conven- densed with the rising vapor in a fractionating tional crude. column. Spent shale: The retorted residual material after Reserve: A resource that can be extracted from the oil and gas products are removed. Its prop- the deposit and processed to yield products erties vary with the type of retorting procedure that can be marketed at a profit. used; indirectly heated retorts product a car- Resource: A naturally occurring substance with bonaceous spent shale, while directly heated properties that can be put to use. retorts produce a material essentially stripped Retort: The vessel or container in which the oil of carbon. shale is pyrolyzed to recover the shale oil. Spot market price: The nonposted price for a bar- Retort plant: rel of oil, Commercial scale—A commercial-size oil Syncrude: Synthetic crude oil, produced from any shale facility would use several modular resource other than conventional petroleum. torts in parallel to obtain the desired produc- Trona: A hydrated mixture of sodium carbonate tion rate, and sodium bicarbonate. It is a source of soda Pilot-plant scale—About one-hundredth of ash for glass production. the capacity of a commercial scale module. Upgrading: The treatment of crude shale oil to im- Pioneer commercial scale—Would contain prove it to a transportable refinery feedstock, several commercial-size modules. e.g., hydrotreating. Semiworks scale—About one-tenth of the ca- Virgin flow: The flow of a river that would occur pacity of commercial-size. in the absence of human-related activities. In Retorting: The raw oil shale is heated to pyrolysis this assessment most of the analysis of water temperatures (about 1,000° F (540° C)) to obtain availability refers to the average flow between crude shale oil. 1930-74, because of its common use in other Above-ground (AGR)—In this process, the re- water resources analyses. torting vessels are essentially large, steel cylin- Viscosity: A measure of a liquid’s resistance to drical or cone-shaped containers lined with re- flow. fractory brick. The retorting systems, which Water rights: differ widely with respect to technical and op- Absolute—The right created when a holder erating characteristics, fall into four classes of a conditional right perfects that right by ac- based on the mode of transferring heat through tually diverting the water and applying it to a the oil shale: 1) by conduction through the re- beneficial use. tort wall, 2) by flowing gases generated from Conditional—The right obtained by filing for the carbonaceous material and hot gases cre- a conditional decree from the State water ated in the retort, 3) by gases heated outside courts, and then proceeding diligently towards the retort, and 4) by mixing hot solid particles the actual use of the water, with the oil shale. Diversion—Permits the diversion of water Modified in situ (MIS)—In this process, a por- from a stream followed by its immediate appli- tion of the shale deposit is mined out, and the cation. rest is fractured with explosives or by other Junior—The prior appropriation doctrine for means to create a highly permeable zone water rights is based on the principle “first-in- through which hot fluids can be circulated. time, first-in-right. ” In times of shortages, True in situ (TIS)—In this process, the shale rights that are junior in terms of the initiation is left underground and is heated by injecting date are curtailed to assure water supplies to hot fluids. users with more senior rights. Rubbling: Shattering by explosives of a portion of Senior—The more senior (older) the water an oil shale deposit so that it can be retorted right, the higher its priority for the use of lim- underground. A modified in situ process. ited resources. Sedimentary rocks: These are derived from the Storage—Permits the impoundment of water disintegration and weathering of older rocks, for later application.

o ERRATA - AN ASSESSMENT OF OIL SHALE TECHNOLOGIES

1. The shading on Figure 2, page 7 is incorrect: SEE INSTEAD FIGURE 13, PAGE 90.

2. Issue 4, p. 32: The total estimated cost of pollution control should be 2.4 to 6.0 cents/gal.

3. Figure 51, p. 187: increases from environmental costs should fall lower on the graph (about 2 x 1971 estimate).

Site 11/line 11, under —statu —s should read: Initial environmental, health and safety tests underway.

5. Page 136, first column, lines 6 and 7, should read: Multi Mineral has begun use of an 8-ft-diameter shaft. . . .