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VOLUME 19 - NUMBER 4 DECEMBER 1982

QUARTERLY

Tell Ertl Repository Arihur Lakes Library 't?c!o School of Mines

ROCKY MOUNTAIN DIVISION 0 THE PACE COMPANY CONSULTANTS & ENGINEERS, INC.

Peg. U.S. Pat. OFF. Pace Synthetic Fuels Report is published by the Rocky Mountain Division of the Pace Company Consultants & Engineers, Inc. as a multi-client service and is intended for the sole use of the clients or organizations affiliated with clients by virtue of a relationship equivalent to 51 percent or greater ownership. Pace Synthetic Fuels Report is protected by the copyright laws of the United States; reproduction of any part of the publication requires the express permission of the Rocky Mountain Division of the Pace Company Consultants & Engineers, Inc. The Rocky Mountain Division has provided energy consulting and engineering services since 1955. The Division's experience includes resource evaluation, process development and design, systems planning, marketing studies, licensor comparisons, environmental planning, and economic analysis. The Synthetic Fuels Analysis group prepares a variety of periodic and other reports analyzing developments in the energy field.

ROCKY MOUNTAIN DIVISION THE PACE COMPANY CONSULTANTS & ENGINEERS, INC.

GENERL MANAGER JERRY E. SINOR

MANAGING EDITORS AGNES K. OUBBERLY RONALD L. GIST

CONTRIBUTING EDITORS TREVOR R. ELLIS MICHAEL L. GREGG JOE J. LETO GEORGE N. ONARA RHONOA J. PAXSON PAUL 0. ROLNIAK

PRODUCTION STAFF SHIRLEY A. JOHNSON EUGENE L. JOJOLA REBECCA N. PRYOR WELANA WENOORFF

650 S. CHERRY ST. DENVER, COLORADO B0222-1883 (303} 321-3919 TELEX: 45-0577 PRMO DVR

MICROFICHE COPIES AVAILABLE CONTACT ANY PSFR STAFF MEMBER CONTENTS

HIGHLIGHTS ...... A-i

I. GENERAL

ENERGY POLICY AND FORECASTS National Energy Policy Needed ...... 1-1 Synfuels Contributes Little In "World Energy Outlook ...... 1-4 LEA Presents Policy and Programs of Member Countries ...... 1-9 OTA Report Stresses Need For Major Effort To Reduce Oil Imports ...... 1-10 RESOURCES Applications of Geostatistics To Energy Minerals ...... 115 Federal Land Energy Resource Data Published ...... 1-17 INTERNATIONAL Japanese Involvement In Synthetic Fuels Significant ...... biB World Bank Sees Methanol As Opportunity For Developing Countries ...... 1-19 GOVERNMENT Synthetic Fuels Corporation Announces Plan To Assist Three Projects ...... 1-22 Synthetic Fuels Corporation Outreach Initiative Described ...... 1-23 Synthetic Fuels Corporation Elects Officers ...... 1-23 Energy Preparedness Act Mandates Description Of Presidential Authority In Energy Crisis ...... 1-23 Congressional Research Service Report Looks At Synfuels Industry Problems ...... 1-25 Hodel Confirmed As New Secretary Of The Department Of Energy ...... 1-25 GAO Report Faults DOE For Not Performing According to Statute ...... 1-25 ECONOMICS Change In Methods Of Costing Synfuels Plants Proposed ...... 1-28 ENVIRONMENT DOE's Health Effects Research and Analysis Program Looks At Synfuels ...... 1-29 Clean Air Act Waivers Granted In North Dakota ...... b29 RECENT GENERAL PUBLICATIONS ...... 1-33 COMING EVENTS ...... 1-34

II. OIL SHALE

PROJECT ACTIVITIES Paraho-Ute Project Is Described ...... 2-1 Board Approves Colony Reclamation Plan ...... 2-4 Rundle Oil Shale Tested By TOSCO ...... 2-5 CORPORATION Paraho Development Corporation Relocates Its Main Offices ...... 28 TOSCO Forms A New Oil Shale Group ...... 2-8 GOVERNMENT

SVC Approves Draft Targeted Solicitation For Oil Shale 2-9 DOD Contracts Geokinetics To Refine Shale Oil 2-9 DOE Awards Contracts For Eastern Oil Shale Processes..... 2-10 ENERGY POLICY Energy Interaction Council Discusses Oil Shale ...... 2-12

ECONOMICS Comparative Economics Of Colony And Union Oil Shale Projects' 2-13 TECHNOLOGY

Retorting Oil Shale By Electrical Resistive Heating 2-19 2-25 Continuous Oil Shale Miner Described Grouting Oil Shale Mines With Spent Shale ...... 2-25 Index To Oil Shale Symposia Proceedings Issued 2-29 INTERNATIONAL

Yaamba Joint Venture Signs Contracts For Oil Shale Feasibility Study 2-31 ENVIRONMENTAL

Draft Report Summmarizes Results Of Cumulative Impact Study 2-32

NOSR #1 and #3 - Final Programmatic EIS Issued ...... 2-35 AMC/API Comment On Prototype Oil Shale Leasing DEIS 2-36 Oil Shale Environmental Advisory Panel Charter Is Renewed 2-37

WATER

Water Applications Related To Oil Shale 2-38 RESOURCES Oak Ridge Assesses Chattanooga Shale ...... 2-39 BLM Examines ERTL Claims ...... 2-42 SOCIOECONOMIC Impact Funds Requested By Colorado Local Governments. 2-47

STATUS OF OIL SHALE PROJECTS 2-48 RECENT OIL SHALE PUBLICATIONS ...... 2-56 III. OIL SANDS PROJECT ACTIVITIES

GNC, Chevron Proceed With Tar Sand Project 3-1 Cedar Camp Tar Sand Project Is Proposed 3-4 Enercor Rainbow Project Outlined In PDEIS 3-7 ENPEX Project Described ...... 3-13 CORPORATION

Suncor To Increase Tar Sands Reserves 3-15 GOVERNMENT

U.S. and Canada Sign Tar Sands Agreements 3-16 Final Operating Regulations For Tar Sands Are Issued 3-16

II ENERGY POLICIES Tar Sands Mining Evaluated ...... 3-18 ECONOMICS Results of Natomas Feasibility Study Are Discussed ...... 3-22 TECHNOLOGY Oleophilie Sieve Process Tar Sands Outlined ...... 3-27 RESOURCES Western Kentucky Tar Sands ...... 333 STATUS OF OIL SANDS PROJECTS ...... 3-36 RECENT OIL SANDS PUBLICATIONS ...... 3-55

IV. COAL

PROJECT ACTIVITIES Status Of Coal Projects Applying To The SFC For Assistance ...... 4-1 Ashland Withdraws From The Breckinridge Project ...... 41 Hampshire Energy Project Postponed ...... 4-1 Activities At Sasol One, Two, and Three ...... 4-2 ANR Discussing A Second Phase Of The Great Plains Project ...... 4-7 CORPORATION C-E Lummus Active With Two Coal Conversion Processes ...... 4-9 GOVERNMENT GAO Analyzes Government Involvement In High-Btu Gasification ...... 4-10 The New Federal Coal Leasing Regulations ...... 4-11 ENERGY POLICIES Second Congressional Hearing On The Use Of Methanol As An Alternative To Gasoline ...... 4-14 ECONOMICS - Costs of Producing Methanol And Medium-Btu Gas By UCG ...... 4-19 Combined Cycle Plant Economics Using Air and Oxygen Blown Gasifiers ...... 4-26 TECHNOLOGY Use of Battelle Treated Coal To Produce Low-Sulfur Fuel Gas ...... 4-34 Status of Direct Methanation Research At GRI ...... 4-38 Coal Liquefaction Using Basic Nitrogen Heterocyclic Solvents ...... 4-42 INTERNATIONAL Coal Conversion Activities In West Germany ...... 4-45 ENVIRONMENT Wastewater Treatment For The Great Plains Project ...... 4-53

/ Ill RESOURCES

001 Bans Coal Leasing To Railroad-Affiliated Energy Firms 4-62 Powder River Basin Leasing Activities ...... 4-62 Green River-Hams Fork Region Leasing Activities. 4-64

STATUS OF COAL PROJECTS ......

RECENT COAL PUBLICATIONS 4-118

iv V. APPENDIX

Energy Emegeney Preparedness Act of 1982 ...... 1 SFC Draft Targeted Solicitation for Oil Shale Projects ...... 5-5

Opinion of the DOl Solicitor Concerning Leasing of Federal Coal to Railroads 5-31 Glossary of Terms Relative to Geostatistics ...... 5-36 HIGHLIGHTS• General Accounting Office Suggests Net Energy Assessments Be Used By DOE The General Accounting Office (GAO) released a report which recommends that the Department of Energy (DOE) improve its data base and perform a net energy analysis before funding projects. According to GAO: "decision making that spends scarce taxpayer resources on the basis of inconsistent, unvalidated, and low- quality data constitutes an inefficient management of public statutory requirements of Public Law 93-571 and title II of Public Law 96-294 and DOE's explicit promise to the House Committee on Government Operations to implement NEA." A review of GAO's report including methodology for a net energy analysis is on page 1-25. SF0 Selects Three Projects For Support At their Board meeting in December, the Synthetic Fuels Corporation announced that three projects from Phase II of the Second Solicitation had progressed to the point that the Corporation will sign letters of intent with the projects before the January board meeting. These three are: First Colony peat-to-methanol project in North Carolina; the Santa Rosa oil sands project in New Mexico; and the Calsyn heavy oil conversion project in California. The major provisions of the letters of intent proposed for the three projects are discussed in the General Section on page 1-22. Two Coal-Based Projects Suffer Setbacks Although three projects were selected for SFC support, two coal-based projects that applied to the SFC for assistance have experienced major problems. On November 22, 1982, Ashland Oil announced it was withdrawing from the Breckin- ridge Project in Kentucky. Further information on Ashland's decision can be found in the article beginning on page 4-1. In other developments, the four remaining sponsors of the proposed Hampshire Energy Project near Gillette, Wyoming, announced on December 8, 1982, that they were postponing the start of construction of the project. As described on pages 4-1 to 4-2, the project had recently achieved several significant milestones, but had been unable to attract additional equity sponsors to replace Standard Oil Company of Ohio. National Energy Plan Necessary For Economic Recovery And Security Our present recession is due in great measure to our dependence on imported oil. The article on Page 1-1 gives suggestions to improve both our economy and energy security. OTA Also Stresses Need For Government Energy Policy The Office of Technology Assessment (OTA) recently released a report to assist Congress in addressing several options that could reduce our dependence on imported oil. One important point presented in the report is that the market place cannot be relied upon to decrease our dependence on imported oil and that the government must become involved. The report is discussed on page 1-10.

SYNTHETIC FUELS REPORT, DECEMBER 1982 A-i HIGHLIGHTS

World Energy Outlook Sees Synfuels Contributing Little To World Energy Supply

In the second "World Energy Outlook" the amount of energy that will be derived from synthetic fuels in the near future is judged to be minimal. The report sees the present oil glut as short term with a tight oil market developing in the late 1980's. A discussion of the study is on page 1-4.

LEA Members Urged To Continue Synfuels Development

In their annual report concerning member's energy policies and programs, the International Energy Agency warns that in the past year members have not decreased their oil dependence by any signficant amount. The report, reviewed on page 1-9, concludes that it is important to pursue synthetic fuels and other unconventional energy development. Methanol Viewed As An Opportunity For Developing Countries

Many developing countries of the world have significant amounts of natural gas that could economically be used for methanol production. The World Bank has analyzed this potential and forecasted demand for methanol to 1990. A review of the World Bank's forecast is also give in the article beginning on page 1-19. Congressional Hearing On The Use Of Methanol As A Fuel Another study concerning methanol is expected following a hearing by the U.S. House of Representatives Subcommittee on Fossil and Synthetic Fuels on Septem- ber 24, 1982. As summarized in the article starting on page 4-14, five witnesses from industry and the government presented testimony and also participated in discussions primarily concerning the use of methanol in blends with gasoline or as a neat fuel.

Energy Emergency Preparedness Is Analyzed

The Energy Emergency Preparedness Act was signed into law in August. The Act mandates that the President submit a memorandum of law to Congress describing the nature and extent of authorities available to the President under existing law to respond to an energy supply interruption. A brief analysis of the memo is given on page 1-23. The Energy Emergency Preparedness Act (PL 97-229) is contained in the Appendix. Congressional Research Service Suggests Positive Action For Synfuels Program.

A Congressional Research Service report released in July proposes legislation and administrative action necessary to promote a viable synfuels industry. Specific suggestions from the report are summarized in the article on page 1-25.

Japanese Synfuels Commitment Stronger Than In The U.S.

In a recent visit to Japan, Pace representatives made contacts with representatives of Japanese companies and agencies involved in synthetic fuels. Pace

A-2 SYNTHETIC FUELS REPORT, DECEMBER 1982 HIGHLIGHTS personnel believe that if the Japanese continue their current program, the U.S. may be importing Japanese synfuels technology before the end of the century. An overview of Japanese policy and programs is given on page 1-18. Costs Of Synfuels Plants Reappraised Reasons for the high costs of synthetic fuels plants are given in a paper by W. A. Samuel of Fluor. The main points of his thesis as well as suggestions that would encourage investments in synfuels plants are presented on page 1-28. Industry Should Comment On Oil Shale And Coal Liquefaction Health And Environmental Documents The Health and Environmental Risk Analysis Program of the Department of Energy is in the process of defining various types of health and environmental uncertainties asssociated with emerging energy technologies. A detailed description of the program is on page 1-29. Two draft documents affecting synfuels have been prepared for oil shale and direct coal liquefaction and are available for comments from the DOE. Geostatistics Applicable For Evaluating Energy Minerals Pace and Geostat Systems International Inc. have been studying the application of geostatistics to energy minerals. The first of a series of articles prepared for Pace by GSH begins on page 1-15. Federal Land Energy Resources Described The U.S. Department of Interior has published a report, "Energy Resources on Federally Administered Lands." The documents contain statistical production data and reserves for energy resources and compares production from Federal land with that from the total U.S. The report is described on page 1-17 of this issue. Paraho-Ute Project Is Described As a supplement to a regional Environmental Impact Statement, Paraho Develop- ment Corporation recently prepared a technical report describing the Paraho-Ute Project. This report contains technical, economic, and environmental descriptions of the project. See page 2-1 for a summary. Colony Reclamation Plan Is Approved The Interim Site Plan prepared by the Exxon Company U.S.A. for the Colony Project has been approved by the Colorado Department of Natural Resources. As described in the article beginning on page 2-4, the plan allows Exxon to reactivate construction of the project before 1985 without further formal action by the State.

SYNTHETIC FUELS REPORT A-3 HIGHLIGHTS

SEC Approves Draft Targeted Solicitation For Oil Shale

On December 20, 1982, the U.S. Synthetic Fuels Corporation (SFC) approved a draft of a targeted solicitation for western oil shale. The draft allows project sponsors to request price supports of up to $67 per barrel and loan guarantees of up to $1.6 billion. The SFC plans to select the winning bidder(s) by July 1, 1983. A summary of the draft solicitation begins on page 2-9 and the entire draft is presented on pages 5-5 to 5-30 of the Appendix. DOE Awards Contracts For Eastern Oil Shale Processes

The U.S. Department of Energy (DOE) recently awarded contracts totaling approximately $1 million to three firms to test processes specifically designed for Eastern oil shales. See page 2-10 for a brief description of the three processes to be tested by Rockwell, Battelle, and Gulf. DOD Contracts Geokinetics To Refine Shale Oil

The U.S. Department of Defense (DOD) announced it had signed a contract with Geokinetics Inc. to refine approximately 80,000 barrels of shale oil into military jet fuel. The shale oil will be refined at the Woods Cross Refinery operated by Caribou Four Corners, Inc. The article beginning on page 2-9 provides additional details concerning the contract. Pace Evaluates Oil Shale Economics Pace has conducted an independent analysis of the economics of two oil shale facilities. Using publicly-available information for Exxon's Colony Project and for Union's Parachute Creek Project, several different economic cases were studied to determine the threshold price for shale oil produced from both facilities. The results of these evaluations are presented in the article beginning on page 2-13.

Retorting Oil Shale By Electrical Resistive Heating Is Described Sandia National Laboratories has completed a preliminary theoretical study of the use of electrical resistive heating to retort oil shale. Three mathematical models and an energy balance for the proposed process were developed during the study. As described in the article beginning on page 2-19, additional studies and testing are needed to further develop the concept. Continuous Oil Shale Miner Described A final report for the U.S. Department of Energy by John C. Haspert presents the design of a prototype continuous oil shale underground raining machine. The author claims the machine is capable of increasing productivity above that of conventional room and pillar oil shale mining by a factor of 4 to 7. The description of the machine begins on page 2-24 of this issue.

A-4 SYNTHETIC FUELS REPORT, DECEMBER 1982 HIGHLIGHTS Grouting Of Oil Shale Mines Is Described Rio Blanco Oil Shale Company recently completed tests that evaluated the use of spent oil shale to grout oil shale mines. The tests, described in the article beginning on page 2-25, determined that an acceptable grout can be produced from spent shale. Yaamba Joint Venture Funds Study Of Oil Shale Project The partners of the Yaamba Joint Venture have initiated a feasibility study for development of its oil shale project. The study will determine the environmental, technical, and economic feasibility of a commercial project proposed for central Queensland, Australia. See page 2-31 for additional details of the study. AMC And API Comment On The Prototype Oil Shale Leasing DEIS The American Mining Congress (AMC) and the American Petroleum Institute (API) have formally responded to the Draft Environmental Impact Statement (DEIS) concerning the proposed prototype oil shale leasing program. As described on page 2-36, the AMC and API found the DEIS to be seriously deficient in regard to the analyses of air quality, hydrogen, and socioeconomics. Cumulative Impacts Of Energy Development Are Described In Draft Report The Colorado Department of Health has issued its draft report summarizing the cumulative effects of energy development on the environment in northwest Colorado. The article beginning on page 2-32 summarizes the methodology, conclusions, and recommendations of the study. NOSR #1 And #3- Final Programmatic EIS Issued

As summarized on page 2-35, the Final Programmatic EIS for the Naval Oil Shale Reserves in Colorado has been issued. The EIS evaluated and compared the impacts of eight liquid fuel alternatives and five different modes of operation. The EIS conclusion is that the present energy situation does not require development of NOSR #1 and that a "no action" alternative is the preferred alternative. Oak Ridge Assesses Chattanooga Shale Oak Ridge National Laboratory has completed an assessment of the oil shale resource of the Chattanooga Shale. The assessment evaluated a commercial oil shale mining and processing plant operating at 100,000 tons per day. The resource base, technology (mining and processing), and economics are described beginning on page 2-39. ELM Examines Ertl Claims The Bureau of Land Management (ELM) has let a contract to Energy Minerals Technical Assessment of Golden, Colorado for the examination of the unpatented Ertl claims. The examination is required by mining law to determine the validity

SYNTHETIC FUELS REPORT, DECEMBER 1982 A-S HIGHLIGHTS of the claims. Phillips Petroleum leased the unpatented claims in 1980. A discussion of the claims examination and other relevant issues begins on page 2- 42. ENERCOR Rainbow Project Outlined In PDEIS A preliminary draft environmental impact statement (PDEIS) has been issued for the ENERCOR tar sands project in the North P.R. Springs, Utah tar sands deposit. The project calls for a 2,000 BPD syncrude modular plant expandable to 5,000 BPD. The process involves a surface mine, hot water and soda ash extraction plant, and a delayed coking unit. Further details on the project and the emissions are given in the article on page 3-7. ENPEX Project Described ENPEX evaluated various combinations of in situ tar sands producton and on-site upgrading. ENPEX has 2,200 acres of leases adjacent to the property where Conoco conducted its Fracture Assisted Steamflood Technology tests. ENPEX will combine the same production technology integrated with H-Oil hydro- converson of the product tar. Further details are given on page 3-13. Economics Presented For Natomas Tar Sands Process The Department of Energy partially funded a feasibility study on the Natomas Tar Sands Process. The study found that the raw bitumen requires significant upgrading. Project economic viability is sensitive to capital requirements and product prices. The economic analysis of the study is reviewed in an article on page 3-22.

1f$r And Canada To Conduct Joint Tar Sands Program The U.S. and Canada signed two agreements in September for cooperation in research and development of tar sands and heavy oil. A description of the agreement is on page 3-16. One agreement provides guidance for dissemination of information while the objective of the other is to conduct a coordinated laboratory program to evaluate in situ steam processes. Mono Power And Enercor Cedar Camp Project Is Described Mono Power and Enercor submitted the Cedar Camp project to be included in the Uinta Basin Regional EIS. The two firms hold tar sand bearing oil and gas leases in the P.R. Springs deposit. A description of the conceptual project is on page 3- 4. GNC And Standard OR Of California Will Develop Utah Tar Sands GNC's tar sands project was approached as a large scale mining project. Background of the project and description of the process is given on page 3-1.

A-6 SYNTHETIC FUELS REPORT, DECEMBER 1982 HIGHLIGHTS Suncor To Spend $700 Million On Tar Sands Operations While many firms have scaled back synfuels expenditures, Suncor plans to spend $700 million on their tar sands operation. A brief description of Suncor's plans is on page 3-15. Final Operating Regulations For Tar Sands Issued The Department of Interior issued the final regulations to facilitate operations for tar sand development under the Combined Hydrocarbon Leasing Act in September. These regulations are discussed on page 3-16. Western Kentucky Tar Sands Described A paper by Martin C. Noger of the Kentucky Geological Survey, reporting on a study of the tar sands of western Kentucky, is described on page 3-33. The location and characteristics of identified occurrences of surface and subsurface deposits are presented. Tar Sands Mining Evaluated The factors involved in assessing the mineability of U.S. tar sands were evaluated in a paper by David Pike, and Randall Metz. Resources in Alabama, Missouri, New Mexico and Utah were considered for three types of mining technology - surface, underground and mine-assisted in situ. Estimated capital costs and operating costs are given in the article on page 3-18. Oleophilic Sieve Process For Tar Sands Outlined Kruger Research and Development Ltd. is developing an oleophilic separation process for recovering bitumen from tar sands and tar sands tailings. The process is based on the attraction of bitumen for the coating on a wire screen. Economics are attractive for integrating the oleophilic process into a hot water extraction plant especially for lower grades of tar sands resource. This article is on page 3- 27. Sasol One, Two, And Three Activities Are Described A significant milestone was achieved on May 10, 1982, when the Sasol Three facility began producing synthetic oil. Another major activity involves the construction and operation of a commercial-scale Westinghouse gasifier. See pages 4-2 to 4-7 for a more complete description of the activities at the Sasol plants. GAO Analyzes Government Involvement In High-Stu Coal Gasification The U.S. General Accounting Office (GAO) recently issued a report summarizing its analysis of government involvement in both research and development and in commercialization of high-BTU coal gasification technologies. In the report, the GAO concludes that government support of research and development projects

SYNTHETIC FUELS REPORT, DECEMBER 1982 A-7 HIGHLIGHTS should be more focused and that a long-range plan is needed. A summary of the GAO report begins on page 4-10. New Federal Coal Leasing Regulations Are Issued On August 30, 1982, the new Federal Coal Leasing Regulations were issued. The new regulations should significantly increase the availability of Federal coal reserves for leasing and should remove some requirements considered to be burdensome by the coal industry. The article beginning on page 4-11 briefly reviews the major changes in the new regulations. Costs of Producing Methanol and Medium-Btu Gas By UCG Jacobs Engineering Group has developed preliminary capital and operating costs for the production of methanol or medium-BTU gas via underground coal gasification (UCG). The study results indicate that a UCG facility can produce methanol or gas at a cost that is competitive to aboveground coal gasification processes. A description of the UCG facility and the cost estimates begins on page 4-19. Economics Of Air- And Oxygen-Blown Coal Gasifiers For Combined Cycle Plants Westinghouse Electric Corporation has evaluated the economics of air- and oxygen-blown coal gasifiers for combined cycle power plants. As described in the article beginning on page 4-26, the study results indicate that an air-blown plant is less expensive, more efficient, and less complex than an oxygen-blown plant. Use Of Battelle Treated Coal To Produce Fuel Gas Is Evaluated Researchers at Battelle National Laboratories have developed a method of treating coal with calcium compounds to render the coal non-agglomerating, highly reactive, resistant to slagging, and conditioned for sulfur capture. Based on laboratory tests, gasification of BTC is economically competitive with natural gas, fuel oil, and gasification of low-sulfur coal. See page 4-34 for a more complete description of the process and the economic analysis. Direct Methanation Research At GRI Is Described The Gas Research Institute (CR1) has been involved in a program to develop new types of methanation catalysts. This research has led to a new family of catalysts that can promote the conversion of coal-derived synthesis gas to substitute natural gas without requiring costly gas clean-up processing. As described in the article beginning on page 4-38, CR1 personnel recently summarized their program and presented preliminary economic analyses. Coal Liquefaction Using Basic Nitrogen Solvents The Electric Power Research Institute (EPRI) has been sponsoring coal liquefaction research on a concept using basic nitrogen heterocyclic solvents at relatively mild liquefaction conditions. As described in the article beginning on page 4-42, coal conversions of essentially 100% have been achieved.

A-8 SYNTHETIC FUELS REPORT, DECEMBER 1982 \ V fl fnel s: general ENERGY POLICY AND FORECASTS

NATIONAL ENERGY POLICY NEEDED subsequent article.) In that publication, the lEA presents a very detailed analysis on how the 1979-1980 price While the synthetic fuels industry has been the object increases contributed to the present recession. That of much legislation, including the Energy Security Act analysis, coupled with the results presented in the lEA which established the Synthetic Fuels Corporation, our "World Energy Outlook" (see the next article), paint a country still does not have a well defined synfuels clear picture that economic recovery will be hampered by policy or even an energy policy. A number of attempts our dependence on oil. to abolish the corporation have been made repeatedly by members of Congress. President Reagan's support Further, the LEA also sees the energy situation in the U.S. has certainly not been positive or decisive; he took over as well as the world as uncertain and cautions that "It a year to appoint a full board of directors to the would be particularly inappropriate, and carry great risks, corporation, giving industry very mixed signals as to his if the public in the United States and abroad were to feeling about the SFC and whether it would be allowed regard the dismantling of the Department of Energy as an to exist. The Administration and Congress need to indication that the United States government feels that issue a well-defined policy statement recognizing the energy problems have now been resolved." importance of energy to the economy and our security and giving the Synthetic Fuels Corporation full and Dr. Ulf Lantzke, Executive Director of the International complete support. Energy Agency has suggested that the present concern for the stability of the International Banking System is While the government and corporations are concerned directly tied to the recycling of petro-dollars and the about the availability, the resulting cost, and relation- financing requirements of the largest developing country ships of various forms of energy, disagreement exists economics. He also attributed the latest financial about the relationships between the economy and concern to the damage that unbalanced energy supplies energy resulting in an economic situation that can be can do to a nations"and the worlds' economy. described, at best, as uncertain. Obviously, the price of oil affects a country's balance of Part of the uncertainty stems from the controversy payments. Table 2, taken from the June 1982 Department concerning the degree that the price of energy, particu- of Commerce Survey of Current Business, gives the larly oil has affected our economy. Table I gives the amount of our petroleum imports as well as our trade landed cost of crude oil imports into the U.S. from balance. Figure 2 is a graphic representation of that selected countries between 1975 and 1981. Figure 1 data. As our imports of petroleum products increased, gives the refiner acquisition cost of crude oil. Source: the negative balance of payments also increased. Energy Information Administration's 111981 Annual Report to Congress." TABLE 2 U.S. COST OF PETROLEUM IMPORTS After both the 1973 and 1979 price explosions, a AND TRADE BALANCE recession occurred. One economist, James D. Hamilton of the Department of Economics at the Millions of Dollars University of Virginia has presented evidence that over Petroleum Trade the period 1948-1972, all but one of the U.S. recessions Year Imports Balance have been preceded by a dramatic increase in the price of crude. Further, he states that the correlation is 1974 26,609 -5,343 statistically significant and nonspurious, supporting the 1975 27,017 -9,047 proposition that oil prices were a contributing factor in 1976 35,573 -9,306 at least some of the recessions prior to 1972. 1977 44,983 -0,873 1978 42,312 -33,759 Following the 1973-1974 Arab oil embargo, the United 1979 60,482 -27,346 States and fifteen other oil importing countries estab- 1980 79,414 -25,338 lished the International Energy Agency (lEA). (See the 1981 77,579 -27,889 following article and page 1-6 of the December 1980 Synthetic Fuels Report for more information on the Source: Survey of Current Business lEA.) One of the most important objectives of the lEA June 1, 1982; page 50, Table III was to remove energy as a constraint to economic growth among industrialized countries by using available energy resources in a balanced manner. The present administration's policy of allowing the market In addition, the LEA reviews the energy policies of place to determine energy supply and demand is clearly member countries. (The latest publication on members' insufficient to deal with the complexity and depth of the energy policies and programs is reviewed in detail in a problems regarding energy and the economy.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-1 Dollars per Barrel Dollars per Barrel 50- -50

45- Imported -45 Composite 40- Domestic - -40

35- I /, 30- /'/ -30 I // 25- I 1/ -25 / I,/ I 20- /, -20 I, 15- ,/ / -IS — ------10- _------10 : .:_--

5- -5

I I I I p p I I I I I 1968 1970 1972 1974 1978 1978 1980 1981 FIGURE 1 REFINER ACQUISITION COST OF CRUDE OIL

MILLIONS N OCLLAF6 80000

PE 70000 INJOWS 60000

5 0000 TRADE OALMCE 40000

30000

20000 -

10000 -

-10000 - N -20000 -

-30000

-40000 1914 1975 1918 1977 1970 1919 1980 1901 YEAR

FIGURE 2 COST OF PETROLEUM IMPORTS AND TRADE BALANCE FOR U.S.

1-2 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 REFINER ACQUISITION COST1 OF CRUDE OIL, 1968-1981 (Dollars per Barrel) Year Domestic2 Imported! Composite2 1968 3.21 2.90 3.17 1969 3.37 2.80 3.29 1970 3.46 2.96 3.40 1971 3.68 3.17 3.60 1972 3.67 3.22 3.58 1973 4.17 4.08 4.15 1974 7.18 12.52 9.07 1975 8.39 13.93 10.38 1976 8.84 13.48 10.89 1977 9.55 14.53 11.96 1978 10.61 14.57 12.46 1979 14.27 21.67 17.72 1980 24.23 33.89 28.07 1981 34.33 37.24 35.25

1. Refiner acquisition cost of crude oil for each category and for the composite is derived by dividing the sum of the total purchasing (acquisition) costs of all refiners by the total volume of all refiners' purchases. 2. Data 1968 through 1973 are estimated. 3. Averages for January through November. Sources: • 1974 through January 1976 - Federal Energy Administration, Form FEO 96, "Monthly Cost Allocation Report." • February 1976 through September 1977 - Federal Energy Administration, Form PEA P110-M-1, "Refiners' Monthly Cost Allocation Report." • October 1977 through June 1978 - Energy Informa- tion Administration, Form PEA P110-M-1, "Refiners' Monthly Cost Allocation Report." S July 1978 through December 1980 - Energy Information Administra- tion, Form ERA 49, "Domestic Crude Oil Entitlements Program." S 1981 - Energy Information Administration, Form EIA-14, "Refiners Monthly Cost Report."

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-3 One factor overlooked in allowing the market to guide TABLE 3 energy policy is the high capital cost and long lead time required to build a synthetic fuels plant. Couple these MAJOR LEGISLATION AFFECTING ALTERNATIVE requirements with the need for executives to produce a FUELS POLICIES positive bottom line on the balance sheet or be replaced, it is not surprising that firm after firm have Clean Air Act (and amendments) scaled down or cancelled plans for synthetic fuels Clean Water Act (and amendments) development. Coastal Zone Management Act Coal Leasing Act (and amendments) The Administration's desire for a minimum amount of Combined Hydrocarbon Leasing Act of 1981 government interference through regulations or sub- Antiquities Act of 1906 sidies is desirable and makes good election rhetoric, Archeological Resources Production Act of 1979 The problem, however, is the number of laws and Deep Water Ports Act regulations that influence the energy options. Table 3 Endangered Species Act of 1973 (and amendments) is a listing of some of the major legislation affecting Endangered American Wilderness Act of 1978 alternate fuels policy. Obviously, a more comprehen- Energy Security Act sive and accurate list could be drawn up regarding any Federal Coal Mine Safety and Health Act of 1969 (and resource option. Certainly, the trend toward less amendments) government interference can be advantageous. How- Federal Land Policy and Management Act of 1977 ever, even if 50 percent of these laws were totally National Energy Act repealed we would have only compounded our present Fishery Conservation and Management Act biggest problem: uncertainty. Various groups would National Forest Roadless Act of 1980 challenge the repeal and industry would be only more Natural Gas Policy Act uncertain about the prospects for the future. National Historic Preservation Act National Environmental Policy Act Clearly then what is needed is direction: A defined Marine Protection Research and Sanctuaries Act energy policy, ideally that is bi-partisan. Further our Noise Control Act energy policy and foreign policy should be coordinated Outer Continental Shelf Land Act for security reasons. The importance of energy and the National Game Fish and Wildlife Act security issue has been widely analyzed. Harvard Resource Conservation and Recovery Act University's Energy and Security Research Project Safe Drinking Water Act (and amendments) explored in depth the relationships between energy, the Soil and Water Resources Conservation Act economy and national security, publishing the results in Solid Waste Disposal Act (and amendments) a book, "Energy and Security," Edited by David A. Power Plant and Industrial Fuel Use Act Deese and Joseph S. Nye. The Energy and Environ- Surface Mining Control and Reclamation Act of 1977 mental Policy Center co-sponsored a study of the Toxic Substances Control Act impact of energy on the world economy and world Windfall ProfitsAct Politics and released the results in a recently published book, "Global Insecurity: A Strategy for Energy and Economic Renewal," edited by Daniel Yergin and Martin Hillenbrand. Like the lEA study, it also predicts gress and the Administration would help the country World Energy to the year 2000 based on 2 scenarios economically and strategically by working toward a which see synthetic fuels making only a minor contribu- defined energy policy that is coordinated with our mili- tion to energy available. One reason given is the tary policy. unclear position on synthetic fuels of Ronald Reagan. The Georgetown Center for Strategic and International Studies began a study of the relationship between SYNFUELS CONTRIBUTES LITTLE IN "WORLD ENERGY energy and national security over two years ago. OUTLOOK" Results of the study were published in a book entitled, "The Critical Link: Energy and National Security in the The International Energy Agency (lEA) recently published 1980's." the second "World Energy Outlook." The first "World Energy Outlook" published in 1977 examined how the In a more directed effort, James K. Harlan of the industrialized countries could move toward a better mix Synthetic Fuels Corporation has recently published, of energy supplies to prevent economic disruption. "Starting With Synfuels: Benefits, Costs and Program Design Assessments." The quantitative analysis of The analysis presented in the first "World Energy Outlook" costs and benefits of a national synthetic fuels program laid the basis for developing energy guidelines. The most is presented as is a qualitative analysis. One important important are: Principles-for Energy Policy (1977), Lines point that Harlan addresses is the need for Congress to of Action of Coal (1979), and Lines of Action for Energy clarify the Energy Security Act's emphasis on produc- Conservation and Fuel-Switching (1980). tion volume as a primary objective. The lEA was established in 1974 when the United States in All energy policy makers in Congress and the Adminis- response to the oil crisis of 1973, urged the international tration should read each of these books carefully as community to develop a program of cooperative action they are the results of years of efforts by experts in the for dealing with the changing world energy situation. (See energy and economics fields. Subsequently, both Con-

1-4 SYNTHETIC FUELS REPORT, DECEMBER 1982 page 1-6 of the December 1980 Synthetic Fuels Report for a detailed decription of the lEA.) growth rates of 2.6% per year, on average, between 1980 and 1985, and of 3.2 percent per year in the 1985-2000 The "World Energy Outlook" (1982) covers all forms of period. energy with the focus on the area of concern of the Organization for Economic Cooperation and Develop- The economic growth rate of this scenario would be ment (OECD) with oil as the most crucial fuel. necessary to reduce the current unemployment in the OECD countries. (ED. NOTE: Combining high growth and One major conclusion of the study is that policies and constant oil prices is a basic fallacy of this assumption). economic mechanisms conducive to market equilibrium are currently in place. Implementation of energy In the low demand scenario, growth would be dampened by policies adopted after 1973, together with the price of gradually rising oil prices and subdued economic growth. oil has generated gains in both energy efficiency and The scenario assumes a 3 percent annual increase in the substitution of other fuels for oil. As proof of this, the real oil price after 1985. For the immediate future, a study cites the declining imput of both energy and oil price decline of 3.3 percent per year is assumed. This per unit of Gross Domestic Product (GDP). In 1980, for would mean that real oil prices in constant 1981 dollars example, real GDP in the OECD was 19 percent higher would fall to about US$ 29 per barrel in 1985 and then than in 1973, but energy consumption had grown by only grow to levels of about US$ 45 per, barrel at the end of 4 percent and oil use was even 3 percent below 1973 the century. As in the high demand scenario, assumptions levels. for economic growth are based on a recovery in the first half of the 1980s but at lower rates, averaging 2.4 percent The study attempts to quantify the likely efforts of per year through 1985 and 2.7 percent per year over the market forces under presently prevailing policies using period 1985-2000. These growth rates would not curb two assumed scenarios for price and economic growth. unemployment. Table 1 gives the underlying assumption of demand Using each of these scenarios, the supply and demand by projections. fuel for each of three regional groups of OECD countries was determined. TABLE 1 Study Sees Present Situation Deceptive UNDERLYING AUMPTIONS OF DEMAND PROJECTIONS According to the study, the current situation in the energy markets and the oil market in particular, is 1980-1985 1985-2000 deceptive in its stability as well as uncertain and cyclical. It is deceptive in that the current oil market does not High Demand Scenario: indicate the tight market projected by the study in the Constant Oil Price/High Growth latter 19801s. Table 2 gives the OECD energy demand and Real Oil Price -3.9% +0% world oil balance. Economic Growth +2.6% 3.2% From the mid-1980's onwards, the study sees the oil market likely to gradually move towards a basic dis- Low Demand Scenario: equilibrium again as growing world oil demand will be Rising Oil Price/Lower Growth confronted with stagnating production. In particular, oil Real Oil Price -3.3% +3.0% output in North America, the North Sea and the Soviet Union is projected to level off or decline, and OPEC Economic Growth +2.4% +2.7% production could well be constrained by declining reserves in some countries and by political decision in others. At the same'time, oil import requirements are expected to Existing energy data for OECD countries, as well as rise significantly in the Third World as a result of assumptions about the effects of policies in place and economic development, increasing urbanization and indus- technological changes, are used to derive price and trialization. OECD demand for oil imports, on the other income elasticities of energy demand for each of the hand, would at best decline slightly from present levels if major end-use sectors. On this basis, an econometric non-oil energy use grows substantially, but may well model was constructed in order to illustrate the quanti- increase steeply in the absence of additional price or tative impact of various economic assumptions on policy incentives to restrain oil consumption and to future energy demand. increase domestic production. The basic assumption of the high demand scenario is According to the study: "overall demand developments that oil prices would maintain their real value in the together with limited progress in interfuel substitution long run, i.e., increase at the rate of inflation, between could set the stage for an oil market situation where the mid-1980s and the end of the century. Until 1985, demand would again tend to exceed available supplies. however, real oil prices are assumed to decline by 3.9 With growing margins of excess demand, substantial price percent per year, i.e., by 1 percentage point more than pressures would build up and might ultimately find an the 1974-78 trend in world oil prices. The result would outlet in renewed erratic price movements. In fact, the be a real oil price of about US$ 28 per barrel, in past price shocks occurred in a climate where demand and constant 1981 dollars, after the mid-1980s. In line with supply were closely balanced, but were suddenly this pricing outlook, the scenario assumes economic precipitated by political events in the Middle East. Political tensions in that area remain unsettled and the

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-5 TABLE 2

OECD ENERGY DEMAND AND THE WORLD OIL BALANCE1 (Mbd)2

1980 1985 1990 2000

OECD

Total Primary Energy 79.1 81 - 82 89 - 93 105 - 121 Non-Oil Energy Demand 40.4 46 55 - 56 72 - 78 Oil Demand 38.7 35 - 36 34 - 37 72 - 78 Oil Import Demand 24.2 21 20 - 24 18 - 30

World Oil Demand

OECD 38.7 35 - 36 34 - 37 33 - 43 OPEC 2.9 4 5 - 6 8 - 9 Non-OPEC LDCs3 7.9 9 -10 11 - 13 17 - 22 Total 49.5 48 - 50 40 - 56 58 - 74

World Oil Supply

OECD4 14.8 15 14 - 13 15 - 13 OPEC5 27.5 23 - 26 27 - 29 24 - 28 Non-OPEC LOCs 5.3 8 9 8 - 11 9 - 13 CPE6 Net Exports (Imports) 1.3 1 - (1) 0 - (2) 0 - (2) Processing Gains 7 0.6 0.6 0.6 0.6 Total 49.5 48 - 50 50 - 52 49 - 53

Excess Demand - -- 0 - 4 9 - 21

1. Figures mentioned first are from Low Demand Scenario 2. Conversion factor: 1 Mbd = 48.2 Mtoe or 1 toe - 7.57 barrels 3. Non-OPEC Developing countries (also includes South Africa and Israel). 4. Including Synfuels 5. OPEC estimates are basically for 'possible" production as indicated by reserves and projected additions to reserves. In addition, estimates for 1985 reflect low demand. For 1990 and 2000, oil production in capital surplus countries such as Saudi Arabia, Kuwait, and Abu Dhabi is less than technical capacity. 6. Centrally Planned Economies: EuropeLn and Non-European Comecon countries: Chinn, North Korea, Laos, Kampuchea; Yugoslavia, Albania 7. Gains in volume (not in weight) due to the refining process

16 SYNThETIC FUELS REPORT, DECEMBER 1582 major risk to the world economy that will arise as oil The major issues associated with gas trade are price and markets tighten is the range of political events that security of supply. The study warns that oil dependence could once again disrupt oil supplies." could be replaced by a new vulnerability to disruption in external gas supplies. Table 3 gives the natural gas Figure 1 gives a synopsis of OECD primary energy projections: demand and supply history and projection. This assessment does not capture the potential risks underlying the Coal will be of growing importance both in absolute and supply side. relative terms. Table 4 shows projected coal use. Coal output is estimated to expand in line with the development of demand.

The study concluded that 10 to 20 percent of total OECD energy could be met by nuclear energy. Table 5 shows projected nuclear energy use. The study is an excellent reference work detailing the world oil supply outlook and giving a detailed world analysis of oil production. World coal prospects are extensively covered by looking at the resources and reserves, supply and demand, prices, interfuel cost comparisons for electricity generation, and constraints on coal use including environmental problems. The role of nuclear power generation is assessed and status of nuclear programs in OECD countries is given. (ED. NOTE: Perhaps one of the major problems with the study is that it attributes a greater percentage of the energy picture to nuclear than is warranted.)

The study covers natural gas demand, production, resource and reserve in the same detail as other conventional energy sources. Role of Synthetic Fuels Is Minimal

Synthetic fuels are referred to briefly in the analysis of conventional fuels as being part of the unconventional source; i.e., synthetic gas from coal is categorized as unconventional gas. Unconventional oil is defined as oil from tar sands.

One chapter on new and renewable energy technologies briefly deals with tar sands and heavy oils, shale oil, coal conversion, coal combustion and enhanced oil recovery. According to the study, the $45 (1981 $) projected for 2000 in the low demand/high oil price scenerio closes off present options for developing alternative fuels on a FIGURE I strictly economic basis as current estimates place the OECD PRIMARY ENERGY DEMAND AND SUPPLY cost of the product at substantially higher than this level. HISTORY AND PROJECTIONS Further: "Based on current experience and evaluation, it is most unlikely that shale oil, tar sands or coal conversion will, at least in this century, be more than marginally economic compared with petroleum. Capital cost estimates of such large plants provide only an accurate guide where proven technology is being considered: inflation The study sees the importance of natural gas varying being the major variable. Once costing of new processes regionally. "In North America, where high gas use was is undertaken, technological uncertainties become signi- sustained by domestic production in the past, con- ficant and tend to have large effects on the total capital strained gas output may lead to a decrease from a costs, particularly as project completion draws near. This present share of over 25 percent to 16 - 21 percent in phenomenon has occurred with shale oil ventures, and the 1990's. In contrast, gas is projected to grow in with a recent coal liquefaction project, now abandoned. importance in the Pacific Region from only 7 percent It should be noted that, apart from the South African to 13 - 17 percent. In Europe, where natural gas now experience, coal conversion technology is not so far accounts for 14 percent of total energy, the future advanced as oil shale. If synthetic fuels are to be a viable share could range from 12 - 16 percent." alternative beyond the year 2000, it follows that pioneer plants have to be built now so that technically and

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-7 TABLE 3

PROJECTED OECD USE OF NATURAL GAS (in billion cubic meters)

1980 1985 1990 2000 Production 840 845 - 851 805 - 851 740 - 854 Net imports 56 100 - 102 218 - 201 275 - 305 Total 896 945 - 953 1,023 - 1,051 1,015 - 1,159

TABLE 4

PROJECTED OECD USE OF COAL (in million tons of coal equivalent)

1980 1985 1990 2000 Production 1,138 1,187 - 1,194 1,419 - 1,474 1,985 - 2,300 Net Imports 46 81 - 64 81 - 86 143 - 186 Total 1,160 * 1,248 - 1,258 1,500 - 1,500 2,128 - 2,486

Excluding 1980 stock increases

TABLES

PROJECTED OECD USE OF NUCLEAR AND OTHER ENERGY

1980 1985 1990 2000 Nuclear Fuel equivalent (Mtoe) 145 300 - 305 425 - 441 570 - 620 Capacity Equivalent (GWe)* 119 215 - 220 305 - 310 405 - 440

Other (Mtoe) 255 278 - 283 310 - 334 380 - 520

* Figure for 1980: end of year. Otherwise approximate estimates on the basis of an annual utilization rate of 65% (conversion factor I GWe = 1.4 Mtoe).

1-8 SYNTHETIC FUELS REPORT, DECEMBER 1982 economically viable commercial scale designs are avail- percent per year from 1975-1978 setting the stage for the able for the future. Since in the short term, industry massive price explosion of 1978-1980. Renewed economic would find this investment virtually impossible, govern- growth could lead to rapid increases in oil demand. ment assistance would be required to enable the momentum of synfuels development to be maintained." The report presents a succinct analysis of how the 1979- 1980 price increases contributed to the significant down- The report concludes that: "By 1990, the contribution turn in lEA economics. The 170 percent increase in the of all synthetic fuels to the energy supply price of oil resulted in an increased payment to oil demand/balance will be only marginally signficant. By producers outside of OECD, mostly OPEC. This very 2000, their contribution in OECD countries might have large transfer of OECD resources affected overall increased to 50 million tons of oil equivalent. economic performance in three ways: The "World Energy Outlook" can be purchased for $45 • an adverse shift in the terms of trade occurred which from the OECD Publications and Information Center, increased the price of all oil and oil-related products 1750 Pennsylvania Avenue, N.W., Washington, D.C. and consequently reduced the real income of oil- 20006-4582. consuming countries. The most substantial shift in income occurred between OECD and OPEC countries, and amounted in 1980 to about 2 percent of total OECD GOP; a transfer of similar magnitude occurred LEA PRESENTS POLICY AND PROGRAMS OF in 1981; MEMBER COUNTRIES • aggregate demand for OECD goods and services fell The lEA was established in 1973 to assist member significantly as this transferred income was not countries to overcome their dependence on imported immediately or totally respent in OECD economies. oil. (See the article in the Energy Forecasts section Some of the oil-producing nations to whom income was and also the December 1980 Cameron Synthetic Fuels transferred are characterized by small populations and Report for a description of the lEA.) high per capita income and the additional income manifested itself as very high surpluses on their The International Energy Agency presents a yearly current account balance of payments. While these review of member countries' national energy policies. surpluses were ultimately available to be borrowed, In the 1981 report, released earlier this year, detailed the recirculation of the transferred income took some reviews were completed for Germany, Ireland, Italy, time and thus tended to reduce aggregate demand in Sweden, the United States and the United Kingdom. the OECD economies. The OECD has estimated the Also examined were the policies of: Australia, Austria, effects of this overall reduction in spending to be Belgium, Canada, Denmark, Japan, Luxenbourg, equivalent to a reduction of OECD GDP (from levels it Netherlands, New Zealand, Norway, Portugal, Spain, might otherwise have attained) of about 3 percent in Switzerland and Turkey. The report points out that 1980 and 4 percent in 1981; while lEA members have imported and consumed less oil following the 1979-1980 oil price hikes, lEA • in response to the direct inflationary consequences of economies have not decreased their dependence on oil higher oil prices, changes in the terms of trade, and very much; In 1973 oil accounted for 51 percent of reductions in overall spending, OECD governments total energy requirements and only fell to 48 percent in attempted to limit the flow-through of higher oil 1980. prices to domestic inflation by adopting more restric- tive domestic economic policies. The alternatives to One important point made in the report is that "relative such an approach would have risked a more serious stability in oil prices can be an important factor in a acceleration of inflation and inflationary expectations, return to higher economic growth rates. If, however, causing even greater economic problems. This policy higher levels of economic activity were to lead to a response has been estimated by the OECD to have substantial increase in oil demand, the vulnerability of further reduced OECD GDP by about 0.25 percent in the world economy to potential oil market pressures 1980 and about 1.75 percent in 1981. would increase once again. Oil would continue to be a constraint to sustaining healthy economic growth, and Overall, these factors have amounted to a 5 percent loss the breathing space which is now available because of in real income in 1980 and a subsequent loss of almost 8 the current oil market position would not have been percent in 1981. Over these two years, the total loss of used wisely - to protect and enhance our future income attributed to the oil price increases amounted, in options." 1980 dollars, to almost US$ 1000 billion —or about 115$ 1250 per person in the OECD economies. The oil price The extent that reduction in oil demand reflects perma- increases also contributed to increasing unemployment nent changes in the structure of energy economies is and continuing high inflation rates. The overall impact on discussed in detail in the report. Almost half of the unemployment has been staggering, with the total number observed reduction in oil use may beattributed to of unemployed rising from about 19 million persons in economic recession and other special factors such as 1979 to an estimated 29 million in 1982. The continuing climate and stocking behavior. inflationary pressure has also been substantial and has resulted in interest rates rising to record levels in an In the recession of 1973-1975, oil use decreased by 5.6 effort to contain inflation and reduce it to more accept- percent (1.9 mbd) the following economic recovery led able levels. These estimates indicate the overall magni- to a rapid increase in oil demand in lEA countries: 4.1 tude of the cost of the oil price increases, and show

SYNTHETIC FUELS REPORT, DECEMBEIL 1982 19 clearly why it is essential to protect against the TABLE 1 possibility of further price shocks in the future. ECONOMIC INDICATORS - SELECTED lEA COUNTRIES' Table 1 from the lEA report gives selected economic (per cent) indicators that are important from an energy policy viewpoint. The interest rates governs the return -- in 1968-73 1973-80 1979-81 terms of savings in energy costs - which investors require from investments in energy efficiency or substi- Economic Growth2 tution. It also markedly affects the viability of non- Canada 5.4 2.9 0.9 conventional energy sources, such as coal gasification Germany 5.1 2.3 0.5 and liquefaction, solar plants, and bio-energy plants, as Italy 4.4 4.0 2.0 well as new electricity generating capacity. Such Japan 9.7 3.6 3.5 plants are very capital-intensive and, where new tech- United Kingdom 3.2 0.8 -1.3 nology is involved, are often viewed as high-risk invest- United States 3.3 2.6 1.04 ments. In most lEA countries, real interest rates have increased markedly between 1973 and 1981, and most of Weighted Average 4.6 2.7 1.3 the countries listed in Table I have also sustained a severe decline in the rate of growth of investment. In Inflation Rate5 the United Kingdom and the United States the absolute Canada 5.3 10.0 8.7 level of real investment declined between 1979 and Germany 6.0 4.7 3.9 1981. Italy 7.2 17.6 16.8 Japan 6.2 7.2 2.8 The report concludes that: "Sustained and determined United Kingdom 7.8 16.1 12.9 implementation of energy policies is required to United States 5.1 7.9 8.1 continue to reduce energy and oil use through effi- Weighted Average 5.7 8.6 7.5 ciency gains and to replace oil with coal, natural gas and nuclear energy. The development of non-conven- Average Annual Growth tional forms of energy such as solar, wind, coal conver- of Private Investment sion and biogas will also be required in the medium to Canada 7.3 3.5 5.9 longer term." Germany 6.2 1.5 0.5 Italy 3.1 0.8 5.8 Specifically: "renewable energy, synthetic fuels, and Japan 12.2 7.7 1.6 unconventional energies can play an important and United Kingdom 2.3 -0.2 -3.6 increasing role in replacing oil. Hydroelectric power United States 4.8 1.2 -3•34 already makes a substantial contribution and other renewable sources are receiving support of various 1973 1979 1980 1981 kinds from most lEA governments. Energy produced by these other sources will increase rapidly during the Unemployment Rate (%) 1980's, but will not make a significant contribution to Canada 5.9 7.5 7.5 7.6 TPE until after 1990. Synthetic fuels and unconven- Germany 1.3 3.8 3.8 4.8 tional energies generally require large capital commit- Italy 6.4 7.7 7.6 8.5 ments and long lead times. The environment for their Japan 1.3 2.1 2.0 2.2 development is not favorable at present due to high Unitd Kingdom 2.6 5.4 6.8 10.8 interest rates, withdrawal of government support in United States 4.9 5.8 7.1 7.6 some countries, recent oil price movements and uncertainty about future oil price trends. Because of long Interest Rate7 lead times for renewables and synthetics, however, it Canada 7.7 11.3 12.7 15.4 remains important to pursue the development of tech- Germany 9.6 7.9 8.9 10.8 nologies required to the point where commercialization Italy 7.1 14.0 18.2 19.3 becomes feasible, under appropriate economic Japan - 8.6 9.4 9.0 conditions, with minimum delay." United Kingdom 12.3 11.8 12.1 14.1 United States 6.5 9.6 11.5 14.3

1. The six countries shown account for about 80% of OTA REPORT STRESSES NEED FOR MAJOR EFFORT total GDP in the LEA area. TO REDUCE OIL IMPORTS 2. Annual average growth rates of GDP between the two years stated. The Senate Committee on Commerce, Science, and 3. 1981 statistics are extrapolated from the data for Transportation requested the Office of Technology the first two quarters of 1981 Assessment to assess and compare increased automobile 4. Extrapolated from the first three quarters of 1981. fuel efficiency and synthetic fuels production with 5. Rate of growth of GDP deflator. respect to their potential to reduce conventional oil 6. Extrapolated from first quarter 1981 only. consumption. The report, released September 16, also 7. Interest rate on long-term government bonds. considered, in less detail, conservation and fuel switching as a means of reducing stationary oil uses. The purpose of the report was to assist Congress in address-

1-10 SYNTHETIC FUELS REPORT, DECEMBER 1982 ing several options that could reduce our dependence on • Even a 20 percent electrification of the auto fleet imported petroleum. - a market penetration that must be considered improbable within the next several decades - is The OTA report pointed to two conclusions that may unlikely to save more than about 0.2 MMB/D. warrant congressional consideration of changes in current Federal energy policy. These are: Regarding comparative costs the report found that: "the estimated investment costs (in dollars per barrel per day) • 'First, current policies affecting investments in during the 1990's of automobile efficiency increases, energy conservation and domestic energy pro- synthetic fuels production, and reduction of stationary duction are not likely to result in levels of oil uses of oil are essentially the same, within reasonable imports below 4 MMB/D in 2000, if the U.S. error bounds. If Congress wishes to channel national economy is healthy and has not undergone investments preferentially into one of these options, unforeseen structural changes that might reduce differentials in estimated investment costs cannot provide oil demand well below projected levels. During a compelling basis for choice." the next 20 years, OTA expects that, under these policies, oil import reductions due to synthetic However, the report noted that "investments during the fuels production and decrejised stationary and 1980's to reduce stationary oil use (from the current 4.4 automobile oil use will be partially offset by a to 3 MMB/D or less by 1990) and increase automobile fuel decrease in domestic production of conventional efficiency (to a 35 to 45 mpg new-car fleet average by oil. Reducing net oil imports to 1 or 2 MMB/D 1990) are likely to cost less than the 1990-2000 invest- or less by 2000 is likely to require more vigorous ments in any of the options." pursuit of all options for reducing domestic consumption of conventional oil products. On the Regarding synthetic fuels plants the report also pointed other hand, elimination of current conservation out that: and synthetic fuels production policies could cause imports to range from 5 to 6 MMB/D by "Large-scale synthetic fuels production would generate 2000 under these same economic conditions." significant amounts of toxic substances, posing risks of health damage to workers and possible risks to the public • "Second, current policies may not provide through contamination of ground waters or by small society with adequate protection from some of amounts of toxics left in the fuels. There should not be the adverse side effects of synthetic fuels any technological barrier to adequate control of these development and increased automobile fuel effi- substances, but OTA concludes that there are substantial ciency. Of particular concern are possible reasons to be concerned about the adequacy both of reductions in automobile crash safety (as the proposed environmental protection systems and of the number of smaller, more fuel-efficient cars existing regulatory structure. increases), inadequate control of toxic substances from synfuels development, and adverse "Other important effects of synfuels production stem socioeconomic effects from both options." from the very large scale of both the individual projects and, potentially, the industry as a whole. These may Figure 1 shows the possible contribution of various overwhelm the social and economic resources of nearby sources by the year 2000. population centers, especially in sparsely populated areas of the West. At national production levels of a few The report cautions, however, that: because of the million barrels per day, impacts from coal and shale large technical, economic, and market uncertainties mining and population pressures on wilderness areas and inherent in the analyses of oil displacement options, other fragile ecosystems can be substantial even in com- Congress may wish to emphasize flexible incentives parison with major industries such as coal-fired power with provisions for periodic review and adjustment. A generation. On the other hand, conventional air pollution stable commitment to oil import displacement will be problems from such plants are likely to be considerably necessary, however, to maximize the effect of such less than those associated with similar amounts of coal- policies. fired power generation. • On a "per unit of coal used" basis. The report also cited the following specific conclusions: "Finally, although water requirements for synfuels are a • Increases in auto fuel efficiency will continue, small fraction of total national consumption, growth of a driven by market demand and foreign competi- synfuels industry could either create or intensify competition. tion for water, depending on both regional and local factors. Such competition is of special concern in the • Substantial contributions to oil import reductions and West. Unfortunately, a reliable determination of from production of synthetic fuels appear to be both the cumulative impacts on other water users and, in less certain than substantial contributions from some instances, the actual availability of water for the other options. (See Figure I for possible synfuels development is precluded by physical and institu- contributions from various sources.) tional uncertainties, changing public attitudes towards water use priorities, and the analytical shortcomings of • There are likely to be large reductions in the existing studies. stationary use of fuel oil (currently 4.4 MMB/D) in the next few decades.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-11 B

7 -

* 6 - SynILleI5 Conservation and High - tuel switching in stationary uses of fueloll High Additional potential & I ricrosed auto savings beyond fuel efficiency a - L base case 3 High C Low

Oil aavings incorporated In base case

• ______I_ri__Ifl.5 a as t sn-u.. ,__ _w • S - _ - — waaaaaaaaw edt. — — we — — — Saaaaaw,.

FIGURE I POTENTIAL OIL SAVINGS POSSIBLE BY THE YEAR 2000 (RELATIVE TO 1980 DEMAND)

"However, in areas where there are relatively few able, most people would agree that they are significant obstacles to transferring water rights (e.g., as is ($5 to $50/bbl depending on various circumstances) and currently the case in Colorado), developers should be that the private market generally does not take them into able to obtain the water they need because their account." consumption per barrel of oil produced is small enough to enable them to pay a relatively high price without While the report lists the distinguishing features of significantly affecting the final cost of their products." increasing automobile fuel efficiency versus synfuels production as given in Table I, OTA states that the essential The report's most worthy contribution which should be differences between them suggest that there is no single heeded by both the administration as well as Congress, role for government policies and programs, and that both is the analysis of the role of the government in the are complementary measures for reducing oil imports. Chapter on Policy as well as the analysis of the real costs of oil imports in the chapter or issues and Under Policy Options the report discusses both economy- findings. The report correctly states that: wide and sector-specific policies. Taxation on oil and transportation fuels as well as special taxation provisions "Government policy is vitally important, because are discussed. Government policies regarding research energy inevitably affects, whether directly or and development, and trade protection are also discussed. indirectly, all production and consumption decisions in Sector-Specific demand stimuli such as purchase pricing an industrial society. How quickly and to what level mechanisms and registration taxes are analyzed. the Nation displaces oil imports have direct implications for who benefits from, and who pays the costs of, Sector-specific supply stimuli such as loan guarantees and energy independence. Such distributional questions grants, purchases and price guarantees are also analyzed. arise regardless of policy choices. Thus, the policy A very small portion of the chapter cites the policies that choices made by Congress transcend a simple choice could be used to encourage the use of methanol. Given between intervention and nonintervention." the extensive coverage of methanol in recent Congres- sional hearings (see page 4-40 of the September 1982 Pace OTA justifies the imposition of Federal policy on the Synthetic Fuels Report), a major shortcoming of the OTA workings of the private market on the basis of the report is the limited analyses of the role the government market's failure to value public costs and benefits. For could play in methanol use. Further, the report does not example: "A particularly important public cost of U.S. address the significant role of natural gas in the produc- dependence on imported oil, is the national security tion of methanol (see article in the International Section problem imposed by political instability in the Middle on methanol production in underdeveloped countries.) East and the resulting potential for oil cutoffs. Although the precise magnitude of these costs is debat-

1-12 SYNTHETIC FUELS REPORT, DECEMBER 1982 The report, as a whole, is worthwhile and should be read by policymakers. Pace's view of synfuels and policies necessary for the government to undertake for decreas- ing our reliance on imported oil are analyzed in the first article in this section.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-13 TABLE 1

FEATURES OF INCREASING AUTOMOBILE FUEL EFFICIENCY AND SYNFUELS PRODUCTION

Increasing automobile fuel efficiency Synfuels production 1. Both near- and long-term restructuring of an 1. Growth and promotion of a new industry existing industry Likely to be dominated by a few large, mature 2. Dominated by a few large, mature companies 2. companies 3. Automobiles as consumer durables; differentiable; Synfuels as uniform, consumable commodities deferrable 3. 4. New technology involved, but can proceed incre- 4. Large technical risks; possibiities for "white mentally; associated risks are an ongoing feature elephants," major risk occurs with first commercial- of industry scale demonstration plants 5. Industry must produce competitive products each 5. Sponsoring industry is involved in a breadth of activities that provides alternative investment and year, including fuel-efficient cars 6. Precariousness of industry's current financial business opportunities, of which synfuels is one position; need to ease readjustment of an industry 6. Soundness of sponsoring industry's current financial in distress - position; need to facilitate growth 7. Large demand uncertainty 7 No unusual demand risk except insofar as synfuels 8. Dispersion of industrial activities, domestically differ from conventional fuels and, increasingly, internationally; some concen- 8. Dispersion of activities among coal regions; current tration of activities in the North-Central region oil shale activity concentrated in a small area of the of the United States West 9. Capital intensity and associated risks 9. Capital intensity and associated risks 10. Declining profit margins in domestic industry 10 Potential for profit still highly uncertain 11. Significance of international competition (i.e., 11. Long-term export potential; importahce of inter- auto imports); importance of domestic market to national competition (i.e., oil imports) in terms of financial viability establishing the marginal price 12. Large amounts of capital continually requirdd for 12. Large amounts of capital required primarily in the redesign, retooling, etc.; final costs for improved initial construction phase; final costs for synfuels fuel efficiency uncertain; calculation of capital production uncertain costs for fuel economy dependent on methods for 13. Can make significant contributions to reducing U.S. cost allocation oil imports; contributions have a long leadtime and 13. Can make significant contributions to reducing will not be significant until commercialization U.S. oil imports; contributions have a long lead- 14. Caters to a slowly growing or possibly declining time but can have significance incrementallly market 14. Caters to a saturated market; focus on product 15 No investment needed by consumer; consumer pays replacement rather than growth marketsqk incrementally for each increment of consumption 15. Consumer costs are investment to reduce future 16. Substitutes one fuel for another - fuel purchases 17. Fuel-replacement potential ultimately limited by 16. Reduces consumption of fuel demand for synfucis, environmental impacts of syn- 17. Fuel savings in automobiles limited to about 3.5 fuels plants, and coal and oil shale reserves MMB/D with about 1.5 MMB/D savings coming 18. Environmental and health impacts from: large-scale mining of coal and oil shale; possible escape of toxic from achieving a 30-mpg fleet 18. Principal health impact may be increased auto substances from synfuels reactors (major risks are deaths due to smaller cars direct worker exposures, contamination of ground water); visibility degradation; development pressures on frag4)e, arid ecosystems

1-14 SYNTHEIC FUELS REPORT, DECEMBER 1982 RESOURCES

APPLICATIONS OF GEOSTATISTICS TO ENERGY difference between classical statistics and spatial MINERALS statistics (geostatistics) is that the first looks at all observed (measured) values as having no spatial correla- Pace and Geostat Systems International Inc. (GSli) have tion, while geostatistics incorporates spatial correlation. been studying the application of geostatistics to coal This simle difference has a profound impact on the and synthetic fuels resources. Dr. Rex C. Bryan, success and quality of estimations. Further, geostatistics Director of the U.S. Division of GSII prepared this can offer professionals in other disciplines, such as geolo- article specifically for the Pace Synthetic Fuels gists, mine planners, and corporate executives, new tools Report. to achieve greater insights into their respective problems and to derive better answers. It is the first in a series dealing with the application of geostatistics to energy minerals such as oil, coal, oil Spatial Correlation shale and tar sands. The following papers will revolve around particular cases that 0511 has studied. In most energy mineral deposits (or oil reservoirs) the geologist is able to recognize the presence of areas where Geostatistics has become a powerful decision tool at the values of the measured phenomena (bitumen grade, many levels within resource and energy companies. The seam thickness, reservoir porosity) are higher or lower technique has shown itself to be extremely effective in than elsewhere. Furthermore, he will in most cases, answering a host of questions dealing with resource observe that the values of two measurements are more estimation, design of sampling programs, predicting likely to be similar if they are taken close together than grade fluctuations, plus many other questions. it they are taken far apart. The term geostatistics is used to describe applied This indicates that there exists some correlation between statistical techniques originally developed for mining measurements and that this correlation is a function of applications. The method is based on the observation the position and distance between samples. This study of that many geological processes, and hence variables correlation (or inversely, the variability) between that are derived (such as grade), are spatially spatially distributed samples can be illustrated by an controlled. This observation has prompted the extremely useful graphical representation called the development of a theory of regionalized variables. The variogram (sometimes referred to in the literature as the

FIGURE I BASIC COMPONENTS OF A VARIOGRAM

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-15 semi-variograrn). Figure 1 shows the basic components 1. The estimator should be unbiased: it should not of a variogram. A variogram can be used to describe systematically over or under estimate the true the three distinct sources of this variability: a random unknown value. component, a spatially correlated component and a deterministic component. 2. The (inevitable) errors resulting from the estimates should be as small as possible. The random component expresses the fact that two core samples taken side by side (or at the limit, taken 3. The estimator should be a simple relation of the known over one another) often do not have the same value. sample values (hence a linear function). This is seen in the lab, for example, by replication analysis and in the field by the nonrepeatability of The estimator which satisfies these properties is thus a many measurements. This random component has been minimum variance, linear, unbiased estimator or other- given the term "nugget" and is shown in Figure 1 as the wise known as the BLUE (for Best Linear Unbiased non-zero value at a very small separation distance. Estimator) estimator. The spatially correlated component models the observa- These elements are met by the geostatistical estimation tions of the geologists regarding the similarity of close method called "kringing." Results from the kriging samples. It further quantifies the variation of the method have been successfully compared to actual mined values at any separation distance. At a large enough data in many studies. It is just this type of pragmatic distance many phenomena have no spatial correlation at review which has led to its general acceptance by mining alt. It is at this distance, called the "range", that firms. measurements may be considered independent. Applications to Energy Minerals The deterministic component is used to model another observation of the geologist, namely the fact that There have now been quite a few applications of gco- values often preset a systematic variation in space. A statistics to oil sands and coal deposits, and studies systematic variation (referred to as a drift or trend) directed towards oil shale. The following applications manifests itself for example as a tendency for thickness list is not exhaustive, nor is an application limited to a of oil shale units to decrease along a specific direction. specific commodity. Interestingly enough, one can see that by leaving out Some of the applications of geostatistics in the Coal the correlated component and the deterministic compo- Industry are: nent, the geostatistical model is idential to the classical statistics model. • Estimating average BTU values and other coal qualities for mine planning Making Predictions • Deriving measurements of the estimation error to efficiently plan sampling campaigns Once a geostatistical model has been determined, it can • Designing stockpile and mixing stratagems to comply then be used to predict the value of the phenomena at with contract specifications unsampled locations along with a measure of the quality • Simulating the variation of coal qualities as mined to of that prediction. investigate the expected fluctuation of their values over time, given different mining plans An estimator usually combines (weights) samples around the unsampled location for which a predicted value is Some of the applications of geostatistics in the Tar Sands desired. The way in which the weights are assigned Industry are: depends on the estimation method. For example the polygonal estimator (widely used in mining) gives all the • Oridding and contour mapping of seismic variables weight (100%) to the sample closest to the unsampled such as velocity and depth point. The classical statistics estimator on the other • Determination of ore top and bottom depth hand weights each surrounding sample (l ... n) by one (1) • Interpolation of reserve parameters between core over the total number of samples W. Other techniques - - holes like inverse distance or inverse distance squared, • Estimation of volumetric reserves by block kriging weight the surrounding samples as a function of both • Estimation of volumetric reserves by zones or layers their number (n) and their distance from the unsampled • Determination of level of confidence on point and/or point. volume estimates • Gridding and contour mapping of levels of confidence All the above-mentioned techniques, fail to use all • Drillng campaign optimization three components of the geostatistical model. Further- more, none of the above methods give an indication of Some of the applications of geostatistics in the Oil Shale the reliability of the estimate, i.e.: the precision with Industry are: which the prediction is made. • Validation of measured samples by the use of Thus one should ask himself what are the desirable jacknifing (estimation of the measured sample from properties of an estimator? After reflection, these surrounding samples) properties can be identified as: • Tabulation of reserves according to grade and precision categories

1-16 SYNTHETIC FUELS REPORT, DECEMBER 1982 • Estimation of reserves within different mining zones and solar energy resources. The document presents and properties production data from 1952 through 1980 and illustrations • Plotting of block maps for mining purposes shows graphically the trends in production over that period. Historical discussion includes the how and when Importance to an energy firm lands within the Public Domain were acquired. The text and illustration show a growth of energy production from Geostatistics must be considered as a powerful tool to Federal lands from 5 percent of total U.S. domestic be employed in concert with the more traditional fields production in 1955 to 18 percent in 1980. The share of of geology, engineering and business. Better estimates energy production by commodity from Federal land is mean better decisions - and with measurements of presented by state and compared with total energy precisions, decisions on investing in more information production by commodity and state. (e.g. from additional drilling) can be handled more rationally. Table 1, summarized from the report, shows the energy production share from Federal land and compares it with In articles in subsequent issues of the Synthetic Fuels total domestic production for oil, gas, coal, and uranium Report some of these applications will be explored. as well as the royalties paid to the government for 1980. Cases to be illustrated in oil shale will be variogram According to the report, the government has collected construction, validation of samples through re-estima- about $4.7 billion in royalty from oil,gas, coal, and tion (jacknifing) and comparison of error of estimation uranium. What the report does not show are bonus bids, given differing block sizes. In coal, we will explore annual rentals, and licensing and permitting fees. In optimum sampling geometries, estimation of seam addition, the report does not present revenue from geo- oriented mining blocks and how to estimate the risk thermal leases or the production of hydroelectric power. associated with not fulfiling contract specifications During 1980 federally administered hydroelectric power (the unit-train rejection problem). In tar sands, we will made up 47.8% of total U.S. production of hydroelectric investigate concepts of precision, how sampling density power. impacts on local and global estimate reliability, and how the inclusion of better geologic models enhances The report is, however, a handy reference guide for the quality of estimates. energy production numbers and is available from the Superintendent of Documents, U.S. Government Printing Vocabulary Office, Washington, D. C. 20402. As in any new field, geostatistics has generaed its own unique lexicon. To help the general reader in understanding this new field a short glossary may be found in the Appendix to prepare the reader for future articles.

FEDERAL LAND ENERGY RESOURCE DATA PUBLISHED

A 254 page report published by the Department of Interior, "Energy Resources on Federally Administered Lands," contains statistical data on oil and gas, coal hydroelectric, uranium, oil shale, tar sands, geothermal,

TABLE 1 SUMMARY OF ENERGYPRODUCTION & ROYALTIES 1980 Royalties Total U.S. Federal Land Paid To Production Production Govt. (MM $)

Oil (million Bbls) 3,719 508.5 2,960.7 Gas (trillion Ft3) 19.3 5.8 1,652.9 Coal (million tons) 835.4 92.9 40.1 Uranium (million tons ore) 16.7 3.1 9.8 4,663.5

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-17 INTERNATIONAL

JAPANESE INVOLVEMENT IN SYNTHETIC FUELS some 150 industrial companies. It conducts "paper" SIGNIFICANT studies on energy alternatives and has major current programs in fuel-methanol markets/applications, feasi- Pace representatives attended the Pan-Pacific Synfuels bility of conversion of Indonesian coal to methanol, coal Conference in Tokyo, Japan, November 17 - 19, 1982. gasification/combined cycle potential, and a geothermal Several additional contacts were made with represen- assessment in Indonesia. Additionally lEE is conducting a tatives of Japanese companies and agencies involved in comprehensive evaluation to develop a recommendation development of synthetic fuels, continuing our efforts on one coal liquefaction technology to sponsor of three to stay abreast of synthetic fuels developments world- being considered. lEE also prepares energy forecasts and wide. is determining the potential for direct coal combustion in Japan. The Japanese have a significant and growing program in synfuels at all levels from basic research to participa- 2. New Energy Development Organization (NEDO) - tion in commercial or near-commercial projects. Over NEDO is responsible for much of the technological forty industrial companies and several governmental developments in synfuels. This organization is funded agencies are involved in synfuels activity. There is two-thirds by MITI and one-third by industrial companies. considerable sharing of information among participating NEDO is sponsoring applied research in coal conversion, companies and agencies with emphasis on improvements geothermal energy, solar energy, hydrogen for fuel, and in existing technology. The Japanese are also involved electricity storage using advanced batteries. in information sharing and cooperative programs with several other nations, including Brazil, Indonesia, and NEDO has extractive coal liquefaction test facilties at China. A strong indication of Japan's interest in Akadaira and Hazaki, Japan and component research on synfuels is evidenced by the attendance at the Pan- coal liquefaction at Ichidawa and Amagasaki, Japan. Pacific Synfuels Conference - of about 560 attendees NEDO operates a Brown Coal Liquefaction pilot plant in from around the world, approximately 450 were from Victoria, Australia and conducts applied research on Japan. Japan could easily become a leader in synfuels Brown coal conversion at their test facilities in Japan technology and projects with continuation of its current (Yaehiyo, Yokohama, and Kobe). NEDO is developing its program combined with the corresponding slowdown in own version of solvent refined coal processing called synfuels developments and project postponements in the Solvolysis in test facilities at Hiroshima and Nagasaki, United States, Canada, Europe, and Australia. Japan and is conducting research on this process at Kitakyushu, Japan. NEDO is also involved in direct coal Much of the synfuels involvement by the Japanese is liquefaction at a test facility in Kawasaki and in this influenced by its national policy to cut its dependence research at Hitachi, Tsuchiura, Ichihara, and Fugi, Japan. upon imported crude oil from about 70 percent of total energy currently to less than 50 percent by 1990. JapaneseSynfuels Projects - The Japanese are active in Japanese trading and industrial companies additionally development of coal conversion projects in the United have set themselves a course to be at the forefront of States and Australia, and in oil shale in Australia: Addi- synfuels technology. The Japanese also have other tionally the Japanese are participating in tar sands major programs in conservation, solar energy, biomass, research in Canada. direct coal combustion, hydrogen, advanced batteries, and fuel cells to further reduce dependence upon A consortium of Japanese companies participated financi- imported crude oil. ally and technically in the Exxon Donor Solvent and Solvent Refined Coal (SRC-II) coal-liquefaction develop- Since the Japanese have few natural resources other ment programs in the United States. The Japanese have a than some coal production comprising less than 5 similar involvement in the Cool Water coal conversion percent of total energy, with a projected decline in the project in California. The Exxon project is being slowed future, synfuels activity is focused upon small-scale significantly at the end of 1982 and the SRC-II program research in Japan and participation in a variety of was discontinued in 1981. The Cool Water project is still projects outside Japan. Highlights of current activity active. include: Japanese groups are participating in three coal conversion Japanese Synfuels Research - Synfuels research is being projects in Australia and one in Indonesia - all are on carried out at major Japanese universities and govern- low-quality Brown coal and at an early stage in development/quasi-government agencies: ment. The NEDO project was mentioned above. The Nippon Brown Coal Liquefaction Company has started 1. Institute of Energy Economics (lEE) - this agency is construction of a 50 ton per day pilot plant in the Latrobe strictly a research organization funded one-third by the Valley of Victoria, Australia. Mitsui/CSR, Ltd. of Japanese government (as an adjunct to MITI - Ministry Australia has extended its test program in Queensland, for International Trade and Industry) and two-thirds by Australia and is now conducting addtional marketing,

1-18 SYNTHETIC FUELS REPORT, DECEMBER 1982 technology and resource studies to determine the WORLD BANK SEES METHANOL AS OPPORTUNITY feasibility and economics of a major project. The FOR DEVELOPING COUNTRIES Institute of Energy Economies is particpating in a joint feasibility study for conversion of low-quality coal to The World Bank recently published a report" "Emerging methanol with an Indonesian governmental agenc y. Ube Energy and Chemical Application of Methanol: Industries, Ltd. recently announced it will use a Texaco Opportunities For Developing Countries." The report gasifier for a coal-to-ammonia plant to he built in Ube analyzed the current and potential uses of methanol as City, Japan. well as technology, raw materials and production costs. Worldwide supply, demand, and price prospects for In oil shale, a consortium of 40 major Japanese methanol were also analyzed. Finally the opportunities companies (including oil, trading, steel, cement, and for developing countries were identified as was the role other heavy industry companies) is sponsoring a $24 the World Bank should play. million, 2-year feasibility study jointly with the owners (Southern Pacific Petroleum) of the Condor shale One of the main points of the report is that 80 percent of resource in Queensland, Australia. The Japanese con- the existing world methanol capacity is based on natural sortium is incorporated as Japanese Australian Oil gas. Large-scale production of coal-based methanol Shale Company, Ltd. (JAOSCO). plants is unlikely before the end of the 1980's. Many of the developing countries possess significant amounts of This study will encompass mining, crushing, retorting, natural gas which, because of surplus availability and/or and upgrading studies and include technical, economic, lack of economic transportability, has an economic value environmental and market analysis. Engineering, tech- below the calorific equivalence of petroleum products. nical and management talent is being supplied from the Consequently methanol could be economically produced in various Japanese companies and Southern Pacific plants significantly smaller than those necessary for coal- Petroleum for the Condor project. At this time con- based methanol production. sideration is being given to four retorting technologies available for license from United States companies. In the September 1982 Pace Synthetic Fuels Report, Pace The Japanese government is also playing a major role in identified potential uses of methanol. The World Bank the Condor project since the quasi-governmental report also looks at potential uses as well as projected company, Japanese National Oil Company, is providing demand worldwide. More than 95 percent of today's a considerable portion of the cost of the $24 MM methanol market is in chemical applications. Two new feasibility study. applications were established during the 1970's. The main new application has come from the commercialization of Paralleling the JAOSCO - Southern Pacific Petroleum a new and significantly more cost-effective process route feasibility study, a separate company (Japanese Oil from methanol to acetic acid, which has been tradition- Shale Engineering Company - JOSECO) is conducting ally made from other raw materials. By the late 1980's major research, development, and technical studies of the report foresees that all acetic acid capacity will be oil shale processing technology. Participation in this methanol-based. Similar switches to methanol as a basic consortium is approximately the same 40 companies petrochemical feedstock in the production ofother involved in JAOSCO. JOSECO is calling upon the chemicals currently made from ethyle ne and other talents of the technical personnel from its member common petrochemical raw materials are being envisaged companies and is investigating three oil shale for the longer term. processing technologies including one new process which has not been formally announced. Research is Another potentially significant use is in producing single- being conducted on both Australian and U.S. oil shales cell protein as a high quality animal feed supplement. in bench scale and test facilities. JOSECO hopes to select the one best technology before the Condor In 1980, Im perial Chemical Industries (ICI) commissioned feasibility study is completed. a 50,000-75,000 tpy single-cell protein (SCP) plant in the United Kingdom. The process is based on methanol The Japanese have only minor involvement in Canadian feedstock which bacteria transform entirely, leaving tar sands in the PCEJ and Primrose projects. Both are virtually no hazardous leftovers. The product of the ICI at an early stage involving specific research studies. plant is now for sale in Western Europe as a high quality animal feed supplement. Compared to fishmeal, SCP Conclusions reportedly results in small but important increments in liveweight gain and feed-conversion efficiency in chicken, It is apparent that the Japanese have a major synfuels slightly greater ones in pigs, and surprisingly large live- program involving many major companies and thousands weight gains in fish. At today's prices, the product cannot of individuals. Continuation of the current program economically compete with soya protein and fishmeal, but will likely lead to technical advances and improve- in early 1980 ICI announced a breakthrough in SCP ments, particularly in coal conversion and oil shale. research via recombinant DNA techniques increasing the The United States may be importing newly developed carbon efficiency of the bacteria. ICI is said to plan a Japanese synfuels technology before the end of this second 300,000 tpy Se p plant based on the prospects of century. its becoming competitive, particularly in the fishmeal market, as the world protein supply situation tightens in the medium-to long-term. With about two tons of methanol needed for one ton of SCP according to the report, this particular use might become a significant chemical outlet for methanol, although in all likelihood

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-19 only in Western Europe, and perhaps in the U.S.S.R. and pricing scheme and of such other financial or tax schemes in Eastern Europe during the 1980's. as might be envisaged. The report presents a worldwide forecast of demand for "The Bank will also make efforts to attract suitable methanol based on World Bank estimates, as well as on foreign partners and/or foreign financing through the the growth forecast contained in various industry and umbrella of its own financial participation, where justi- government studies for the chemical uses of methanol. fied; commercial cofinancing should be sought for an A downward adjustment has been made to reflect the export-oriented methanol or MTBE project, even where relatively low GM' growth rates forecast in the World the joint-venture concept is not adopted. Bank's World Development Report 1981 for developed countries, i.e., at best only about 3 percent to 3.5 "Finally, the Bank can help develop the host country's percent per year during 1980-1990. Table 1 gives the research and testing effort with regard to domestic World Bank forecast. chemical and fuel applications of methanol. This assistance can comprise studies, or the financing of pilot Role of the World Bank Given projects, and general support in defining and evaluating the programs to be undertaken. The World Bank headquartered in Washington, D.C. was established in 1945 as the International Bank for Recon- "The Bank's active support of economically justified struction and Development (IBRD). The bank finances methanol or MTBE projects will concentrate on a few its lending operations primarily through its own borrow- countries. Even if support is so limited, it may encourage ings on capital markets, retained earnings, and loan exploitation of this potential in a larger number of repayments. Loans are specifically directed toward countries. The Bank will also facilitate the transfer of those developing countries considered to be in more experience with methanol projects and programs among advanced stages of economic and social growth, such as the developing countries. Indonesia and Brazil, and are generally repayable over a period of 17-20 years with an interest rate commen- "Finally, Bank support for methanol production programs surate with the bank's borrowing. To help less financi- will complement increased Bank lending for the develop- ally secure countries, the International Develpment ment of conventional energy sources such as petroleum, Association (IDA), an affiliate of the World Bank, was coal, and hydropower and provide a basis for developing created in 1960. the export base of gas-rich developing countries. Given the topical nature of the subject, and the continuing IDA countries must have an annual per capita GNP of uncertainties about future energy supplies and prices, less than $731 (1980 dollars), such as Bangladesh and support for methanol projects by the World Bank Group Pakistan. There are close to 50 countries that are will be based on a careful evaluation of all factors that eligible for IDA credits, which are usually repayable influence their viability. In most cases, such evaluations over a 50-year period at no interest, except for a small can be made only after detailed country reviews." surcharge. Over 80 percent of IDA loans go to nations with an annual per capita GNP of less than $360.

Loans for energy development have increased over the years with 25.8 percent of the total loads in 1982 for energy development. The role of the World Bank is identified in the report as follows:

"The Bank can play an important role in assisting gas- rich developing countries in evaluating the potential, prospects, and viability of methanol production. In most cases, initial assistance would be in the form of undertaking preliminary gas-utilization studies so as to evaluate the relative merits of gas use for power generation against those of methanol, ammonia and ammonia/urea, and, where there is an option, LNG production. The Bank has already performed or commissioned studies of this type in a number of countries. "The Bank can also help develop the investment policy measures and gas-pricing policy to be followed for potential methanol projects or for other future gas- based projects, in countries that have major gas development and utilization programs. The evaluation of methanol projects would also include a study of the sharing of benefits from the project under various scenarios, to ensure that an equitable sharing situation will emerge from the application of the proposed gas

1-20 SYNTHETIC FUELS REPORT, DECEMBER 1982

TABLE I

CURRENT AND PROJECTED DEMAND IN ESTABLISHED CHEMICAL METHANOL APPLICATIONS FOR THE U.S., WESTERN EUROPE, AND JAPAN (in thousand tons)

1979 1985 1990 Western Western Western USA Europe Japan USA Europe Japan USA Europe Traditional Uses

Formaldehyde 1,315 1,600 625 1,615 1,910 770 1,920 2,215 915 Solvent 300 270 itO 370 320 130 440 370 150 Dimethyl Tereph- talate (UNIT) 150 160 40 160 180 35 170 200 20 Others 1,140 895 285 1,400 1,070 340 1,660 1,140 395 Newly Estabished Uses Acetic Acid (AA) 275 25 - 500 260 170 850 550 170 Single Cell Protein (SCP) - 5 - --- 150 - - 650 -

Total, Established Chemical Uses 3,180 2,955 1,060 4,045 3,890 1,445 5,040 5,225 1,650 Growth Rate per year 1979-85 4.1 4.7 5.3 1985-90 4.5 6.1 2.9

SYNTHETLC FUELS REPORT, DECEMBER 1982 1-21 GOVERNMENT

SYNTHETIC FUELS CORPORATION ANNOUNCES on page 3-5 of the September 1982 Pace S ynthetic Fuels PLAN TO ASSIST THREE PROJECTS Report. At the December meeting of the Synthetic Fuels Maximum obligation for the Santa Rosa project is $41 Corporation, Edward E. Noble, Chairman, announced million. The loan guarantee is $20 million. The price that as a result of the actions of the Board of guarantee is for the earlier of 8 years or 6 million barrels Directors, he plans to issue letter-of-intent to three of aggregate product. Initial price guarantee is $21 projects: First Colony, Calysn, and Santa Rosa. million. This amount will increase as the loan is repaid up to a maximum of $41 million. The Corporation will The Board had previously earmarked $6 billion for coal, participate in revenue sharing. $3 billion for oil shale and $1 billon on tar sands and heavy oil. The Calysn and Santa Rosa projects will be Calsvn Will Receive Loan Guarantees funded through the $1 billion earmarked for tar sands. The First Colony project comes under the definition of The 5,100 BPD project proposes to construct a Dyna- Section 131(u) ("other monies") of the Energ y Security cracking unit and demonstrate operability on petroleum Act leaving the $6 billion for coal and the $3 billion for resid, heavy oil, and tar sands bitumen. For a more oil shale intact. According to Ralph Bayer, Vice detailed description see page 3-2 of the September 1982 President of Projects for the Corporation, First Colony Pace Synthetic Fuels Report. Calysn will negotiate for a fits into the SFC picture as a "significant resource loan guarantee of up to $50.5 million. base." Other Board Action Concerns Remaining Projects First Colony Gets Loan and Price Guarantees In other actions on projects, the Board granted the The First Colony project is a proposed 4,600 BPD peat - Hampshire coal liquids project a waiver until April 1, 1983 to methanol project under the partnership of Energy to continue negotiating under the first solicitation, but it Transition Corp., Koppers Company, Inc., J. B. Sunder- voted to remove the Breekinridge project from the first land, and Transco Companies, Inc. and second solicitations. I3reckinridge sponsors subsequently decided to suspend the project. In their A detailed description of the project planned for announcement of this action, Ashland cited the effects of Creswell, N.C. is on page 4-15 of the June 1982 Pace recent tax law changes which have reduced the potential Synthetic Fuels Report. tax benefits associated with the project. See page 4-1 of the June 1982 Pace Synthetic Fuels Report for more The maximum SFC obligation to the First Colony details on Breekinridge. project will be $465 million including money provided under Section 131(u) of the Energy Security Act. The The Hampshire project has also subsequently been ter- cost sharing agreement provides for a maximum of minated. A detailed discussion of the Hampshire project $4.65 million to be available December 1982 through can be found in the Coal Section. February 1983. This motley will be used to refine the design so as to improve the accuracy of estimated Of the other projects that had been in Phase II of the costs. The design of the gasifier cooling train will be second solicitation, four projects, Coolwater, Hop Kern, among the subjects addressed. Kensyntar, and North Alabama were continued in the second solicitation review process, while four others, In addition, $341 million t $25 million interest accrued Paraho, Enpex-Syntaro, Sunnyside and New England will he provided under the loan guarantees. The price Energy Park, were removed but are encouraged to reapply guarantee, with 15 years maximum life, is renegotiable in the third solicitation. after 10 years. The initial price guarantee is $99 million. This amount will increase as the loan is repaid Edward E. Noble, Chairman of the Corporation in making up to a maximum of $440 million. The Corporation will the announcements regarding the project said: "The third participate in revenue sharing as price increases above solicitation, which closes January 10, 1983, is expected to the guaranteed level. attract a minimum of 30-40 projects, about half of which will be new submittals. These projects are expected to Santa Rosa Gets Price and Loan Guarantees include all the major resource bases eligible under the Energy Security Act. Further, a number of them appear The Santa Rosa Oil Sands project ;nvolves surface to be of particular interest in terms of their maturity mining of the oil sand deposit near Santa Rosa, New levels and/or their programmatic fit." Mexico and solvent assisted, hot water extraction to recovery the bitumen. The plant size is 4,000 BPI) of bitumen. A more detailed description of the project is

1-22 SYNTHETIC FUELS REPORT, DECEMBER 1982

SYNTHETIC FUELS CORPORATION OUTREACH this initiative, it will have been of immense value to our INITIATIVE DESCRIBED country." Jimmie Bowden was appointed Executive Vice President As part of this program, Victor A Schroeder, President of the Synthetic Fuels Corporation (SFC) in August. As and Chief Operating Officer of the SFC discussed possible Executive Vice President, Bowden will report directly Japanese involvement in the development of a U.S. to Corporation President Victor A. Schroeder and will synthetic fuels industry at meetings in Tokyo, Japan in oversee the day-to-day operations of the corporation. November. Bowden brings to the Synthetic Fuels Corporation more Prior to his arrival in Japan, Mr. Schroeder meet in than 20 years of diverse experience with Conoco, Germany with executives of Ruhrkohle A.G. to brief them Incorporated. Prior to becoming Vice President of on the Synthetic fuels Corporation and its role in assisting Government Relations with Conoco Chemicals the development of synthetic fuels. Company, he served from 1974-80 as Vice President, Executive Vice President and President of Conoco Coal 1t ## # Development Company. During that time, he managed the research and commercial phases of an effort aimed SYNTHETIC FUELS CORPORATION ELECTS OFFICERS at the commercialization of coal-based synthetic fuels processes and advanced methods of coal utilization. At the December meeting of the Synthetic Fuels Corpora- From 1972-74, Bowden was Executive Assistant to the tion, the following people were elected to the position as Executive Vice President of Conoco, Inc. and from noted: 1966-71, he was President of Conoco, Plastics. Victor A. Schroeder In his first report to the Board of Directors of the President and Chief Operating Officer Corporation in December, he described what he termed the Outreach Initiative in preference to outreach pro- Jimmie R. Bowden gram. He said the outreach program "implies a plan Executive Vice President with a beginning, middle and end and with a well defined goal in mind. By contrast, our Outreach Leonard C. Axelrod Initiative is a continuation and amplification of our Vice President for Technology and Engineering communications with industry and, to a lesser degree, with Congress and the public." He commented on the Ralph L. Bayrer initiative with industry, describing what it is not as it is Vice President for Projects misunderstood. "It is not, as some have characterized it, an attempt to find equity for projects which the Charles A. Cowan, Jr. sponsors cannot fund themselves. It is not an effort to Senior Vice President for Projects find a project to support before Congress changes its mind, decides our long range energy security is less Dwight A. Ink important than short term politics and raids our Vice President for Administration and Treasurer treasury. It is not an attempt to find foreign homes for domestic technology. Edward F. Cox General Counsel and Secretary "It is an effort to contact industrial leaders, not only synfuels enthusiasts, and to persuade that leadership Darrel W. Lundquist that the present management of the SFC intends to Vice President for Planning discharge its statutory responsibiities to assist the infant synthetic fuels industry in its formative years; Edward S. Miller that the SFC understands and is sensitive to the needs Vice President for Finance of that industry; and that the SFC intends to exhibit substantial flexibility within its statute to accomplish William F. Rhatican this task. In addition to the signal that "all channels Vice President for External Relations are open" the SFC Outreach Initiative will transmit substantive guidance to industry through its future targeted solicitations. These solicitations will provide unmistakable guidance to industry in the form of clear statements of the needs of this nation for synthetic ENERGY PREPAREDNESS ACT MANDATES fuels and a measure of the work of these fuels to our DESCRIPTION OF PRESIDENTIAL AUTHORITY IN country." ENERGY CRISIS He commented further that "Although the Outreach On August 3, 1982 President Reagan signed S-2332, Public Initiative is a fundamental and necessary component of Law 97-229, "The Energy Emergency Preparedness Act of the SFC program, we may never be able to identify a 1982" into law. The importance of this law is that it project which was completed only because of the initia- extended the Energy Policy and Conservation Act (42 tive. We should anticipate that our encouragement will U.S.C. 6272) to December 31, 1982 and amended it by make the difference only in borderline cases. However, adding Part C - Energy Emergency Preparedness. (See if we convert only one "leaner" into a "ringer" through the Appendix)

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-23 In the amendment, Section 271(b) states Congress Energy Conservation Act of 1979, and the Export intent as follows: Administration Act of 1979. Each of these is discussed in detail. In addition, numerous miscellaneous statutes such "(b) POLICY - The Congress declares that its shall be as the Public Utility Regulatory Policies Act of 1978, the the policy of the United States that the Federal Powerplant and Industrial Fuel Use Act of 1978 the Government shall be prepared prior to any shortage of Federal Power Act, and Natural Gas Act, the Natural Gas petroleum products to respond to energy emergencies, Policy Act, the Mineral Lands Leasing Act, the Outer pursuant to authorities under provisions of law other Continental Shelf Lands Act, the Clean Air Act, the than this part, as a supplement to reliance on the free Interstate Commerce Act, the Disaster Relief Act of market to mitigate the adverse impacts of a shortage 1974, the Magnuson Act, and the Foreign Assistance Act of petroleum products on public health, safety, and of 1961 are also covered. welfare." The memo discusses at length Section 101(c) of the To assure Congress that the policy is carried out, the Defense Production Act, 50 U.S.C. App. par. 2071(e), Act mandates that the President submit to Congress by which provides that the President may require the alloca- November 15 a memorandum of law which describes the tion of, or the priority performance under, contracts or nature and extent of the authorities available to the orders relating to "supplies of materials and equipment in President under existing law to respond to a severe order to maximize domestic energy supplies," if he makes energy supply interruption or other substantial reduc- certain findings with respect to the need for the materials tion in the amount of petroleum products available to for either the exploration, production, refining, the United States. transportation, or conservation of energy supplies, or for the construction and maintenance of energy facilities. Further, he should also submit to the Congress compre- The President's authority under par. 101(c) may be hensive energy emergency response procedures for exercised "notwithstanding any other provision of this implementation, in whole or in part, of the authorities Act," and therefore is not subject to the "national described under subsection (a) by December 3, 1982. defense" requirement of par. 101(a) or the constraints The memorandum dated November 15, was prepared by imposed by par. 101(b), 50 U.S.C. app. par. 2071(a), (b). the Office of Legal Counsel of the Department of This section thus provides some authority for the Justice, at the direction of and under the supervision of President to allocate materials in the civilian market, or the Attorney General, in consultation with the Depart- to require priority performance of contracts, that is not ment of Energy. Assistance was also provided by the dependent on a national defense nexus or the findings Antitrust Division and Land and Natural Resources required by par. 101(h). Division of the Department of Justice, theDepartment of Defense,.the Department of State, and the Federal The memo discusses whether Congress intended that par. Emergency Management Agency. 101(e) be used to allocate supplies of energy sources, such as Petroleum Products. The memo notes that the The memorandum analyzes the primary statutory authority in this section is limited by the requirement authorities that would be available to the President in that the allocation be necessary to "maximize domestic the event of a severe energy supply interruption. In energy supplies." addition to describing the requirements, scope, and limitations of those statutory authorities, legal issues The memo also reviews the authority under par. 710 of specifically raised by Congress during consideration of the DPA, 50 U.S.C. app. par. 2160. Accordingly, the the EEPA are also addressed. The memo notes that President may, subject to certain restrictions, authorize "the available statutory authorities generally provide the training and employment of persons from the private the President with broad discretion to determine if, sector in order to facilitate planning for and responding to when, and how they should be exercised, taking into energy emergencies. Two methods of facilitating such account the facts of any future energy emergency and training and employment are authorized by this section. the President's best judgment as to how to prevent or Subsection (b) permits the President to employ "persons of deal with the emergency situation." outstanding experiences and ability" to serve without compensation in advisory positions for purposes of Statutory Authority Analyzed assisting in carrying out the purposes and provisions of the OPA. Id. par. 2160(b). Subsection (e) authorizes the The memo is useful in that it outlines the terms of the establishment and training of a "nucleus executive authority provided by the statutes to the President and reserve" ("Executive Reserve") for employment during any limitation on that authority. "periods of emergency." Id. par. 2160(e). Use of these authorities to obtain advice and assistance from the Among these authorities, the Energy Policy and Con- private sector in planning for or responding to an emer- servation Act, the Defense Production Act of 1950, and gency caused by a petroleum shortage raises two legal the Trade Expansion Act of 1962, provide the President, issues: (1) the circumstances under which these authori- in a petroleum emergency meeting the requirements of ties can be used; and (2) the applicability of conflict-of- those statutes, with some specific authority to affect interest and antitrust laws and regulations. or control the distribution of petroleum products, a well as other authority to mitigate or plan for such an ED. NOTE: From the standpoint of synthetic fuels and emergency. Additional authority that may be available the Department of Defense, the memo should have to the President, depending on the circumstances of any addressed the President's authority to develop the Naval petroleum emergency, is contained in the International Oil Shale Reserve by applying authority granted in these Emergency Economic Powers Act, the Emergency

1-24 SYNTHETIC FUELS REPORT, DECEMBER 1982 two sections long before an emergency situation pre- "The Energy Tax Act of 1978 is a legal expression of eludes a crash development. national policy to speed up the timetable of synthetic fuels development. Similarly, the Energy Security Act of 1980 provides for government price, loan, and purchase guarantees through the Corporation and it provides for the DOE Interim Fast-Start Program. The purpose here is CONGRESSIONAL RESEARCH SERVICE REPORT to lessen the enormous degree of financial risks that a LOOKS AT SYNFUELS INDUSTRY PROBLEMS sponsor of a synthetic fuels project faces. These risks include uncertainty over the time-path of oil prices The Congressional Research Service published the re- through the next quarter century, the technological risks sults of a seminar entitled "United States Synthetic that have been spoken of associated with taking a Fuels Corporation and National Synfuels Policy" in July synthetic fuels technology from the pilot stage to the full 1982. The seminar was co-sponsored by the Sub- commercial scale, and the regulatory delay risks that are committee on Fossil and Synthetic Fuels and the Con- so costly to any large construction project. Like the gressional Research Service (CRS). Energy Tax Act of 1978, only more directly, the energy Security Act of 1980, passed with broad bipartisan Dr. Paul Rothberg of the CRS emphasized three points: support, is a legal expression of national policy to hasten the timetable of commercial synthetic fuels production." 1. In terms of strategic planning for our Nation's future energy supply, it seems realistic to expect an He suggested that if the industry is to move ahead quickly average synfuels production level of no more than then the following legislative and administrative actions 100,000 barrels per day by 1987. Indeed, if this need to be taken: level of production is reached, industry and SFC would have achieved a major technological and "First, Congress should keep the energy investment tax economic accomplishment. credit and expand it to cover all of the property instead of certain portions, of a commercial synfuels plant. 2. Even in light of the SFC program, the decontrol Companies should be allowed to depreciate equipment of oil, and the tax advantages contained in the used in a plant as soon as the equipment is purchased. Economic Recovery Tax Act of 1981, industry has (Currently, depreciation cannot begin until the plants are not invested over the last year substantial amounts in service, and this tax policy adversely affects projects of new capital into additional synfuels projects. The with long lead times.) Third, SFC must continue to hire bottom line is that much of industry is still watching the best personnel possible in order to conduct its from the sidelines and waiting for SFC to extend the important program. And finally, Congress and the Reagan welcome hand of Uncle Sam. Administration could indicate their support for continuing the national commitment to stimulate synthetic fuels, 3. The 22 or so Federal laws that will regulate the thus reducing some of industry's uncertainties regarding synfuels industry are the least developed and the investments in synfuels plants." least specified parts of our National Synfuels Policy. Lawsuits, court injunctions, and other delays stemming from these regulatory policies, as well as uncertainties regarding EPA's and DOE's environmental role, could adversely affect both SFC's HODEL CONFIRMED AS NEW SECRETARY OF THE program and industry's production efforts. DEPARTMENT OF ENERGY

He also commented that the SFC was only one com- Donald P. Hodel was sworn in as Secretary of the Depart- ponent of the total National Synfuels Policy. Other ment of Energy on November 8. His appointment was Federal regulatory agencies, such as the Environmental approved by the Senate on December 8. He replaced Protection Agency, the Occupational Safety and Health James B. Edwards who left office without achieving his Administration, the Federal Energy Regulatory Com- goal of dismantling the DOE. Congress, however, mission, will also heavily influence the rate of growth received President Reagan's Federal Energy Reorganiza- of this Nation's synfuels industry. tion Act of 1982 in May. (See page 1-3 of the June 1982 Pace Synthetic Fuels Report.) Little progress has been Marshall Koleda, President of the National Council of made in passage of the bill since then. Synthetic Fuels Production focused on the timetable for commercial synthetic fuels development. He said: Hodel, a graduate of Harvard, was former Undersecretary of Interior and has been an energy consultant. He also "Tax incentives; SFC price, loan and purchase guaran- served as Administrator and Deputy Administrator of the tees; and the efforts to provide a greater degree of Bonneville Power Administration, as well as Director of regulatory certainty for the industry are all elements of the Electric Power Research Institute. a national policy affecting the timing of synthetic fuels production. The Energy Tax Act of 1978 provides a ten percent investment tax credit for certain property associated with a synthetic fuels plant. It serves to GAO REPORT FAULTS DOE FOR NOT PERFORMING make the economics of synthetic fuels projects more ACCORDING TO STATUTE favorable and thereby tends to hasten the time at which synthetic fuels plants are likely to be built. In a study released in July, the General Accounting Office (GAO) faulted the Department of Energy (DOE) for not

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-25 using Net Energy Analysis (NEA) in funding new energy The report states that, "No data were available from DOE technologies. The Federal Nonnuclear Energy Research that presented the indirect energy required in the energy and Development Act, of 1974 (Public Law No. 93-577 facilities we evaluated. Although data were available on commonly called the Nonnuclear Act), requires DOE to the direct energy inputs (such as fuels and electricity) to consider the net energy to be produced by a proposed the facilities, we were given no estimates for the indirect technology before granting funds to such projects. energy required to construct, operate, and maintain coal Also, Title II of the Energy Security Act of 1980 (Public liquefaction and ethanol production facilities. We needed Law No. 96-294) requires that both gross and net indirect energy measures for energy to manufacture and premium fuels be a major consideration in DOE's construct the facilities, energy to mine, manufacture, or funding decisions of certain biomass energy tech- farm the raw material and energy products used in nologies. operating and maintaining the facilities, and energy to transport the raw materials and products to and from the The GAO report argues that DOE has not used net facilities. We compensated for this lack of data by using energy analysis (NEA) in its proposal evaluation pro- process analysis and 1-0 (Input-Output) analysis to cess, and it has initiated major technological develop- estimate the indirect energy required at each stage of a ment and procurement processes without first estima- facility's production trajectory. However, such approxi- ting which ones most efficiently produce premium fuels mations are only illustrative of the methodology; they are that can reduce U.S. dependence on foreign supplies. not conclusive estimates of the net energy yields of the Further the report faults the DOE for not having facilities we analyzed." provided the leadership and the analytical support needed to implement and refine the methodology for GAO further stated: "The quality of data provided to conducting a NEA. DOE on the proposed technologies cannot be quantified, because the proposal documents provide no quantitative In the report, the GAO examines the methodological uncertainties associated with point estimates of cost, feasibility and usefulness of net energy analysis by performance parameters, material inputs, and final specifying a methodology and performing the NEA for products and byproducts. Furthermore, there is no four coal liquefaction processes, (Sac I, Sac ii, H-Coal evidence of specific DOE requirements to insure that (1) .and Exxon Donor Solvent), and two ethanol processes. bidders use similar or comparable cost-estimating methods, based on acceptable levels of engineering effort, In developing the methodology, the GAO boundaries in developing proposals, (2) cost estimates are reasonably were set to exclude energy of labor, unregulated validated, and (3) bidders submit standardized and con- environmental impacts, solar energy, "boomtown sistent data on the energy and materials inputs and final effect," and end-use efficiency and technological products and byproducts. No additional cost burden to change. DOE would result from improving the data base. The deficiencies we mention here can be corrected by requir- (Ed. Note: In developing any net energy analysis, the ing quality data in proposal documents. The task of parameters or boundaries as GAO identifies them, are reasonably validating such data could be absorbed by the the most controversial determination. The extent that existing proposal review validating process." one includes certain factors is significant in the end result and the definition of indirect energy imputs all The report recommends that: "The Secretary of the important.) Department of Energy should issue directives necessary for: In GAO's analysis, six basic steps were followed: o insuring that similar or comparable cost-estimating • identifying target products and byproducts methods, based on acceptable levels of engineering • defining the trajectory of direct and indirect effort, are used in developing proposal documents energy inputs and that their results are tested for validity; • obtaining a data base • estimating the embodied energy of direct and o obtaining uniform data on the cost, performance indirect inputs and outputs along the trajectory parameters, energy, materials inputs, and final • calculating net energy results in terms of the products and byproducts of energy facilities in chosen measures of effectiveness, and proposal documents, along with their associated • comparing net energy yields quantitative uncertainties; While the report presents a good case, in addition to o developing the additional data base for the analysis statutory requirements, for using a net energy analysis, of indirect energy flows; perhaps the most important factor that GAO should focus on more intently is the inconsistency of data from o providing the net energy analysis on all tech- Department of Energy sponsored projects. The report nologies proposed under authority of Public Laws terms this significant pointing up the need for similar 93-577 and 96-294. or comparable cost-estimating methods, because inconsistency makes comparisons very difficult. Further, "Uncertainties exist regarding which Federal entities will "All proposals for projects should include standardized carry out future research, development, and demonstra- and consistent data on energy and materials inputs and tion activities. The recommendations above would also on final product and byproducts. apply to the administrators of succeeding agencies."

1-26 SYNTHETIC FUELS REPORT, DECEMBER 1982 The following recommendation was made to the Congress: "In Public Laws 93-577 and 96-294, the Congress expressd its interest in net energy analysis; we have demonstrated the feasibility and value of conducting such analysis; DOE has not conducted net energy analysis. Therefore, the Congress should require the Department of Energy, or succeeding entities, to demonstrate during oversight and appropriationsg hearings that the potential ability of proposed ener y technologies to produce net rather than gross premium fuels and energy at their commercial stage was analyzed and considered before DOE funded the development of those technologies." One point the report makes is that the authority for support of the Synthetic Fuels Corporation comes from title I of the Energy Security Act (Pub. L. No. 96-294), which does not require that net energy yields be considered in evaluating projects. Rather unfortunately the GAO does not recommend that a NEA be part of the response to the SFC solicitations, If this were the case, uniformity of data would be required for comparison, and the SFC would be better able to compare processes and justify their decisions.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-27 ECONOMICS

CHANCE IN METHODS OF COSTING SYNPUEL.S PLANTS PROPOSED

"A New Look at Cost Patterns For Synfuels" was presented by W. A. Samuel at the American Institute of Chemical Engineers meeting in June. In the paper he pointed out that there is no economic incentive for synfuels as conventional cost account always indicates that the cost of producing synfuels is significantly higher than the current price of imported petroleum materials. He states that "our bookkeeping and tax regulations work to the disadvantage of highly capital intensive'installations. A major cause for this effect lies in the tact that depreciation is charged oft at historical costs. As inflation rises, the present discounted value of the depreciation deduction from the tax liability falls. In other words, the number of dollars deducted from the tax liability at any point in time does not fairly represent that portion of the depreciable capital that it was intended to cover. The more years over which the plant must depreciate, the worse this effect becomes." Another point he made is that "there are very high prepaid tax components in the prices charged for capital items. These represent costs to the sponsors which must be recovered in DCF procedures under the current rules. Obviously, if these tax costs could be eliminated, the required product prices would drop." tie suggests that the "government promptly disburse or refund back to the project developers that portion of their expenditures that represents the flow of funds that has already found or will find its way to the Federal treasury." In addition, he would have "the producers exempted from paying income taxes at least until the investment, on DCP basis, is fully recovered." Perhaps his strongest point is made in arguing that this would not cost the treasury anything "for otherwise the plants will not be built. The treasury would have collected nothing in the first place. On the contrary, if the plants are built, the public in general, and the treasury in particular, will have benefited by the economic growth that has resulted. We shall have taken underutilized resources of capital, labor, and raw materials and employed them to make products of high utility -synthetic fuels."

1-28 5YNTdErIc FUELS REPORT, DECEMBER 1982 ENVIRONMENT

DOE'S HEALTH EFFECTS RESEARCH AND ANALYSIS HERAP is scheduled to continue as long as doubts remain PROGRAM LOOKS AT SYNFUELS regarding the uncertainties associated with health and environmental effects and the HERAP can make meaning- A little publicized Department of Energy (DOE) ful inputs to energy program managers. program which is now in its third year is emerging as one which promises to provide some long-sought HERA? Strategy guidance to decision-makers faced with installing new energy producing facilities, yet being unable to provide Dr. Barr is assisted by Dr. Paul Cho, and a management sufficient risk analysis of the health and environmental support contract with the Aerospace Corporation. impacts of such plants. The program is designed so that HERA? funds the analysis of about a dozen emerging all affected parties can discuss, understand, assess, and energy technologies each year, foremost among which are agree upon the risks involved, and industry can proceed Oil Shale and Coal Liquefaction, along with Photovoltaics, in a cost-effective manner. Batteries, Municipal Solid Waste Combustion, Geothermal Energy, Diesels, Fluidized Bed Combustion, Liquid Metals This program carries the acronym HERA?, and is Fast Breeder Reactors, and Space Nuclear Systems. Each housed in the Office of Health and Environmental of these topics is addressed by a contractor at the level of Research of DOE's Office of Energy Research. Headed effort of two to six person-years per year for each by Dr. Nathaniel P. Barr, a chemist/biophysicist, the technology. Contracted analyses describe what is known HERA? program is concerned with the analysis of and what is not known regarding the potential health and available information and has the overall objectives of environmental impacts of installing, operating and defining, expressing, and combining the various types of decommissioning industries planning to utilize emerging health and environmental uncertainties associated with energy technologies and capable of providing a significant the installation of emerging energy technologies. fraction of the national energy demand. The HERAP Program At the end of each fiscal year, the results of each investigation are sum maried in a fifty-page, technology- HERAP was initiated in 1980 and is funded at a level specific, Health and Environmental Effects Document exceeding $150 million per year, and involves research (HEED), supported with complete appendices of data. activities in the physical, ecological, biological and HEED project leaders are directed to concentrate their medical sciences. A substantial portion of the program analytical efforts on issues that bear directly on defining is devoted to acquiring information broadly relevant to uncertainties regarding the nature and magnitude of the understanding of processes basic to our ability to potential health and ecological impacts. They are identify and estimate the magnitude of potential instructed to avoid analysis of peripheral issues, such as environmental impacts of energy technologies (e.g., resource availability, socioeconomic impacts, and atmospheric processes, ecosystem structures and func- economic• and technical feasibility. They are also tions, mechanisms of action of toxic agents, etc.). directed to base their analyses on a reference industry capable of supplying about one quad per year of energy A significant portion of the program is directed at and to anticipate that the industry will operate in acquiring data and developing understandings which are compliance with existing and projected environmental required to reduce uncertainties regarding specific im- regulations and employ control technologies to reduce pacts of individual energy technologies or groups of unregulated emissions to levels which are as low as can be technologies (e.g., leachability of heavy metals from reasonably achieved. They are to avoid presenting processed oil shale, characterization of effluents from judgments regarding the acceptability of potential coal gasification plants, epidemiological studies of impacts or of uncertainties regarding their magnitudes. populations exposed to ionizing radiation, etc.). The HEEDs A basic objective of HERA? is to assist energy research managers to identify, manage, evaluate, and defend These we written to be read by technical research research programs by providing them with risk analyses managers familiar with the specific energy technology, which identify the nature and magnitude of current but expert in only a limited number of the scientific and uncertainties regarding potential health and ecological technical areas treated in the analysis. After publication, impact that could impede the cost-effective develop- the HEED is circulated widely by HERAP •staff to ment and operation of emerging energy technologies. interested parties in industry, government, and academia, In addition HERA? will provide a framework for evalu- who are invited to comment on its utility as a basis for ating how information provided by current and future research planning and to suggest how it might be research promises to reduce these uncertainties. improved. Project leaders then are asked to develop plans Reduction in the magnitude of these uncertainties is a for continuing analyses which reflect these comments and primary objective of the HERA?. suggestions. These revised plans then are discussed at an annual meeting of HERAP contractors. Dollar decisions

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-29 on each program then are made shortly after the annual effects control of a new plant to zero will result in meeting. application of Best Available Control Technologies, and cost-effectiveness be damned." The result of such A smaller portion of the HERAP program is devoted to approaches likely will be no plant. analysis of potential impacts of toxicants common to several emerging energy technologies and are intended Review of Heeds, December 1982 to support the preparation of technology-specific HEEDs (e.g., nitrogen oxides, organic water pollutants, Draft REED documents were circulated in November and hydrocarbon carcinogenicity, airborne particles, etc.). reviewed in one-half day sessions for each one during the The results of these analyses are presented annually and period December 1-10, 1982. Results of work conducted undergo the same peer review process. in 1982 were presented by the project leaders to a peer audience consisting of health effects and risk analysis A final portion of the HERAP program is devoted to the experts from government, academia and private industry. development of improved methodologies to support For each draft HEED, DOE has appointed a principal technology-specific and generic analyses. reviewer whose responsibility is to assemble all comments received and summarize them in time for the project HERAP Program Status leader to respond to those comments during the annual contractor's conference in Feburary. The first contractors meeting was held in February, 1980, at the inception of the program, and the fourth is The oil shale HEED document has been through several scheduled for February 7 through 9, 1983 (at the Key such iterations and will be the first HEED to be finalized. Bridge Marriott Hotel, Rosslyn, Virginia, just outside Approval and issuance is expected in mid- to late 1983. Washington, D.C.). During 1982, 12 technology-specific Pace staff attended the following three review meetings. and four generic HEEDs have been written; these were reviewed in detail in half-day sessions during early Hydrocarbon Carcinogenicity December, 1982, in preparation for the February 1983 contractors conference. This subject is generic to all fossil energy sources. The HEED assembled by Dr. E. A. A. Crouch and his Dr. Barr has initiated a program with the National coworkers at the Harvard University Energy and Environ- Academy of Sciences/National Research Council mental Policy Center, entitled, "Non-Regulatory and (NAS/NRC) to undertake a continuing review of the Cost-Effectiveness Control of Carcinogenic Hazard. The HEEDs; the first two of these will deal with synthetic Beginnings: A Methodology for Using Animal Data to fuels, specifically Oil Shale and Coal Liquefaction. Decrease Uncertainty in Human Risk of Carcinogens Released by Energy Technologies," was reviewed. In reviewing the status of his HERAP program after the December, 1982 HEED reviews, Dr. Barr said that the It has been conventional to look for human carcinogens by maturity of the HEEDS currently is such that they testing in animals, usually rodents because they are should not yet be used to serve decision-makers dealing mammals, to some extent similar to man, which have with technology development planning, regulatory con- rapid metabolisms and short lives, so that answers can be trol, NEPA compliance, priorities for national energy obtained quickly. However, there are now many known planning, setting public health policies, etc. Although a animal carcinogens, and the more sensitive the animal number of major energy companies now are participat- test, the larger the fraction of chemicals which fall into ing in the HERAP program, their initial reactions to a the carcinogen net. Since minute traces of many HEED is usually negative. For example, the oil shale chemicals nowcan be detected, the simple approach of industry is nearly ready to go, has dollars on the line, is prohibiting all human exposure to animal carcinogens in compliance with existing regulations and laws, and is leads to the impossible task of controlling all such minute now faced with what is perceived to be another govern- concentrations. Among the known carcinogens are many mental delaying tactic, an assessment of risks to public that are found naturally in the environment, even in food, health. some that are useful in energy-related industries, and some that are unavoidable by-products of energy use. To The best approach to such negativism, Dr. Barr feels, is prohibit the release of any carcinogen would be to ban complete and open discussion with the key principals most industrial activity. Control, therefore, must be developing the energy technology. One concept which applied selectively. has evolved during the HERAP program is that siting a new energy-producing plant at any location carries with One approach is to attend only to chemicals that come to it the risk of introducing a certain number of new the attention of regulators. However, this is considered cancers into the local environment. Defining these by the Harvard scientists to be arbitrary, with the risks, along with the uncertainties, is a primary objec- undesirable consequences of possibly insensitive and tive of the HERAP program. As soon asthe uncertain- poorly conducted experiments, leading. to controls which ties have been defined and quantified, the next step is are irresponsible and cost-ineffective. the development of data so as to be able to reduce the magnitude of those uncertainties, and allow the emerg- An alternative proposed by the Harvard group is to ing energy industry to develop on a more cost-effective assume that all chemicals are carcinogenic, each with a basis. potency that must be measured. A non-carcinogen is a chemical with zero potency. In practice, however, zero All parties should recognize the health and ecological cannot be measured, only an upper bound. Using impacts involved, Dr. Barr concludes. 'Setting health estimates of potency, exposure, and an interspecies factor

1-30 SYNTHETIC FUELS REPORT, DECEMBER 1982 (which also accounts for uncertainties in extrapolating This Oil Shale HEED is close to completion. After review from the animal data to man), an estimate of risk and at the contractors meeting in February, and review by the the uncertainty associated with that estimate is made, NAS/NRC (expected by June), the document will be together with upper bounds on the risk. If the upper finalized and released. bound is small, the risk is negligible and can be ignored. If it is large, then exposureat the level proposed should Direct Coal Liquefaction not be permitted. Further information then may be developed which can change the risk estimate or lower Two presentations were made, one by Dr. Peter J. the uncertainty, so that the upper bound of the risk can Mellinger of Battelle Memorial Institute's Pacific North- be reduced. In such an approach, the estimation of west Laboratory, the other by Dr. Philip J. Walsh of uncertainty is as important as estimation of a best DOE's Oak Ridge National Laboratory. Dr. Mellinger's value of risk. study estimated potential human health effects from inhalation of non-methane hydrocarbons (NMHC) that may Oil Shale be released from a future hypothetical industry producing about 600,000 bbls/day of synthetic fuel by direct lique- Summation of this HEED was presented by its principal faction of coal. The coke oven industry was selected as a authors, Dr. Lawrence B. Gratt, Project Leader, IWO surrogate for this study, because its emissions were Corporation San Diego, California, in conjunction with judged to approximate more closely potential coal lique- Dr. Willard R. Chappell, Program Manager, University faction emissions. of Colorado at Denver. Potential effects of a 1 MM bbl/day oil shale industry supplying 2.1 quads of energy Using the extensive epidemiological, environmental and operating in a steady state fashion by the year 2010 chemical data base for coke oven workers, estimates were were estimated. made of about 0.001 excess cancer death/year in the industrial work force of 7,800 persons, and 0.05 excess Results obtained indicate the occurrence of less than cancer death/year in the U.S. population as a whole from 450 fatalities per year in the combined occupational NMHC which boil above 600°F. workforce and general public. A health benefit in decreased premature deaths from the displacement of Sources of uncertainty in the estimates include: the rate imported oil by production of low sulfur shale oil as of release of high-boiling NMHC (2.4 to 2.6gjsec); the refinery feedstock was estimated to be 600. Therefore, magnitude of occupational exposures (2.4 x lob to 4.2 x oil shale technology represents a net health benefit to lob person-ng/m 3) and east central U.S. public exposures the public sector. This benefit is based upon a sulfate (9.5 x 106 to 1.7 x 108 person-ng/m3) resulting from dose-response model as a surrogate for all air release. The carcinogenic potency of high-boiling NMHC pollutants. is assumed to be the same as the potency of coke oven emissions. The estimated risk to the 41,000 oil shale workers is 17 to 140 fatalities per year, of which accidents will cause Using these uncertainties, it was estimated that from 10 to 19 fatalities, and occupational illnesses the 0.0002 to 0.005 lung cancer death/year may occur in the remainder. The occupational disease of key concern is industrial work force and from 0.01 to 0.25 lung cancer pneumoconiosis due to exposure to dust. This disease death/year in the U.S. population as a whole. On an may account for up to 50 percent of the estimated individual basis, the excess lifetime risk to occupationally deaths, with the remainder due to internal cancers, exposed workers was estimated to be 500 times greater chronic bronchitis, skin cancer, and airway obstruction. than to members of the U.S. public. It is also estimated that the industry will have 3,000 to 5,600 accidents yearly resulting in injuries. Dr. Philip Walsh and his study group estimated that construction and operation of a 1-quad direct coal lique- The oil shale industry is estimated to cause 0 to 390 faction industry will result in 38 to 205 excess deaths premature deaths per year in the public sector, based annually among occupational and public groups in the U.S. on sulfur dioxide emissions of 115 MT/day and the use These estimates were based on siting of two 0.1-quad of oil shale region and long range transport models. plants at each of five generic sites. The uncertainty range of this estimate is greater than for corresponding risks in the occupational sector, The major contributors to the excess annual mortality per although the expected occupational fatalities are 60 quad are as follows: percent greater than the expected public fatalities. • 8 to 10 fatal accidents from mining coal The public health cancer risks from airborne emissions • 2 to 4 occupational deaths from coal transportation of arsenic, cadmium, chromium, nickel, polycyclic by rail aromatic hydrocarbons, and radionuclides all are • 25 to 50 public deaths from coal transportation by expected to be relatively insignificant (e.g., one excess rail respiratory cancer from arsenic occurs every 300 years • less than 1 death from construction activities in a population of 616,000 persons). • 3 to 10 accidental deaths from operation of the plants The ecosystem analysis (done for Western oil shale) • zero to 30 public deaths from releases of toxic quai,tified mule deer, indian ricegrass, and plant materials from the plants community disturbance using two models. Acid rain • zero to 100 occupational deaths from exposures to and salinity issues are addressed briefly in this HEED. toxic materials in the plants

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-31 These scientists also estimate up to 12,000 non-fatal Already the Committee is holding site visits and dis- injuries annually as follows: cussions of the two documents, in preparation for the February 1983 contractors conference. The Direct Coal • 500 to 1,000 occupational injuries during coal Liquefaction HEED was reviewed at Oak Ridge National transportation by rail Laboratory, December 15 through 17, and the Oil Shale a 500 to 700 occupational injuries during coal HEED will be reviewed in Denver January 19 through 21, mining 1983. These review meetings are not open to the public. • 5,000 to 10,000 public injuries during coal transportation by rail. The Committee may remain involved in the HERAP program, reviewing other HEEDs as they approach Thus a large fraction of the impacts of the reference 1- completion. quad direct coal liquefaction industry are associated with front-end fuel cycle activities of raining and transportation, and will be associated with any technology which uses the same coal supplies. Coal transpor- CLEAN AIR ACT WAIVERS GRANTED IN NORTH tation impacts can be reduced by barging or by locating DAKOTA the liquefaction plants at the mine mouths; but the impacts would increase with longer transportation On September 20, 1982, the National Park Service issued distances. its final decision that six energy projects in western North Dakota will cause "no adverse impact" on the Class I air The major focus of this HEED is on the risks associated quality in Theodore Roosevelt National Park and the with the variety of toxic materials generated by direct Lostwood Wildlife Refuge. The six projects affected by coal liquefaction and some associated critical health the ruling are: endpoints (especially cancer) that are considered to be unique to direct coal liquefaction facilities. Estimates • Basin Electric Power Cooperative - seeking a are made of exposures to these materials by atmos- permit to build a third coal-fired generating pheric exposure, by ingestion via the terrestrial food station at its Antelope Valley site near Beulah. chain, and by drinking water. • Warren Petroleum - seeking a permit to double Copies of the draft HEED documents can be obtained the size of its gas processing plant in Billings by contacting Dr. Barr or Dr. Cho at the U.S. Depart- County. ment of Energy, Office of Health and Environmental Research, Office of Energy Research, Washington, 0. • Nokota Co.,— seeking a permit to build a coal-to- C. 20545. Industry is eneouragd to secure the docu- methanol plant in Dunn County. ments for review and comment. • Minnesota Power & Light Co. - seeking a permit Principal Reviewer for the Oil Shale and Direct Coal to build a 11,000-megawatt coal-fired power plant Liqufaetion HEEDS is Dr. Stanley M. Greenfield, of in Oliver County. Systems Applications of San Rafael, California. Dr. Greenfield is assembling all comments concerning these • Amoco Production Co. - seeking a permit to build two HEEDs, for presentation to the contractors meet- a gas processing plant in Billings County. ing in February. • PhillipsPetroleum Co. - a natural gas processing Role of the NAS/NRC plant in Williams County presently operating under a variance granted by the North Dakota Health In September 1982, DOE's HERAP program contracted Department. with the National Academy of Sciences for a one-year study, primarily to review the two synfuels HEEDs, In May 1982, the companies were informed that none of dealing with Oil Shale and Direct Coal Liquefaction. the projects would be allowed air quality permits because computer studies conducted by the North Dakota Health The NAS will be the final review authority for these Department showed that Prevention of Significant two documents, and will emphasize review of the Deterioration (PSD) limits for sulfur dioxide in nearby assessment of risk estimation. NAS will not suggest a Class I areas would be exceeded. The sponsors then research agenda to the DOE. applied to the U.S. Department of the Interior for waivers under provisions of the Clean Air Act which allows such To accomplish its task, the NAS/NRC Commission on waiver if the Federal land manager determines that Life Sciences has established a Committee on Health violations of the P50 limits will not adversely affect air and Ecological Effects of the Synthetic Fuels Industry. quality. The Park Service issued its preliminary decision The NAS Staff Officer is Dr. Roy Widdus, who may be in favor of the waivers in July 1982. The final decision reached at the Academy, 2101 Constitution Avenue announced in September reaffirmed the preliminary deci- NW, Washington, D.C., 20418. sion despite objections from environmental groups. The Committee itself is chaired by Dr. Roy E. Albert, The North Dakota Health Department began conducting of the Institute of Environmental Medicine, New York public hearings on four of the six projects during University Medical Center in New York. Some nine September and October. The U.S. Environmental Pro- other members of this committee are being assembled. tection Agency (EPA) must review the computer model results. If the EPA approves the projects, the state could then issue air quality permits and construction of the projects could begin.

1-32 SYNTHETIC FUELS REPORT, DECEMBER 1982 RECENT GENERAL PUBLICATIONS

Congressional Research Service, "U.S. Synthetic Fuels Corporation and National Synfuels Policy,' proceedings of a seminar sponsored by the Congressional Research Service in cooperation with the Subcommittee on Fossil and Synthetic Fuels of the Committee on Energy and Commerce, U.S. House of Representatives, July 1982, available from U.S. Government Printing Office, Washington. Deese, David A. and Joseph S. Nye, "Energy and Security," a report of Harvard's Energy and Security Research Project. Ebinger, Charles K., "The Critical Link: Energy and National Security In The 1980s," a report of the International Resources Division, published by Ballinger Publishing Co., Cambridge, Massachusetts. Garibaldi, Pierpaolo, Director, Energy and Combustion Solids, Assoreni, "The Development of Synthetic Fuels in Italy," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982.

*International Energy Agency "Energy Policies and Programmes of lEA Countries, 1981 review," Paris 1982. "World Energy Outlook," Paris 1982. Munai, Yasushi, Director, Planning and Business Development, New Energy Development Organization, "The Precut Status of the Development of Synfuels in Japan," presented at the Synfuels' 2nd worldwide Symposum, October 12, 1982. Office of Technology Assessment, "Increased Automobile Fuel Efficiency and Synthetic Fuels: Alternatives For Reducing Oil Imports Summary," available from U.S. Congress, Office of Technology Assessment, Washington, D. C. 20510, Attn: Publishing Office (OTA-E-186). Proceedings of the Fourth Annual Meeting, International Society of Petroleum Industry Biologists, Denver, Colorado, September 22-25, 1981. Samuel, W. A., "A New Look At Cost Patterns For Synfuels," presented at the AIChE National Meeting, Anaheim, California, June 9, 1982. Stobaugh, Robert and Daniel Yergin, "Energy Future," report of the energy project at the Harvard Business School. *U.S. Department of Justice, "Memorandum Of Law: Legal Authorities Available to the President to Respond to a Severe Energy Supply Interruption or Other Substantial Reduction in Available Petroleum Products," Office of Legal Counsel, November 15, 1982. *U.S. General Accounting Office, "DOE Funds New Energy Technologies Without Estimating Potential Net Energy Yields." (GAO/IPE-82-1), July 26, 1982. *World Bank, "Emerging Energy and Chemical Applications of Methanol: Opportunities for Develping Countries," April 1982. Yerbin, Daniel and Martin Hillenbrand, "Global Insecurity: A Strategy for Energy and Economic Renewal," 1982, published by Houghton Mifflin Co., Boston.

Reviewed in this issue.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-33 COMING EVENTS

DECEMBER 6-7, ATLANTA, GEORGIA - Industrial Energy Conservation Seminar, short course, sponsored by Association of Energy Engineers.

DECEMBER 7-9, BALTIMORE, MARYLAND - Mid-Atlantic Energy Conference and Exposition, sponsored by Government Institutes Inc.

DECEMBER 7-9, HOUSTON, TEXAS, ASTROHALI. - 5th International Coal Utilization Exhibition & Conference. This year, the five topics covered will be:

o Applied Transportation & Coal Export • Storage & Handling • Direct Combustion • Synthetic Fuels • Industrial/Utility Applications for Coal

DECEMBER 13-15, MIAMI BEACH, FLORIDA - 5th Miami International Conference on Alternative Energy Sources, sponsored by Miami University, Coral Gables, FL (USA) and Clean Energy Research Institute.

JANUARY 12, 1983, NEW YORK, N.Y. - Shifting Energy Priorities Conference, sponsored by The Conference Board, Inc. JANUARY 24-28, 1983, LAKE BUENA VISTA, FLORIDA - ICT Seventh Annual Meeting on Energy From Biomass and Wastes, sponsored by Institute of Gas Technology.

JANUARY 30 - FEBRUARY 2, 1983, HOUSTON, TEXAS - A Synthetic Fuels Symposium will be held by the American Society of Mechanical Engineers at the Energy-Sources Technology Conference.

JANUARY 31 - FEBRUARY 3, 1983 - HOUSTON, TEXAS - Synthetic Fuels Symposium, sponsored by Petroleum Division; Fuels division; Safety Division; Advanced Energy Systems Division - ASME. Topics to be covered are: • Synfuels From Shale Oil • Utilization of Synfuels • Synfuel Plants • Renewable Feedstocks * Designing for Safety Using Non-Conventional Feedstocks 3 Renewable Fuel Feedstocks • Synfuel Extraction & Utilization • Combustion of Heavy Coal Liquids • Application of Technology of Synthetic Fuels • Advanced Fuel Technology 3 Advanced Energy Conversion Technologies

JANUARY 30 - FEBRUARY 3, 1983, HOUSTON, TEXAS - Energy-sources Technology Conference & Exhibition, sponsored by American Society of Mechanical Engineers, American Institute of Plant Engineers, American Society of Lubrication Engineers, National Association of Corrosion Engineers, and Texas Energy & Natural Resources Advisory Council.

FEBRUARY 2-4, 1983, NEW YORK CITY - Science & Technology of Synfuels: II, sponsored by Clean Fuels Institute and City College. Conference will cover applied research and specific process technology as it relates to the production and the end use of synthetic fuels.

FEBRUARY 7-9, 1983, LEXINGTON, KENTUCKY - International Coal Testing Conference. FEBRUARY 9-1I, 1983, DENVER, COLORADO - 86th National Western Mining Conference and Exhibition, sponsored by Colorado Mining Association.

FEBRUARY 9-11, 1983, LONG BEACH, CALIFORNIA AT THE LONG BEACH CONVENTION AND ENTERTAINMENT CENTER - 1983 Southern California Oil Show, an international trade show and conference.

1-34 SYNTHETIC FUELS REPORT, DECEMBER 1982 FEBRUARY 18-23, 1983, NEW DELHI, INDIA - Chemtech 183 - Oil & Refining Technology. Trade exhibition & conference for oil, gas, chemical and process engineering industries. FEBRUARY 20-26, 1983, MANILA, PHILIPPINES - Accelerating Philippine Coal Development Through U.S. Technology, sponsored by the Ministry of Energy, Philippines; and The Trade & Development Program, United States. FEBRUARY 21-23, 1982, MANILA, PHILIPPINES - Coal Expo '83, an international exhibition of coal mining and processing equipment in conjunction with the Philippine-U.S. Coal/Lignite Symposium. FEBRUARY 28 - MARCH 3, 1983, SHERATON WASHINGTON HOTEL, WASHINGTON, D.C. - Energy Technology Conference & Exposition, sponsors are: American Gas Association, Electric Power Research Institute, Gas Research Institute and National Coal Association. MARCH 1-4, 1983, JAKARTA FAIR GROUNDS, JAKARTA, INDONESIA --lndo-Energy 183, Indonesia's first energy exhibition and energy business conference. MARCH 8-11, 1983, BUDAPEST, HUNGARY - International Symposium on CO2 Enhanced Oil Recovery, organized by Institut Francais du Petrole and the Hungarian Hydrocarbon Institute. MARCH 8-10, 1983, DALLAS, TEXAS - PLM 9th Annual Coal Conference. Conference will feature speakers from the coal and railroad industries, utilities, railcar manufacturers and government agencies. MARCH 14-18, 1983, CHICAGO, ILLINOIS - Solvent Extraction Technology, short course, sponsored by the Center for Professional Advancement. MARCH 15-18, 1983, SAN FRANCISCO, CALIFORNIA - 8th International Technical Conference on Slurry Transporta- tion. Reports will be presented by representatives from ten countries. Topics will include: • Preliminary concept to direct combustion • Laboratory testing to commercial demonstration project • Preparation to dewatering • Rheological properties to regulatory considerations • Research and development to actual operating experience • International coal transportation systems to the latest equipment • Non-water slurries to protection of pipes against erosion/corrosion MARCH 18-26. 1983, BEIJING, CHINA - The China Mines Investment and Marketing Seminar. MARCH 19-24, 1983, LAHORE, PAKISTAN - International Symposium-Workshop on Renewable Energy Sources, sponsored by Clean Energy Research Institute and the University of Miami. MARCH 20-25, 1983, SEATTLE, WASHINGTON - 185th American Chemical Society - National Meeting. MARCH 23-24, 1983, SAN FRANCISCO, CALIFORNIA - 2nd Annual Conference on Alcohol as An Octane Enhancer, co- sponsored by Alcohol Week and the Renewable Fuels Association. MARCH 27-31, 1983, ASTROHALL, HOUSTON, TEXAS - AIChE's Spring 1983 National Meeting and 12th Petrochemical and Refining Exposition. Sessions of specific interest are: • Marketing Petroleum Fuels and Petrochemicals In The Americas • Coal Liquefaction and Gasification - Atmospheric Impact • Enhanced Oil Recovery • Upgrading Heavy Residual Oil Fractions and Hydrocracking • Feedstock Alternatives - Chemicals • Methanol Production - Technology & Economics • Coking Phenomena in Coal Liquefaction Processes • Coal Liquids Upgrading, Technology & Economics • Coal Liquefaction Tutorial • Utilizing Texas Lignite • Indirect Coal Liquefaction • Coal Conversion R&D - Industrial or Government Funding? • Chemical Pathways in Coal Conversion • Thermophysical and Transport Properties in Coal Conversion • Catalysis of Direct Coal Liquefaction • Use of Catalysis in Coal Gasification MARCH 29-31, NEW ORLEANS, LOUISIANA - New Orleans Oil Show and Conference.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1-35 APRIL 13-15, 1983, GOLDEN, COLORADO - 16th Oil Shale Symposium, sponsored by the Colorado School of Mines.

APRIL 15-16, 1983, LOS ANGELES, CALIFORNIA - Conference - Energy Independence: A Challenge for Native American Communities, sponsored by the American Indian Studies Center, University of California.

APRIL 19-23, 1983, HAMBURG, GERMANY - Energy 1 83 International Trade Fair.

APRIL 25-27, 1983, TAMPA, FLORIDA - Fifth International Symposium on Coal Slurry Combustion and Technology, sponsored by the Pittsburgh Energy Technology Center and the U.S. Department of Energy.

MAY 1-4, 1983, PHILADELPHIA, PENNSYLVANIA - Eighth North American Meeting of the Catalysis Society.

MAY 9-10, 1983, NEW YORK CITY - First International Conference on Fuel Methanol, sponsored by Alcohol Week.

MAY 12-14, 1983, SYDNEY, NSW, AUSTRALIA - IV International Coal Exploration Symposium.

JUNE 5-8, 1983, CALGARY, ALBERTA, CANADA - 66th Canadian Chemical Conference and Exhibition. Special sessions include environmental impact of oil and coal industry.

AUGUST 15-19, 1983, PITTSBURGH, PENNSYLVANIA - 1983 International Conference on Coal Science.

AUGUST 28-31, 1983, DENVER, COLORADO - AIChE's Summer 1983 National Meeting. Topics of special interest are:

• Feedstock and Energy Supply - Demand and Outlook o Managing Interface Between Government and Industry in Synfuel Projects • Environmental Aspects of Synfuel Projects • Managing Major Synfuel Projects • Future of Synfuel Projects • Western Coal Utilization • Underground Coal Utilization • Solid Waste Disposal • Coal-Water Slurry Systems: Technology and Economics • Oil Shale and Tar Sands Development: Technology and Economics • Environmental Considerations in Oil Shale and Tar Sands Development

1-36 SYNTHETIC FUELS REPORT, DECEMBER 1982 n \ 0)11.1 SJJlilLJILe PROJECT ACTIVITIES

PAItAHO-UTE PROJECT IS DESCRIBED • Solids storage, including a 350-acre spent shale disposal area and 66-acre raw shale fines storage Paraho Development Corp. (Paraho) plans to build and area. operate a commercial shale oil plant in Uintah County, Utah. When the proposed Paraho-Ute Shale Oil Facility • Liquid waste treatment and recycling systems, is operating at its design rate, the projected production including retention ponds. (per stream day) will be approximately 42,000 barrels of hydrotreatcd oil, 185 megawatts of electrical power (30 • 3.5-mile product pipeline (tie-in to existing MW for export), 210 tons of anhydrous ammonia, and 95 Chevron pipeline for distribution in the Salt Lake tons of elemental sulfur. Several rights-of-way across City area). public lands will be required by the project. In accordance with the National Environmental Policy Act • Ancillary facilities including: of 1969, the Bureau of Land Management (BLM) Utah State Office is preparing an environmental impact access roads (4.2 miles) statement (EIS) covering proposed rights-of-way on water pipeline (2.7 miles) public lands for synthetic fuel projects in the Uinta power transmission line (3.2 miles) Basin located in eastern Utah. (Refer to pg. 1-49 of the communication facilities September 1982 Pace Synthetic Fuels Report for a review of the draft EIS). The BLM requested that The overall project schedule as submitted by Paraho is Paraho prepare a technical report describing in detail shown in Figure 1. This schedule is to change based upon the Paraho-Ute Shale Oil Facility as supplementary completion of the EIS and decisions on the requested information to the EIS. This report "The Paraho-Ute rights-of-way grants and other permitting actions. The Project Technical Report" discusses a high level estimated tine required from start of construction to scenario, low level scenario (single retort operation) full-scale production is five years. Table I summarizes and Paraho's proposed alternative schedule, the phased the projected investment in 1980 dollars, and excluding schedule. In the phased schedule, the plant design, interest during construction and adjustments for inflation. operation information and other details fall within the bounds established by the high and low level scenarios. Paraho's projected construction schedule would begin in early 1983 and last through the second half of 1987. The high scenario is based on a mine production rate of After construction of the first retort is completed, start- 71,440 tons per stream day (TPSD) of oil shale and a up will occur in late 1985. The first hydrotreater will facility production rate of 42,000 BPSD of hydrotreated come on-stream around April, 1986. At this time, the oil. The mine will be an underground room-and-pillar, crude shale oil that will have been stored will be top heading and bench system. Crushing and screening upgraded. The second retort will start producing crude units are designed to provide approximately 65,000 shale oil in mid-1986. Full production will begin in late TPSD of oil shale to the retorts. Raw shale fines will 1987 when the third retort and all auxiliaries are fully be stored on-site for probable future processing. The operational. About 10 years of production are anticipated low scenario consists of a single retort operation and is from the reserves contained in the present site. not considered to be a commercial scenario. After a short operation, not to exceed two years, the single To implement the proposed Paraho project, BLM must retort operation would be either a) scaled up to full grant rights-of-way for the following components: commercial operation b) abandoned, or possibly c) continued as a research facility. The Single Retort opera- • 3.2 miles for access roads tion does not have oil upgrading nor electric power generation facilities. It produces up to 10,520 BPSD of • 3.5 miles for product pipeline crude shale oil, and requires a retort feed of up to 17,730 TPSD of crushed oil shale. The mine must • 2 miles for power transmission line produce up to 19,700 TPSD of oil shale. The construction of all project components would result in The proposed Paraho-Ute project consists of the follow- the disturbance of approximately 1,087 acres. Table 2 ing major components: shows the magnitude and duration of land disturbance. No wilderness areas would be significantly affected by the • Underground room-and-pillar mine and proposed project. associated facilities. Tables 3, 4, and 5 show the resources consumed and • Processing plant with Paraho retorts and produced during operation, total controlled emissions, and upgrading units. solid waste generated during operation. An analysis of the affected environment for the Paraho-Ute Project

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-1 YEAR 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 TASKK QTR rr TTT

A0Iho,,za?.o., —

S"t' E a1.&loll —

She CONSTRUCTION PRODUCTION — — -I. — — —

U10PtS — — I

— — -

M.100.1.H.Odk.1g —

R.oa. Cootn.o,,

fl10I •1 A.'oe' '2 H10'i •

CONSTRUCTION PRODUCTION

PG CONSTRUCTION ftODUCTION

FIGURE I PARAHO-UTE PROJECT SCHEDULE

TABLE 1 - PARAHO-UTE SHALE OIL FACILITY INVESTMENT SUMMARY (Excluding Interest) 1980 Dollars (s/Millions) Process Facilities $__411 Support Facilities 109 Mine 150 Offsitcs 6 Subtotal $ 676 Engineering, Construction, etc. 294 Other Costs 213 Plant Investment Total $1,183 Start-up 60 Working Capital (spare parts) - 121 Administration (EIS, monitoring, lie., permits) S Other 20 Investment Total (1980 Dollars) $1,389 25% Equity 341 75% Debt $1,042

2-2 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 2

MAGNITUDE AND DURATION OF LAND DISTURBANCE

Maximum Length Construction Operation Disturbed Removed Component (Miles) Width/Size Width/Size Acres/Duratlona Acres/Duration Reclaimed Acres

PROPOSED ACTION

Mine and Pltb NA NA NA 43312 years 292/10 years 141

Spent Shale Oiposal Area NA NA NA 350/10 years° 0 350

Access Roads 4.2 250 ft 100 ft 127/ 10 years 76

Product Pipeline 3.5 100 It 20 It 43/1 year 0 43

Power Transmission Line 3.2 20 ft 20 ft 22/1 year 0 22 SD It radius/ pole

Water System 2.7 100 it 20 It 32/I year 0 32

Construction Camp NA NA NA 80/3 years 80/3 years 80

Connun icat Ion Systems No Acreage Required (Microwave System)

TOTAL 1,087 343 744

ALTERNATIVE

Bonanza Power Plant Water Supply System 12 100 ft 20 ft 1451I year 0 145 aliaeimum disturbed duration equals maximum duration and/or active land use.

W b zi es on-site water pipeline and 2-rena long construction camp road. crorty acres disturbed per year.

TABLE 3 RESOURCES CONSUMED AND PRODUCED DURING OPERATION'

Resource Consurnotion Resource Production Resource Quantity Resource Quantity Oil Shale 75,000 tons/day Shale Oil 42,000 barrels/day waterb 2,900 ac-ft/yr Powerc 30 megawatts/day Natural Gas 29,000 million cubic Ammonia 210 tons/day feet/day

Fuel Oil 3,300 gallons/thy Sulfur 100 tons/day Propelled 260 gallons/day Diesel 17,000 gallons/day Gasoline 3,000 gallons/day

aFull production rates of 42,000 bpsd of hydrotreated shale oil. bWater source: White River, c155 magawatts/day produced; 30 megawatts/day available for export. dPropane consumption would increase in the event of a natural gas shortage.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-3 TABLE 4 baseline. Vernal would have population increases over baseline of 13.9 percent (1,289 persons) in 1985 and 14.5 TOTAL CONTROLLED EMISSIONS percent (1,465 persons) in 1987. Dinosaur's increases (Peak Operation) would be 23.5 percent (118 persons) over baseline in 1985 and 29.2 percent (127 persons) in 1987. Emission Rate (kilograms Employment increases would center in Uintah County, Pollutant per hour) which would have an increase over baseline of 30.5 percent (3.226 persons) in 1985 and 19.3 percent (2,138 Total Suspended Particulates 93 persons) in 1987. Duchesne County's increase would be Sulfur Oxides 177 relatively small. Nitrogen Oxides 381 Carbon Monoxide 46 The Paraho-Ute operation would be a zero discharge Hydrocarbons 5 process; therefore, the processing facilities would not alter the quality of any surface water supply. However, erosion during construction would contribute additional sediment to streams. This would be a temporary and insignificant impact. The 2,900 ac-ft/yr that Paraho-Ute TABLE S proposes to withdraw from the White River represents 0.6 percent of the average annual flow. Withdrawal of this SOLID WASTE GENERATED DURING OPERATION amount would not be a significant impact. Quantity The proposed mine shafts could encounter a permeable Product Per Day zone of the Bird's Nest aquifer and would require dewatering during construction. The effect would be Wastewater Treatment 21 tons temporary and probably would not extend to the boun- Sludge daries of the mine property. The mine, 300 to 500 feet Garbage and Scrap S tons below the Bird's Nest, might encounter a large open Spent Catalysts 3 cubic yards fracture or fracture zone extending to the Bird's Nest Pretreatment Lime Sludge 108 tons (10% solids) aquifer. Any water entering the mine would be recharged Oil Filter Particles 43 tons (60% solids) into the Bird's Nest aquifer through a well sufficiently Sulfura 100 tons (maximum) remote to prevent recirculation. aonly a waste if not marketed. The impact to other environmental areas is discussed in both Paraho's technical report and BLM's draft EIS. Overall, the socioeconomic impacts and air quality and visibility degradation are most significant. It was determined that all impacts would be manageable, assuming indicated that except for total suspended particulates, implementation of specific mitigation measures, com- no Ambient Air Quality Standards (NAAQS) violations pliance with existing regulations, and implementation of are expected. The baseline particulates levels are suitable socioeconomic impact agreements. Based on all predicted to violate the 24-hour average particulate the data presented, BLM recommended in the draft £15 standard, mostly due to dust from dirt roads and soil that rights-of-way for the Paraho-Ute project be particles suspended during windy conditions. approved as proposed by Paraho Development Corpora- tion. The Paraho-Ute project would employ 2,800 people during the peak construction year (1985). Total employment would decrease to 1,650 for the peak operating year (1987). Total population increase for BOARD APPROVES COLONY RECLAMATION PLAN Duchesene and Uintah Counties and the Colorado area would be 5,117 persons in 1985 and 4,239 in 1987. Exxon Company, U.S.A. has been given approval by the Uintah County would be expected to have approxi- Colorado Department of Natural Resources, Mined Land mately 80 percent of the population growth and over 90 Reclamation Division for an Interim Site Plan which percent of the employment increases for both peak describes the construction, stabilization, and reclamation years and Duchesne County and the Colorado area activities planned for the Colony permit area through would have minimal impacts. In 1985 Uintah County's 1984. The Interim Site Plan was submitted with the population increase over baseline would be 16.4 percent understanding that Exxon may proceed at any time with (4,218 persons). This would decrease to 12.2 percent in the construction activities currently authorized by Permit 1987 (3,337 persons). 8-47 without formal action by the Mined Land Reclama- tion Board or by the Division. The incorporated community of Vernal would experience the majority of population increase from the In general, Exxon's site plan calls for the following Paraho-Ute project. Roosevelt would have impacts, but activities: to a much lesser extent. Myton and Ballard would not be expected to have measurable increases. Rangely 1. Complete construction of facilities which are would have minimal population increases; however, essential to any future development (i.e Middle Dinosaur would have substantial increases compared to Fork Dam, river water intake, access road).

2-4 SYNTHETICEUELS REPORT, DECEMBER 1982 2. Permanently reclaim areas which would not likely be re-disturbed by future development (access road side slopes, existing buried pipelines). 3. Stabilize, by revegetation or by chemical treatment, those areas which would reasonably be expected to be re-disturbed by future construction or which must remain active through this interim period (stabilization by revegetation: topsoil stockpiles, abandoned flat-lying soil areas such as the terminal site and vacant office sites; stabilization by chemical treatment: active roads and yards, large stripped rock or rock fill areas such as the plant site, La Sal laydown area & coarse ore site). Included in the Interim Site Plan are a series of oblique color air photos and a table which provides a detailed summary of the status of all affected acreage from 1982 through 1984. The program calls for revegetating 285 acres by the end of 1982 and another 75 acres during 1983-1984. Table 1 shows the status of reclamation and stabilization for 1984. Exxon's reclamation plans were approved on December 16, 1982, with the addition of three provisions. The company will check the stability of a large pile of topsoil that state staffers and environmentalists tear might wash away. Exxon will study whether a small stretch of road left unfinished at the project poses a drainage problem. Also, the company will review its water monitoring and sampling plans by next March. With Exxon's agreement, the Colorado Mined Land Reclamation Board set a deadline of December 31, 1984, for Exxon to decide on the prospect of reactiva- ting a project of the Colony site. At that time, Exxon will present a final reclamation plan if the project is not going to move ahead.

RUNDLE OIL SHALE TESTED BY TOSCO On December 13, 1982, Tosco Corporation announced that its pilot plant at Golden, Colorado, had successfully processed more than 100 tons of oil shale from the Rundle resource to establish yields and data on the Tosco II processing of the Australian shale. The Rundle deposit is situated new the coast of northern Queensland, Australia. The data from the tests will be used by the Rundle joint-venture partners (Esso Exploration and Production, Inc. (EEPA), Southern Pacific Petroleum NL and Central Pacific Minerals ML of Australia) to select a retort for the project. EEPA requested that Tosco process the Rundle shale so its compatability with the Tosco II retorting process could be evaluated because different shales can react differently to the same retorting technology. Rundle shale has a very high moisture content (20 percent) compared to that at the Colony project site in western Colorado (1-1/2 percent).

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SYNTHETIC FUELS REPORT, DECEMBER 1982 2-7 PARAHO DEVELOPMENT CORPORATION RELOCATES fl's MAIN OFFICES The Paraho Development Corporation has moved -its main offices from Grand Junction to Englewood, Colorado (a Denver suburb). The address for this new office is: 183 Inverness Drive West Suite 300A Englewood, Colorado 80112 (303) 694-4949 Paraho is actively engaged in several activities including the Paraho-Ute Project. (For a complete description of the project, refer to the article entitled "Paraho-Ute Project Activities" in this issue of the PaceSynthetic Fuels Report.) Other activities include continued pilot plant testing of various shales (including foreign shale) using its facility previously located at the Anvil Points site. The pilot plant is being moved to an adjacent plot of private land owned by the Klough family. Paraho is maintaining an office in Grand Junction that will staff the pilot plant tests. A 0.5-foot diameter batch retort used by Paraho has been relocated to the Logan Wash site owned by Occidental Petroleum.

TOSCO FORMS A NEW OIL SHALE GROUP On October 18, 1982, Tosco Corporation announced that it had consolidated its oil shale, coal and mineral activities into a new group, called Oil Shale and Minerals. Management of the new group, now headed by senior vice president R. Glenn Vawter, includes: T. R. Gray, Director, Business Development J. H. Barney, Director, Operations R. B. Crookston, Director, Special Projects and Planning Other key members of the Tosco Oil Shale and Minerals Group include: S. D. Brady, Manager, Technical Services; R. J. Long, Manager, Sand Wash Project; R. P. Bills, Manager of Project Evaluation; and K. D. Van Zanten, Manager, Technical Liaison. This new group is part of Tosco's recently formed Commercial Development Division whose purpose is to evaluate and secure new business opportunities for Tosco. The Tosco Oil Shale and Minerals Group is based at 11100 East Bethany Drive, Aurora, Colorado 80014.

2-8 SYNTHETIC FUELS REPORT, DECEMBER 1982 GOVERNMENT

SFC APPROVES DRAFT TARGETED SOLICITATION FOR Standard Price Guarantee will apply to the first 30 million OIL SHALE barrels of shale oil produced and will be treated in six successive increments of five million barrels each. The The Board of the U.S. Synthetic Fuels Corporation average price may not exceed $61 per barrel (in March (SFC) approved a draft of its targeted solicitation for 1983 dollars). In a press conference, J. Bowden, oil shale on December 20, 1982. This draft must now be Executive V.P. of the SFC, stated that this value of approved by the SEC's Advisory Committee and is $67/BBL is not an estimate of crude oil prices, but rather expected to be formally issued on January 20, 1983. an estimate of the cost of producing upgraded shale oil. The draft of the targeted solicitation is reproduced in The SFC staff estimates that a price guarantee of its entirety on pages 5-5 to 5-30 in the Appendix of this $67/BBL could yield a return on the investment of issue of the Pace Synthetic Fuels Report. The approximately 25%, depending on the specifics of each information in the remainder of this article summarizes project. No bid price for any increment may exceed the most significant aspects of the solicitation. $951 BBL (in March 1983 dollars) or be less than $30/BBL (in March 1983 dollars). The bid price for each month's This targeted solicitation is different from the three production is subject to escalation adjustments based on previous general solicitations in that it only addresses the Producer Price Index for Finished Goods (PPI) for that one type of resource: western oil shale. The SFC month divided by the PPI for March 1983. The market expects that five or six projects will respond to the price is defined in the solicitation as 85% of the Depart- solicitation. Secondly, the methodology to be used for ment of Defense average price of JP-4 fuel on a the solicitation is somewhat different in that the SFC continental United States - wide basis (DOD CONUS will first select qualified bidders. These bidders will price). The SFC price guarantee is the amount (if then submit a Technical Proposal and a Competitive positive) by which the adjusted bid price exceeds the Bid. The lowest bidder (and possibly other low bidders) market price. A revenue sharing agreement is also will be selected for negotiations leading to financial included in the solicitation if the market price exceeds assistance. Therefore, the SFC almost "guarantees" 120% of the adjusted bid price. This price guarantee is that at least one project will be selected. Third, the only for shale oil produced before January 1, 1998. schedule for this solicitation will be expedited with the selection of the winning bidder(s) on July 1, 1983. The loan guarantee specified in the targeted solicitation Lastly, in this targeted solicitation, the SFC has issued cannot exceed 75% of the baseline project cost estimate. maximum acceptable values for price and loan A maximum of $1.6 billion in current dollars (approxi- guarantees, thus allowing companies to more mately $940 million, plus inflation) can be guaranteed for adequately assess whether they wish to respond to the each winning bidder(s). Repayment of the principal of the solicitation. debt must commence no later than three years after the start of the project operations and can not have a term As summarized in Table 1, the projects responding to exceeding 30 years. Foreign equity in a project is this targeted solicitation must meet several specifica- acceptable to the SFC. tions. The projects must utilize western oil shale from the Green River Formation to produce 10,000 BPSD for The third type of financial assistance specified in the 300 days per year. The shale oil must contain no more solicitation is a standard convertible combination which than 2,000 ppm (by weight) nitrogen and have a pour combines price and loan guarantees. point no greater than 60°F. Hence, the raw shale oil will most likely require moderate upgrading. Lastly, The targeted solicitation does not specify the type of the plant must begin operations before 1990 and must process (or integrated processes) that may be used to produce shale oil for 20 years. To be selected as a produce the shale oil. However, the process must be Qualified Bidder, each project must meet the specifica- made available for replication on reasonable commercial tions in Table 1 and must demonstrate that a maximum terms. of $100 million (or 20% of the maximum equity required if greater than $100 million) is committed to the The SFC is considering targeted solicitations for other project. resources, primarily coal. A coal solicitation may be issued in two to four months. The SFC has established a "fast track" schedule for this targeted solicitation. The schedule is summarized in Table 2. Major milestones in the schedule include: 1) April 15, 1983, to select qualified bidders; 2) July 1, DOD CONTRACTS GEOKINETICS TO REFINE SHALE 1983, to select the winning bidder(s); and 3) Fall 1983 to OIL approve the types and amounts of financial assistance. On November 15, 1982, it was announced that Geokinetics Three standard types of financial assistance may be Inc., has been awarded a $6,285,000 contract by the requested under this targeted solicitation. The

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-9 TABLE I

SPECIFICATIONS FOR PROJECTS RESPONDING TO THE SFC TARGETED OIL SHALE SOLICITATION Synthetic Fuel Resource: Oil shale from the Green River Formation (which includes the formations in the Green River, Piceance, Uinta, Sand Wash, and Washakie Basins). Technology: Any integrated process or processes that will produce synthetic fuel product from the specified oil shale resource and that will be made available for replication on reasonable commercial terms. Project Scale: Minimum 10,000 barrels per stream day nominal design capacity of synthetic fuel product (net plant output); planned operation for a minimum 300 days per year for 20 years.

Synthetic Fuel Product: Shale oil (C5 +) containing no more than 2,000 wppm nitrogen and having a pour point no greater than 60°F. Project Schedule: Planned Start of Operations before 1990.

TABLE 2 SCHEDULE FOR THE SFC TARGETED OIL SHALE SOLICITATION

Formal.lssuance of the Solicitation: January 20, 1983 Submission of Qualification Proposals: March 15, 1983

Identification of Qualified Bidders: April 15, 1983 Definition of Standard Terms and Conditions: May 2, 1983 Submission of Technical Proposals and Competitive Bids: June 1, 1983 Selection of Winning Bidder(s): July 1, 1983

Negotiation of Financial Assistance Agreement: Summer, 1983 SFC Approval of Agreement: Fall, 1983

Department of Defense to produce military jet fuel treater and other equipment necessary for processing from shale oil. shale oil. Geokinetics and Caribou have entered into a long term agreement to develop and test improved Ground testing of jet engines will be performed at a methods of refining crude shale oil into commercial number of Air Force test facilities. Air Force F-15 and products. F-is fighters based at Hill Air Force Base in Utah will also operate on the shale-derived fuel in a series of Geokinetics Inc., is a public corporétion based in Salt flight tests. Lake City, and engaged in shale oil development and production. Caribou Four Corners, Inc., is a privately These tests will represent the first major use of a owned company based in Afton, Wyoming. Caribou synthetic fuel by the Air Force. Geokineties will supply operates a refinery at Woods Cross, Utah, and a chain of approximately half of the 80,000 barrels of crude shale convenience markets. oil that are required and the balance will come from the Government's shale oil stockpile at Anvil Points, Colorado. Geokinetics' oil came from its true in situ facility near Vernal, Utah. DOE AWARDS CONTRACTS FOR EASTERN OIL SHALE PROCESSES Geokinetics will refine the shale oil through a subcontract to Caribou Four Corners, Inc., at Caribou's The U.S. Department of Energy (DOE) recently awarded Woods Cross Refinery near Salt Lake City. Modifica- contracts to three firms to test processes specifically tions will be made to the refinery, including a hydro-

2-10 SYNTHETIC FUELS REPORT, DECEMBER 1982 adapted to eastern oil shale. Total amount of the contracts is approximately $1 million, to be divided among Rockwell International, Battelle Memorial Institute, and Gulf Research and Development Com- pany. The tests at Rockwell will utilize an existing 1 TPH coal liquefaction pilot plant at Canoga Park, California. Previously the pilot plant had been used to test Rock- well's coal flash hydropyrolysis process. In the process, crushed shale will be rapidly injected into a chamber filled with high-pressure hydrogen. Battelle plans to use its existing multi-solids fluidized bed test unit at Columbus, Ohio. The unit uses fluidized bed technology in which air or steam will be used to suspend finely ground oil shale to extract the oil. Residual carbon left on the spent shale after retorting will be burned in the unit to supply heat. A hydrogen donor solvent process adapted from direct coal liquefaction technologies will be tested at Cults facility at 1-larmarville, Pennsylvania. The process will retort the oil shale in the presence of a hydrogen-rich liquid, such as oil.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-11 ENERGY POLICY

ENERGY INTERACTION COUNCIL DISCUSSES OIL Exxon's postponement of the Colony project. In his study, SHALE he interviewed people in Glenwood Springs, Grand Junction, Fruits, DeBcquc, Parachute, and Rifle to At a meeting on October 28, 1982, the Energy Inter- determine their attitudes concerning the oil shale industry action Council (EIC) met to discuss recent oil shale and their future plans. In general, most people would activities. EIC was organized to contribute to the welcome a renewed interest in oil shale. development of the extractive energy industry in Colorado, Utah, and Wyoming - principally oil shale, During the question and answer period, a number of tar sands, and coal when used for making synthetic subjects were discussed by the panelists and audience. fuels - by providing a forum for examination of Some topics included the following: industry-wide issues. The purpose of the EIC is to identify and analyze these issues and to communicate • Support for local towns to mitigate the effects of the results of these analyses to industry and those oil shale development. impacted by such an industry. The EIC is not a decision-making organization, but does provide infor- • Shale oil pricing. mation and analysis to the decision-makers to assist them. • SFC (federal government) stimulus of the oil shale industry. The title of the panel discussion was "The Boom and Bust Cycle of Oil Shale Development - What Went At the conclusion of the meeting, a plan was proposed to Right and What Went Wrong and What Should be Done hold a workshop in early 1983 to discuss the lessons that in the Future." The following panelists participated in were learned during the last boom-and-bust cycle in oil the discussion: shale and to develop methods to deal with the next boom period. The workshops will be by invitation only from Robert Burford, Director, Bureau of Land Manage- the EIC. The workshop attendees will be selected to ment (BLM) provide a cross-section of opinion concerning oil shale development. Paul L. Russell, Author of "History of Oil Shale"

Ed Marston, Colorado Newspaper Publisher

Eddie French, Director, Office of Synthetic Fuels, Department of Defense (DOD) Following each panalist's presentation, the audience participated in a question and answer period. The audience consisted of a very diverse group including industry, union, and local, state, and federal government representatives. In his presentation, Eddie French of the DOD discussed his organization's concern over the quantity and quality of fuels needed by the U.S. armed forces. He predicted that the Naval Oil Shale Reserve (NOSR-1) would be producing shale oil by the late 19801s. Paul Russell reviewed the history of oil shale production throughout the world. He commented that almost all oil shale production has required some type of government subsidy.

Bob Burford of the BLM discussed his organization's recent efforts in preparing for both prototype and permanent leasing of Federal oil shale tracts. BLM is very actively developing these programs now to avoid a "crash program" in the future. Lastly, Ed Marston presented the preliminary results of his study evaluating the effects on local communities of

2-12 SYNTHETIC FUELS REPORT, DECEMBER 1982 ECONOMICS

COMPARATIVE ECONOMICS OF COLONY AND UNION Table 2 presents Pace's forecast of the GNP deflator OIL SHALE PROJECTS which was used to escalate operating costs and to discount the resulting after tax, cash flow streams. The The termination of the Colony project, a project threshold price for syncrude was escalated using Pace's thought by many to be beyond the point of cancellation, Gulf Coast Composite Crude Oil Forecast, also shown in precipitated numerous questions about the economic Table 2. Pace's by-product price forecasts are shown in viability of oil shale development and the marketability Table 3. of shale oil products. Pace presented its assessment of Exxon's withdrawal from the Colony project in the June The threshold price calculated is defined as the plant gate issue of the Pace Synthetic Fuels Report. In this price that the project must receive in order to realize a present article, Pace presents an independent economic 10 percent constant-dollar discounted cash flow rate of analysis of the Colony and Union oil shale projects. It return (DCFROR). Since the evaluation is based on is hoped the results will lead to a better understanding constant purchasing power, the threshold price in any of why Union is still moving forward while Colony has given year is based on the composite crude oil forecast dropped out. given in Table 2. Table 1 presents the base case economic and financial Another important aspect of the analysis is that it is criteria used to analyze the Colony and Union projects. performed on a company basis. This implies that the Both plants are assumed to begin construction 1982 and parent company or companies are receiving enough to operate for 20 years. Construction and project revenue from other sources to take all of the tax losses start-up schedules for each project are best estimates and credits generated by the synfuel project. This yields based on what is known about the projects. For both a greater rate-of-return than a project basis analysis projects, an operating cost of $21 per barrel was because the losses and credits are taken in the year assumed. This value is based on Pace's estimation of incurred, rather than in less valuable future dollars. mining, retorting, and upgrading costs. Based on the available data, no quantifiable difference in operating The results, of the base case analyses are presented in costs between the two projects could be determined. Tables 4 and 5. The base case threshold price for Union and Colony are $35.0 and $50.3 per barrel (1982 basis), To keep the comparison on a consistent basis, the respectively, for a 10 percent constant purchasing-power financial criteria were kept the same: a 60/40 debt: DCFROR. This can be restated as, if Union receives $35 equity ratio and a 10 year loan term. The long-term per barrel of syncrude sold at the plant gate, the project and construction loan interest rates were assumed to be will see a 10 percent rate of return over inflation. based on three points plus the GNP deflator three years prior to the loan assumption. The three years accounts Table 5 contains capital and operating costs per barrel of for the time lag between interest and inflation rate produced synerude for each project. These costs have changes while the three points reflect long term been deflated back to 1982 dollars and are, therefore, on average real costs of capital. Construction loans were a consistent basis. However, because the analysis is done assigned an additional three points because upon de- in current dollars, certain items do not reflect time- fault, the lending institution would not have an opera- valued averages, but rather the actual cost in the first ting facility as collateral and because the venture is year of full production. Therefore, the column totals are risky. The long term interest rate was penalized an greater than the base case threshold prices due to high additional point because of the riskiness of the venture. initial interest and principal payments. Because there are numerous types of financing for capital intensive projects, this financial basis is just one The $15.3 per produced barrel differential in the base way of evaluating the projects. Pace evaluated the two case threshold price may be attributed to a number of projects using a constant purchasing power, threshold project characteristics. A detailed discussion of these price analysis. Constant purchasing power analyses are items is in the June 1982 Synthetic Fuels Report begin- performed by: ning on page 2-1. A summary of the major factors is as follows: escalating all revenues and costs to current dollars, calculating deductions, taxes, totals, etc., and • Exxon's redesign of TOSCO's original estimate of deflating resulting cash flow back to the base year. the Colony project resulted in significantly higher capital costs. This type of analysis properly considers the time value of money when calculating depreciation, taxes, and • The infrastructure plans, capital costs, and the capital charges. It also allows the effect of real magnitude of the investment are greatly different. differential changes in product prices and costs to be Referring to Tables 1 and 5, Colony would have evaluated. invested almost nine times as much money, up- front, for less than five times the production

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-13

TABLE 1 BASE CASE ECONOMIC AND FINANCIAL CRITERIA (1982 - 1st Q Dollars)

Colony Union Investment/Startup

Capital Cost (MM $ as spent) 5,290 600 First Year of Construction 1982 1982 Construction (%/Year) 5, 15, 30, 35, 15 35, 65 Project Startup 1 year @ 50% on-stream 6 mo. @ 50% on-stream Production (Annual)

Syncrude (Bbl) 16,290,000 3,650,000 Sulfur (Ton) 64,000 10,000 Ammonia (Ton) 50,000 7,900 Coke (Ton) 269,000 0 LPG (Bbl) 2,204,000 0 On-Stream Factor (%) 90 90 Royalty on Syncrude (%) 2.5 2.5 Operation Operating Costs ($/Bbl Syncrude) 21.0 21.0 Plant Life (Years) 20 20 Working Capital (% of operating costs) 25 25 Tax Allowances and Taxes (Company Basis, i.e., tax losses and credits taken in year incurred) Depreciation 5 Year ACRS1 5 Year ACRS1 Depletion Allowance on Syncrude Federal(%) 15.0 15.0 State (%) 27.5 27.5 Investment Tax Credit @ 10% 75.0 75.0 (% of investment eligible) Energy Tax Credit @ 10% 75.0 75.0 (% of investment eligible) Severance Tax on Syncrude (%) 3.3 0.0 State Income Tax (%) 5.0 5.0 Federal Income Tax (%) 46.0 46.0 Financial Debt/Equity Ratio 60/40 60/40 Annual Construction Loan Interest Rate (%) 11.72 12.02 Long Term Interest Rate (%) 9•73 10.03 Loan Term (Years) 10.0 10.0

1 ACRS-Accelerated Cost Recovery System, Economic Recovery Act of 1981. 2 Approximately 6 points above average. GNP deflator during construction periods, 3 points for capital charge plus 3 points for risky construction loan, 3 years. 3 Approximately 4 points above GNP deflator 3 years prior to loan accounts for time lag between interest rates and inflation, 3 points for capital charge, 1 point for risky venture.

2-14 SYNT1{EIC FUELS REPORT, DECEMBER 1982 TABLE 2 PACE ESCALATION RATE FORECAST

1982 1983 1984 1985 1986 1987 1988 1989 1990 1995 2000 GNP Deflator 6.0 5.6 5.7 5.6 5.4 5.2 5.0 4.8 4.6 4.6 4.6 (% Change) Gulf Coast Comp. 1.7 8.2 14.2 5.6 5.4 5.1 5.0 4.8 4.5 4.5 4.6 Crude Oil Forecast Change)

TABLE 3 PACE BY-PRODUCT PRICE FORECASTS

Constant $ - 1982 Current $ 1985 1990 1995 2000 1985 1990 1995 2000 Ammonia ($/Ton) 154.6 245.6 247.0 248.4 194.7 374.4 471.5 593.7 Sulfur ($/T on) 21.0 80.0 77.0 74.0 24.8 122.0 147.0 176.9 Coke (5/Ton) 30.3 33.1 36.0 39.2 35.8 50.5 68.7 93.7 LPG ($/BbI) 24.4 19.6 19.9 18.3 28.9 29.9 36.3 43.7

capacity. On a dollar per barrel basis, Colony's (10 percent) the required selling price increases with investment and capital charges are approxi- capital charges. The delta threshold price varies slight, mately 1.7 times those of Union. Part of these 4.5 dollars per barrel over a 6 point range. charges are related to the required infrastructure for Colony including utilities, transporta- The debt:equity ratio is another critical financial criteria. tion, and communication facilities not required Figure 3 indicates that the threshold price for Union could for the smaller Union project. Of course, these be lowered 2 dollars per barrel if they could get 75/25 costs would have been mitigated if large oil versus 60/40 financing. On the other hand, 40/60 versus shale development could occur to take advantage 60/40 financing of Colony would have increased the of economies of scale for the industry overall. threshold price 6 dollars per barrel. The effect to note from Figure 3 is that because Colony is more capital • The larger investment schedule for Colony adds intensive, its profitability is more greatly affected by up-front investment and interest costs and debt finaneiçg than is Union's. places revenue in less valuable future dollars. Because each of these technologies are new, start-up • Because of Union's size, it does not have to pay a delays are quite possible. Table 4 shows project threshold severance tax on shale oil. prices for two start-up scenarios. A one year delay in on- spec production (i.e., operating costs are incurred, but no Figure 1 shows graphically the sensitivity analysis range saleable product is produced) causes a 5.9 dollar per for the discount rate (DCFROR). The delta threshold barrel increase for Colony and a 3.7 dollar per barrel price between Union and Colony increases from about 9 increase for Union at a 10 percent discount rate. As is dollars per barrel at a 5 percent constant dollar rate of expected, if this production loss is spread over 2 years return to almost 38 dollars at a 20 percent DCFROR. (i.e., a 50 percent reduction in each year) the effect is The primary reason for this is Colony's longer invest- less drastic, but still significant; 4.6 dollars per barrel for ment schedule. Simply put, higher discount rates Colony, 3.1 dollars per barrel for Union. The delta decrease the value of future revenues. between the two projects increases with decreased production, due to the magnified effect of lost future pro- The sensitivity of the projects to capital charges is duction due to investment schedule differences. shown in Figure 2. The base values shown in the legend are the long term interest rates, but the construction As this analysis has shown, the profitability of large, capital charges were varied by the same amount. The capital intensive projects is more sensitive to capital trend here is as expected, at a constant discount rate related charges than smaller, or less capital intensive

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-15

TABLE 4

BASE CASES AND RANGE SENSITIVITIES CONSTANT PURCHASING POWER ANALYSIS Threshold Price ($/Bbl Syncrude - 1982) Delta Description Colony Union Colony - Union Base case @ 10% Discount Rate 50.3 35.0 15.3 Sensitivity to Discount Rate DCFROR = 5% 38.7 30.0 8.7 15% 65.8 41.1 24.7 20% 86.0 48.3 37.7 Sensitivity to Capital Charges Delta Points from Interest Rate Base -2 47.7 33.9 13.8 +2 52.8 36.0 16.8 +4 55.4 37.1 18.3 Sensitivity to Debt: Equity Ratio = 75:25 45.7 33.1 12.6 50:50 53.3 36.2 17.1 40:60 56.3 37.5 18.8 Sensitivity to Startup Period 1 year delay - operating costs 56.2 38.7 17.6 incurred, no production 50% on-stream for 2 years 54.9 38.1 16.8 following base startup period

TABLE 5

COSTS PER PRODUCED BARREL OF SYNCRUDE IN FIRST YEAR OF PULL PRODUCTION (1982 $ - Base Case) Delta Colony Union Colony - Union

First Year of Full Production 1988 1985 Barrels of Synerude Produced 14,660,000 3,285,000

Royalty 1.33 0.93 0.40 Severance Tax 1.71 0.00 1.71 By-Product Credit (4.23) (0.41) (3.82) Operating Cost less Interest 21.00 21.00 0.00 Interest Payment 13.64 8.34 5.30 State Income Tax 0.00 0.00 0.00 Federal Income Tax 0.00 0.00 0.00 Amortized Capital (15 Years) 8.42 4.69 3.73 Principal Payment 15.63 9.26 6.37

Union and Colony operating costs were assumed to be equivalent.

2-16 SYNTHETIC FUELS REPORT, DECEMBER 1982 lireshold Price il/ti) Lw colony 00

ID Union 70

Delta colony-Union

30 — —

0 5 IA IS 20 25

(x)

FIGURE 1 RANGE SENSITIVITIES TO DCFROR COLONY VS UNION OIL SHALE PROJECTS

lireshold Price IS/Deli 60 ulney

Union Base - loot

r------— I

Delta ColwUloo 30

i I I I I -3 -2 -1 0 I 2 3 I 5

Delta Pouts fro. one

FIGURE 2 RANGE SENSITIVITIES TO CAPITAL CHARGES COLONY VS UNION OIL SHALE PROJECTS

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-17

flnsImld flqc, ($/lI 70

Colony

unim ::

-- 40— ____ - Colony - WIM 30 -

- I I 0 I I

30 40 45 50 55 00 70

tt Dan

FIGURE 3 RANGE SENSITIVITIES TO DEBT/EQUITY RATIO COLONY VS UNION OIL SHALE PROJECTS

projects. Colony would have invested almost nine times as much for less than fives times the product capacity, or approximately 1.7 times as much on a dollar per produced barrel basis. Even with the additional by- product credits, Colony's syncrude threshold price is about 15 dollars (1982 constant dollar basis) per barrel greater than Union's at a ten percent discount rate. Because, in this analysis, the per dollar production costs were assumed to be equal for both projects, this effect is attributable solely to the capital intensity and investment schedule of the two projects.

2-18 SYNTHETIC FUELS REPORT, DECEMBER 1982 TECHNOLOGY

RETORTING OIL SHALE BY ELECTRICAL RESISTIVE The study results indicate that the retort front will HEATING emanate from the two electrodes until the process has progressed to some distance from the wellbores. The Sandia National Laboratories recently issued a report retorting process would be stopped by turning off the entitled Resistive Heating for Oil Shale Retorting. The electrical power and the retort products would be report summarizes the results of a theoretical study collected from the two wells. conducted by Sandia staff members to evaluate the concept of retorting oil shale by the use of electrical Mathematical Process Models resistive heating. Objectives of the study include: Three different one-dimensional mathematical models of • define the concept of electrical resistive heating the resistive heating process were developed at Sandia. as applied to oil shale retorting The first model assumes that no thermal conduction occurs during the process. The second method eliminates • describe present efforts assessing the technical that assumption and uses a finite element approach to feasibility of electrical resistive heating of oil solving the problem. The third method uses a non-linear shale integral technique. All three methods assume that the current density, resistivity, and temperature only vary in • define those areas to be researched further. the radial direction away from the electrode. Also, the one-dimensional methods are valid only when the point of The report is preliminary in nature and only documents observation is located much closer to the surface of an the results of the study to date. At the conclusion of electrode than to its ends. the report is a listing of recommendations for future studies. The first analytic solution used by Sandia assumes the following: Process Description • no thermal conduction The concept of an electrical resistive process is of interest because it represents a method of true in situ S the electrical current input remains constant oil shale retorting. Therefore, the costs and potential problems of mining and handling oil shale are • the electrica} conductivity of the oil shale is a minimized. piecewise constant function of temperature

The study conducted by Sandia evaluated a system in • the specific heat of the oil shale is constant. which two wellbores are drilled into the oil shale formation. Two cylindrical electrodes (normally equal The results of this simple process model are presented to the height of the oil shale zone to be retorted) are graphically in Figure 2 for an electrical input of 10 lowered into the wells. A direct or low frequency amperes. Due to the very high temperature gradient at current is then passed between the electrodes, thus approximately 0.53 meters from the electrode as shown in heating the oil shale. Because the density of the Figure 2, the researchers concluded that a refinement to current is highest near the electrodes, these areas will the mathematical model was necessary. begin to heat up first. As shown in Figure 1, when the temperatures in these areas reach 100 0 - 200°C, the The second methematical model that was developed used resistivity of the oil shale increases dramatically due to a finite element method. This method allows a one- the evaporation of water in the pores. The rate of dimensional, non-linear, transient heat conduction heating of the oil shale is directly proportional to its analysis to be performed. Results from this second model resistivity, thus resulting in a rapid increase in are depicted in Figure 3. The model results indicate the temperature in the vicinity of the electrodes. The following predicted characteristics: outer areas of the oil shale formation continue to heat more slowly. • the temperature in the zone of retorted shale is relatively constant at 500°C to 600°C The researchers predict that a second large change in the oil shale resistivity will occur at temperatures • the temperature drops very rapidly in the retorting above 300°C. As free carbon is formed by the zone retorting process, the resistivity of the oil shale will theoretically be reduced. Therefore, the rapid heating • the preheating zone moves radially outward with of the oil shale will be automatically terminated at time. temperatures of 400° to 450°C. Additional energy that is input into the retorted areas near the electodes will Compared to the results from the simpler model, the only slightly increase the temperature of the spent results of the second model indicate that the retort front shale.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-19 108 I I cc AGROSKIN 10 A CR 0 8K IN 106 DUB OW o '-II-''-•. ti \' 10 4 . II I I- _-GENERAL \\ / TREND 103 " \\ ILI io F.__CAMPBELL r 101 - G 100 I 0 100 200 300 400 500 600 700 TEMPERATURE, DEGREES CENTIGRADE FIGURE 1 ELECTRICAL RESISTIVITY - THERMAL EFFECTS

WI I 500 NOTIME THERMAL 52,500 CONDUC SECONDS 0 (14.6 HOURS) I 4OO -

C., U, LU UJI 3OO-

ccUl 2OOr

C cc 10

O:5 :5 2O RADIAL DISTANCE, METERS t • 500 OHM -METERS AT TEMPERATURES LESS THAN 100C e • 106 OHM-METERS AT TEMPERATURES BETWEEN 100 AND 480C CpELECTRICAL ' 2.4 X 10INPUTJIM3C • 10 AMPERES FIGURE 2 ELECTRICAL RESISTIVE HEATING OF OIL SHALE USING THE SIMPLE CLOSED FORM MATHEMATICAL MODEL NEGLECTING HEAT FLOW

2-20 syNrilEnc FUELS REPORT, DECEMBER 1982 600

w 500-

400- C) U) w W 69.7 HOURS Ix 300 - 137.1 LU 0 200

cc LU 100 - LU I- 0 I 0 1 2 3 4 5 6 7 RADIAL DISTANCE, METERS RESISTIVITY-TEMPERATURE RELATIONSHIP

TEMPERATURE RESISTIVITY ('C) (ohm-neters)

-100 5 x 100 5 ,c 102 200 1 x 106 300 1 x 106 450 1 x io 600 1 1580 1 ELECTRICAL INPUT 10 AMPERES THERMAL CONDUCTIVITY • 1.3 WATTS/METERC FIGURE 3 - ELECTRICAL RESISTIVE HEATING OF OIL SHALE USING THE FINITE ELEMENT MATHEMATICAL MODEL INCLUDING HEAT FLOW

is wider; the retort front moves away from the elec- The third method of analyzing the electrical resistive trodes more rapidly, more power (at constant current) retorting concept used a nonlinear integral equation for- is required, and the time to initiate retorting is longer. mulation. This method also assumed that the resistivity versus temperature profile is a piecewise constant func- As shown in Figure 4, the retort front velocity is a tion of temperature. The results using this method were function of the distance from the electrode. A large very similar to the results obtained by the finite element voltage drop occurs across this front due to its high solution. resistance. In the mathematical model, the current was assumed to be constant, thus resulting in high current Sensitivity Analysis density near the electrode. This high current density causes very high voltage drops when the retort front is The researchers at Sandia performed a parametric study near the electode. The researchers conclude that the to test the sensitivity of the results with respect to the input current should be tailored to maintain a more resistivity-temperature relationship of the oil shale. constant voltage drop. This concept of controlling the Three different relationshi ps as defined in Table I were electrical power input was beyond the scope of the evaluated. These relationships were similar in that at preliminary study conducted by Sandia. some temperature the resistivity increases from 500 to I

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-21 FIGURE 4 RETORT RATE RELATIVE TO DISTANCE FROM ELECTRODE

TABLE 1 RESISTIVITY -TEMPERATURE RELATIONSHIPS Resistivity (ohm-meters) Temperature 0 (°C) A B C (Original Case) -100 5 x102 - 5 x102 5 x 10 2 5x102 100 5x102 5x102 5x102 5x102 160 6x105 1x103 1x103 6x105 200 1x106 1x104 1x104 1x106 300 1x106 1x106 1x106 1x106 450 1x104 1x104 1x106 1x106 480 8.1 x 10 3 8.1x103 1x106 1x106 580 1.8x103 1.8x103 1 1 600 1 1 1 1 1580 1 1 1 1

2-22 SYNTHETIC FUELS REPORT, DECEMBER 1982 x 106 ohm-meters and then drops to 1 ohm-meter at 0 electrode end effects another temperature. The curves differ, however, in how quickly and at what temperature these changes • total voltage and amperage requirements for a full occur. scale facility. The results of this parametric study are presented in Energy Balance Table 2. From these results, the researchers conclude that the width of the retort zone is a function of how A relatively sim ple energy balance analysis was per- quickly the resistivity of the oil shale drops off after formed at Sandia based on the following assumptions: retorting begins. Also, a gradual increase in resistivity prior to retorting causes the retort zone to be narrower 1. The efficiency of the electrical power generation and, hence, require less power. Therefore, of the four is 35%. Thus, one gallon of oil will produce 14.2 resistivity-temperature relationships that were studied, KWH of electricity. the most favorable for an efficient process is defined by Case C. 2. Retorting is terminated at 5 meters radius from the electrodes. The amount of heat deposited in Potential Problems the preheating zone outside this radius is less than 25% of the energy in the retort zone based on the The Sandia report identifies several potential problems thermal calculations. with the concept of electrical resistive heating. Non- homogeneities in the oil shale formation such as 3. The heat remaining in the rock after retorting will layering, jointing, or inclusions may result in non- not be recovered by secondary methods. uniform temperature and retorting patterns. However, it may be possible to control the process to correct for 4. Any gas products generated during retorting are these nonhomogeneities. The researchers predict that neglected. if the high-temperature resistivity in the retort zone is uniform, the process will be relatively stable. Also, the 5. Only a fraction of the oil produced will be process may be somewhat "self-healing" as the retort recovered. For this study, recovery rates ranging zone moves away from the electrode because the from 30 to 80% of the Fischer Assay are con- current density is inversely proportional to the distance sidered. (Present in situ processes are within these from the electrode. bounds.) Other problems identified by the researchers include The results of this analysis, presented as the ratio of oil the following: recovered to energy required for power generation, are presented in Figure 5. • potential fingering in the oil shale deposit Conclusions and Recommendations • electrical breakdown of the oil shale The researchers conclude that the mathematical models • material anistropy predict that a narrow 5 cm thick retort zone will pro- pagate outward from the electrodes to a distance of

TABLE 2

RESULTS OF PARAMETRIC STUDY

Maximum Nominal Average Property Time until Width of Voltage Retort Set Retorting Retort Front Drop Rate Sec rn/sec (hr) m . volts (M/Hr)

A 7.46 x 10 4 .97 50,000 3.35 x 10 (20.7) (0.121) o 1.17 x 10 .3534 30,000 2.345 x 10 (32.5) (0.084) C 1.14 x 10 .1017 35,000 3.1715 x 10 (31.7) (0.114) 0 7.24 x 10 4 .177 60,000 5.019 x 10 (20.1) (0.181)

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-23 I I I I I

to 0

cc 'U z LU (01A

.3 /t. "'A

shoo 0 I I 20 30 40 50 60 70 80 PERCENT OF OIL RECOVERED FIGURE ENERGY BALANCE

approximately 5 meters with less than 25% of the • Further studies should include temperature varia- energy wasted outside the retorted area. The pre- tions of the specific heat of the oil shale to liminary calculations also indicate that the current and account for heating due to chemical changes if voltage inputs can be adjusted to control the retorting required. process in a reasonable manner. Lastly, the process appears to be reasonable based on an energy balance • A bench scale test of the method is required to analysis. This energy balance can be improved by allow a more complete observation of the process devising a method to recover the heat remaining in the than could be obtained from a field trial. retorted shale. cs Final assessment of the feasibility of the method The researchers also identified the following subjects with a shallow field experiment accompanied by that require further analysis: diagnostic instrumentation such as thermocouples, resistivity, etc., is needed. • The high temperature resistivity of oil shale (above 450°C) needs to be determined as well as high field strength values of resistivity at lower temperatures. CONTINUOUS OIL SHALE MINER DESCRIBED • Laboratory measurements need to be made to A report, "Haspert Oil Shale Mining System - Final assess the dielectric strength of oil shale at Report on Design Work of Prototype Oil Shale Mining elevated temperatures. Machine" prepared by John C. Haspert for the U.S. Department of Energy (DOE/CS/15006-T1, Vol. 1 & Vol. • An analytical or numerical study in two dimen- 2) describes a continuous underground mining machine for sions is needed to determine whether instabili- oil shale. The report presents the design of a proposed ties die out with time, leading to a smooth retort prototype machine. The machine, unlike other continuous front, or whether they increase with time mining machines proposed for oil shale, would mine a leading to fingering and inefficient use of the retangular opening which would result in a higher resource resource. recovery. - • Some form of one-dimensional perturbation The machine is designed to operate in an underground analysis is needed to provide a closed form heading ranging in height up to 60 feet and a mining face solution to the problem of thermal conduction.

2-24 SYNTHETIC FUELS REPORT, DECEMBER 1982 with an angle of 40 degrees as shown on Figure 1. The GROUTING OIL SHALE MINES WITH SPENT SHALE sloped heading face is reported to be preferable as it provides more surface area on which to apply cutting At the 57th Annual Fall Technical Conference and tools than would a vertical face. The key to the cutting Exhibition of the Society of Petroleum Engineers of AIME machine is a number of discs fitted with a tungsten held in New Orleans, Louisiana, on September 26 to 29, carbide bit, as shown in Figure 2. The disc is locked in 1982, the results of recent tests concerning the use of place and the bit dragged over the face to cut a groove. spent shale to fill oil shale mines were presented. The Discs, in parallel, cut grooves which isolate cores to be title of the paper was "The Filling of Oil Shale Mines with fragmented. The discs are unlocked and rolled back Spent Shale Ash; Ash Characteristics and Grout Develop- under pressure to the starting point. The wedging ment" by George H. Watson, et.al . In the paper, the action of the discs breaks the core between the grooves laboratory and pilot plant studies conducted for Rio as shown on Figure 4. The cutting action is actually a Blanco Oil Shale Company under contract to the U.S. linear oscillating action which moves up and down the Department of Interior were described. sloped heading. The cutting is done on one stroke and breaking of the core between grooves is accomplished Process Description on the return stroke. Figure 5 shows the direction in which the grooves are cut. The report suggests that the Rio Blanco has considered the use of modified in situ machine will provide: (MIS) retorting to recover shale oil from its federal Tract C-a in northwestern Colorado. At the tract, 9 relatively • A continuous mining action producing uniform rich zones and 10 relatively lean zones have been identi- particles that could be directly fed to some fied from corehole data. One of the richer and shallower retort types or would require only single stage zones is the Mahogany zone which is approximately 115 crushing for other retort types. feet thick with an average overburden of 480 feet. • Safer working conditions by eliminating blasting, The MIS retorting method considered by Rio Blanco dust, and potential sparking. consists of mining 20 to 40% of the oil shale and bringing it to the surface for aboveground retorting. The • A groove-cutting and core-breaking technique remaining shale is rubblized by blasting from holes drilled which is a highly efficient use of force. from the surface. The rubblized oil shale in the in situ retort is then ignited, air is blown into the top of the • A reduction in the number of miners which will retort, and liquid shale oil products are withdrawn from increase productivity and reduce mining costs. the bottom. The machine is designed so that each bit cuts a 1/8-inch For processing the shale brought to the surface, Rio groove on each cutting stroke. The machine would Blanco selected the Lurgi-Ruhrgas process. The process operate at 8 strokes per minute or cut 1 inch per is described in detail in the article beginning on page 2-7 minute. The advance rate would therefore be 60 inches of the March 1981 Cameron Synthetic Fuels Report. per operating hour or 5 feet per operating hour. The Basically, fresh, finely crushed shale is fed to a screw prototype machine is designed to operate in a heading mixer where it is retorted by contact with spent shale 18 to 20 feet high and would mine to a width of ash. Kerogen in the shale is converted to liquid and approximately 27 feet. The report claims that the gaseous products. Residual carbon on the spent shale is prototype machine will mine 272 tons of oil shale per burned in a lift pipe and separation bin to supply the heat hour and at a 75% availability basis will mine 4,984 tons needed for retorting. Spent shale ash (SSA) for disposal is per day. Further, the report claims that the machine recovered from the flue gas cyclone and electrostatic will increase man-hour productivity 450 to 700% over precipitator in the waste heat recovery system down- conventional room and pillar oil shale mining methods. stream of the separation bin. The report indicates that when designed to cut a 60 foot heading that S machines could produce 70,000 tons This proposed combination of MIS and Lurgi retorting of oil shale per day. The prototype machine is compli- technologies results in large caverns under ground that cated and will weigh about 376 tons. Motivation is are filled with retorted shale and large quantities of fine provided by track crawlers and the machine is fitted SSA above ground that require disposal. If the MIS retorts with an automatic mucking system. The machine would are abandoned unsealed, the aquifers in the area may be be powered by 5 diesel engines with a combined power connected by some of the caverns. Also, surface sub- of 1,500 hp. sidence may occur. No capital or operating costs were presented in the Therefore, a program was developed to test a SSA-based report. If the claims are true, the machine should be grout that could be injected into the spent MIS retorts. able to efficiently mine oil shale. Conventional room This grout would: and pillar oil shale mines have taken advantage of economies of scale and productivities in excess of 100 1. Seal the retorts to avoid leaching possible con- tons per man-shift are expected. If this machine were taminants from the in-situ spent shale. able to exceed 100 tons per man-shift by a factor of 4 to 7 (400 to 700 tons per man-shift) the system would 2. Stabilize the retorts to eliminate significant sur- indeed be manpower efficient. face subsidence, and 3. Reduce surface disposal of waste by using the surface retorted SSA as a major constituent of the grout.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-25 HEADING P FACEyF EIGHT RANGE FT.

RECTANGULAR BORE CORES AS OPPOSED TO ROUND L4% FIGURE 3 SHOWS GROOVES PRODUCED BY CARBIDE CUTTER BITS FIGURE 1 SHOWING FACE SLOPE ANGLE AND RECTANGULAR OPENING _ It

STON CARBIDE TEETH FIGURE 4 a' WEDGING ACTION OF DISC BREAKS CORES FIGURE 2 KERF-CORE CUTTING AND BREAKING BIT

SHOWS THE DIRECTION OF GROOVE CUTTING

2-26 SYNTHETIC FUELS REPORT, DECEMBER 1982 The first two phases of a four-phase program have been meter for MIS retort grouting is permeability. After the completed and were described in the paper. The first desired permeability was selected, the highest strength phase consisted of defining the characteristics of the was selected within the constraints of the rheological SSA and determining if a grout based on this material characteristics. For the tests, the researchers specified could be used to fill the abandoned retorts. Laboratory the following mechanical properties: testing of the three most promising grouts was also conducted. In the second phase of the testing, two Permeability <1 x 10-6 cm/see. large pilot-sized retorts were grouted with the two Strength >7 kg/cm 2 (100 psi) most promising grouts under simulated in-situ conditions. The grouted "retorts" were then tested for in- Laboratory Tests situ strength and permeability for comparison with laboratory results. Based on a number of laboratory tests to determine the setting time, permeability, strength, bleeding charac- The SSA used for the tests was produced during Lurgi teristics, and viscosity of SSA-based grouts with different pilot plant test runs. These tests were conducted at additives, two grouts were selected as optiminal. The different temperatures and residence times to demon- characteristics of these two grouts are summarized in strate and optimize the Lurgi process. Therefore, SSA Table 1. from tests that most closely represented the expected commercial operating conditions was blended to provide TABLE 1 sufficient quantities for the grouting tests. CHARACTERISTICS OF SELECTED SSA-BASED GROUTS A spent MIS retort prior to grouting is expected to contain spent shale rubble at 150 0 to 165°F with a void at the top of the retort. These physical conditions are Grout # 1 2 Target expected to be very similar to grouting of coarse alluvium near dams. However, the MIS retort is Additive 1 different in that the rubble void volume is much Type Glucon. Glucon. - greater, the temperature is higher, and the grout may Content, 1/m 3 1 1 — lose water due to rehydration of the spent shale. Additive 2 Grout Characteristics Type - Cement - Content, kg/m 3 - 15 - Grout prepared from SSA must demonstrate acceptable rheological characteristics that are directly related to Marsh viscosity, sec. 49.5 47 45-55 the groutability of the slurry. The rheological charac- Dynamic viscosity, cP 140 145 — teristics that define a grout are: Setting time, mm. 95 100 120 Bleeding, % 4 1.5 5 • Initial viscosity. The parameter that determines the distance of flow and the effectiveness of Unconfined 2 day 0.246 0.323 penetration. Compressive 7 day 0.337 0.464 Strength 14 day 0.394 0.506 • Stability. Three basic types of grout can be kg/cm 2 28 day 0.429 0.541 7 prepared (unstable, stable, aerated). However, both the unstable and aerated were eliminated Permeability, cm/s io 5 4.5 10 because the surplus water from the unstable grouts could not be absorbed in the retort walls, Triaxial Shear Tests aerated grouts would not give a satisfactory Angle of friction1 deg. 39 30.5 permeability, and stable grouts have been proven Cohesion, kg/cm' 0.583 1.97 to be the best for grouting "similar" alluvium material. • Setting time. The parameter that defines the time for the grout to be injected and flow Laboratory tests were also conducted to characterize the through the rubble matrix before hardening. rubble to be used in the pilot plant grouting tests. The physical properties of the rubble that were tested in- Based on experience with alluvium grouting, the cluded specific gravity, water absorption, and unconfined researchers selected the following characteristics for compressive strength. Six retorted blocks of spent oil the SSA-based grout: shale from Rio Blanco's Tract C-a were used in the tests. These blocks varied from completely retorted to slightly Viscosity 45 - 55 Marsh Seconds retorted samples to simulate the expected variation in a Stability Bleeding <5% MIS retort. The results of the tests are summarized in Setting Time 2 Hours at 150°F Table 2. In addition to good rheological characteristics, the Pilot Plant Tests cured and hardened grout must also demonstrate acceptable mechnical properties such as strength, per- - The two vessels used in the pilot plant tests designed to meability, and durability. The most important para- simulate the anticipated conditions for grouting full-scale

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-27 TABLE 2

PHYSICAL CHARACTERISTICS OF SPENT SHALE RUBBLE

Minimum Maximum Average

Bulk Specific Gravity and Water Absorption

Dry specific gravity, g/cm 3 1.17 1.98 1.48 Soak specific gravity, g/cmS 1.68 2.23 1.89 Water absorption, weight % 7.2 48 30 Unconfined Compressive strength, kg/cm2 Load perpendicular to the bedding 32.3 112.5 69.2 Load parallel to the bedding 16.2 104.8 49.2

*ASTM C97 "Absorption and Bulk Specific Gravity of Natural Building Stone." • ASTM C170 "Compressive Strength of Natural Building Stone."

MIS retorts in terms of spent shale rubble, temperature, TABLE 3 confinement, and grouting pressures. These vessels were approximately 5 feet diameter by 11 feet high and VOID RATIO AND PERMEABILITY OF THE RUBBLE IN were designed to withstand internal pressures of 250 psi THE TEST VESSELS BEFORE GROUTING at 200°F. Nozzles were installed in the vessels' walls and ends to permit grout injection, monitoring, testing, and relief valve installation. A pipe coil was welded to Vessel Vessel each vessel to permit heating with steam. The vessels #1 #2 were also insulated. Bulk volume of rubble, m 3 15.47 15.29 Approximately 20 tons of rubblized retorted shale was obtained from the Laramie Energy Technology Center. Volume of water injected, m 3 7.56 7.49 The spent shale was screened to remove a portion of the fines before loading in the vessels. After the shale Ratio with regard to bulk was loaded in the vessels, it was saturated with water volume 0.489 0.489 to simulate the expected MIS retort conditions and to avoid water loss from the grout to the shale. Volume of water drained out, m3 6.30 4.78 After the vessels were filled with spent shale, the void ratio and permeability of the rubble were measured. Ratio with regard to bulk The results of these measurements are summarized in volume 0.407 0.317 Table 3. Estimated void ratio 0.45 0.40 Prior to grouting, steam was passed through the vessel coils to heat the shale to 170°F. The rubble was then Permeability, cm/s 40 to 60 8 to 10 grouted in three phases, one per day, at successively higher pressures of 100, 150, and 200 psi. For each phase, the grout was injected successively at three levels as follows: At each level, grout was injected until the desired pressure was achieved, and then the pressure was maintained • Bottom, through the four ports simultaneously. for 10 minutes. As the grout was injected, the water in the vessel was forced upward by the grout and was • Middle, successively through two grouting points collected through ports in the vessel lid. After the three diametrically apart. grouting phases were completed, the vessel temperature was maintained at 170°F for a 28-day curing period. • Top, same as middle level. The first vessel was grouted, allowed to cure for 28 days, and tested for permeability. Because these tests were

2-28 SYNTHETIC FUELS REPORT, DECEMBER 1982 encouraging, more stringent conditions were selected both vessels were performed by injecting water at the for the second vessel. The more stringent conditions bottom of the vessels at an average pressure of 130 psi consisted of the following: and collecting the water from the top of the vessels. The initial permeability of vessel #1 was 25 x 10 7 em/s which • The second vessel was filled with all rubble size declined to approximately 7 x 10 7 cm/s after 80 days. fractions including material finer than 6 mesh. The permeability of vessel #2 decreased from 9.5 x 1-6 cm/s to 4 x 10' after 55 days. • The vessel was heated during the three days of grouting and the heat was only turned off during To determine the strength and deformation characteris- the grouting itself. tics of the grouted shale, pressuremeter tests were run in three holes located in the vessels (one hole in Vessel #1 The researchers report that the grouting of the first and two holes in Vessel W. Geotechnical parameters vessel went very smoothly. During Phase 1 (100 psi), interpreted from the pressuremeter test curves indicate most of the grout was injected at the lower level. that the grouted shale mass is a competent engineering During Phase 2 (150 psi), a small amount of grout was material under confined conditions. It is capable of injected at the lower level and a very small amount was sustaining heavy loads without a significant deformation. injected at the middle level. The amount of grout injected during Phase 3 (200 psi) was very small. The Conclusions second vessel was more difficult to grout due to the finer rubble and corresponding lower void ratio. The The researchers conclude that the study demonstrated grouting data for both vessels are summarized in Table that a grout can be formulated using SSA as a base. 4. However, some chemical additives are required to ensure that underground MIS retorts can be sealed successfully. TABLE 4 A surface tailings disposal system will also be needed because not all of the ash that is produced can be used for GROUTING DATA reinjection. The proposed grouting system will require a large quantity of water when used on a commercial scale that may be obtained from the process as well as the mine Volume of Volume of Grout drainage. Therefore, large volumes of water which other- Grout Injected to Volume of Bulk wise would need extensive treatment prior to discharge Rubble Ratio, 96 may be immobilized. The SSA could also be adapted as a Vessel Vessel Vessel Vessel hydraulic backf ill for other types of mining. #1 #2 #1 #2 Phase 1(100 psi) INDEX TO OIL SHALE SYMPOSIA PROCEEDINGS lower level 2.33 1.28 49.5 27.5 ISSUED middle level 0.028 0.60 0.6 12.8 upper level 0.014 0.19 0.3 4.1 The Colorado School of Mines Press recently issued a cumulative index to the papers presented at the Oil Shale Total 2.37 2.07 50.4 44.4 Symposia held at the Colorado School of Mines since 1964. The index, compiled by G. L. Baughman and C. H. Cox, provides a mechanism for locating pertinent information Phase 2(150 psi) in the published proceedings of the symposia held during the past 18 years. lower level 0.056 0 1.2 0 middle level 0.028 0 0.6 0 Over the years, the Oil Shale Symposium has provided a upper level 0 0 0.0 0 forum at which researchers, developers, government agencies, and other interested persons could preserft the Total 0.084 0 1.8 0 results of their efforts, update the status of their projects, or in some cases, voice their opinions regarding the Phase 3 (200 psi) various aspects of oil shale development. The Symposium was jointly sponsored with the Colorado School of Mines 3 levels Research Institute in 1964 and 1965; with the American combined 0.014 0 0.3 0 Institute of Mining, Metallurgical, and Petroleum Engineers from 1966 through 1974; and with the Laramie Total for 3 Energy Technology Center from 1978 to the present. phases 2.47 2.67 52.5 44.4 The new index is divided into four sections, each Water Collected 2.43 1.97 51.5 42.3 corresponding to a mechanism for seeking out information from the Proceedings. The first section, entitled the Chronological Index, is a collection of the Tables of Contents of each of the published proceedings. This During the grouting, the grout was colored to allow section provides a convenient way for researchers to seek identification when the vessels were dismantled. Both information by scanning the titles without going to the vessels were cured for 28 days at 150°F and allowed to individual documents. It also provides an opportunity for cool for 3 days before testing. Permeability tests on investigators to quickly follow the progress of the oil

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-29 shale industry, as the topics presented in any given year tend to mirror the attitudes and concerns of the day. The second and third sections of the Index correlate presentation titles and their location in the Proceedings with the authors and their corporate affiliations, respectively. The last and possibly most useful section, the Subject Index, identifies the papers according to their subject matter using keywords. The information contained in the Oil Shale Symposium Proceedings represents one of the most extensive collections of data currently available, and the addition of the Index as a companion volume increases the usefulness of that information. Copies of the Oil Shale Symposia Proceedings Index may be obtained for $30 from the Publications Department, Colorado School of Mines, Golden, Colorado 80401.

2-30 SYNTHETIC FUELS REPORT, DECEMBER 1982 INTERNATIONAL

YAAMBA JOINT VENTURE SIGNS CONTRACTS FOR The Yaamba Joint Venture is undertaking the study to OIL SHALE FEASIBILITY STUDY determine the environmental, technological and economic feasibility of a commercial facility to mine and to process Yaamba Joint Venture has signed two contracts for a the Yaamba Basin oil shale. The object of the study is to feasibility study on the development of its oil shale evaluate all facets of such a project in sufficient depth, project in the Yaamba Basin in central Queensland, detail and quality as to permit the use of the study results Australia. Bechtel Pacific Corp of Melbourne will in securing financial commitments and the approval to conduct a preliminary feasibility study on mining and proceed with a detailed design of commercial facilities, processing oil shale from the basin, located under the and in the negotiation of franchise agreements with the alluvial plain, 35 kilometers (21 miles) northwest of State and Federal governments. Rockhampton. Peter Hollingsworth and Associates of Brisbane will study the environmental issues accom- The feasibility study has been organized into two phases panying the development and commercial operation of and will include the undertaking and co-ordination of the Yaamba Oil Shale Project. This impact analysis engineering and planning studies in the following project will be carried out coincidental to the mining and categories: processing feasibility study. Both studies are scheduled for completion in early 1983. mining and waste disposal; The Yaamba Joint Venture was formed by Peabody process facilities; Australia Pty. Ltd. and Central Oil Shale Pty. Ltd. in 1980 to explore and assess the oil shale potential of the infrastructure requirements. Yaarnba and other buried tertiary basins that may exist in the region. Other partners in the venture include: Phase I will be a preliminary study to establish costs and Beloloa Pty. Ltd. and Central Pacific Minerals Pty. other factors within an aeeurancy of + 25 percent and will Ltd. Peabody Australia manages the Yaamba Joint be developed within twelve months. Venture, which holds five "Authorities to Prospect" for oil shale in an area of approximately 1,400 sq. km . Phase II will be a detailed bankable study to establish (346,000 acres) in the Rockhampton and Board Sound costs and other factors within an aeeurancy of + 10 region of Queensland, Australia. In addition to the percent and will be developed within eighteen to twenty- Yaamba Basin, the area includes the Rossmoya Basin, four months. located in the alluvial plains of Hedlow Creek east of the Yaamba Basin and Herbert Creek Basin Located to While the study is being performed, the Joint Venture the northwest along Herbert Creek estuary. The will: "Authorities to Prospect" were granted to the Yaamba Joint Venture by the government of the State of • Continue core drilling to further delineate and Queensland. The Fitzroy River, the Bruce Highway and evaluate the oil shale reserves. the Brisbane-to-Cairns railroad all transect the southern part of the Yaamba Basin. • Negotiate surface acreage options within the Yaamba Basin. Exploratory core drilling duiing 1978-1979 disclosed a thick prospective oil shale sequence in the Yaamba • Carry on franchise negotiations with the State and Basin, which occupies an area of about 50 sq. km . Federal governments. (12,400 acres) adjacent to the small township of Yaamba located 30 km. (19 miles) north-northwest of • Review and evaluate the project economics and the city of Rockhampton. financial plans (by the corporate top-management within the Joint Venture) at the appropriate The oil shale deposits occur from 130 to 2,000 feet in decision points during the feaishility study phases. thickness in 12 main seams covering about U square miles. Reserves are estimated at more than 2 billion barrels of in-situ oil. The estimate of in-situ oil reserves and definition of the scams within the oil shale sequence are based on these 'cutoff' parameters: • minimum seam thickness of 3 meters (10 feet)

• minimum in-situ oil content of 63 litres/tonne of shale (15 U.S. gallons per short ton) • maximum overburden of 460 meters (1,500 feet).

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-31 ENVIRONMENT

DRAFT REPORT SUMMARIZES RESULTS OF CUMU- • Scenario I - 2.5 to 3.9% LATIVE IMPACT STUDY • Scenario II - 6.4 to 10.2% • Scenario III - 12.6 to 20.2% The Colorado Department of Health in association with the U.S. Environmental Protection Agency (EPA), Water Quality Impacts Region VIII, has been studying the environmental impacts of energy development. The results of the The preliminary study conclusions indicate that energy study were issued in draft form in August 1982 in a development will not significantly affect surface water report entitled Assessment of Cumulative Environ- quality in the region. This conclusion is based on the mental Impacts of Energy Development in North- assumption that the energy operations will comply with western Colorado. all State and Federal laws. However, temporary water pollution episodes may occur in isolated locations. The study estimates the impacts of energy development on land, air quality, solid and hazardous wastes, and The study was unable to determine possible effects of noise in a six-county region of northwestern Colorado energy development on groundwater due to the need for (Garfield, Rio Blanco, Mesa, Routt, Moffatt, and Delta further research. The study did determine that salinity in counties). The assessment year for the study is the the Colorado River could be adversely affected by energy year 2000. Table I lists the production levels of coal, development in northwestern Colorado. The preliminary natural gas, oil, powerplants, and coal gasification results indicate that the salinity at the Imperial Dam will assumed for the study. In addition to these base case be increased as follows: production values, three scenarios of oil shale production were studied. These oil shale production estimates • Scenario I - 1.6 mg/1 are presented in Table 2. • Scenario Ill - 13.4 mg/I • Municipal wastewater treatment - 0.30 to Population Projections 0.75 mg/I Based on the four energy development scenarios, the Air Quality Impacts following population projections for the six-county region were determined: The air emission rates used in the study are presented in Table 3. These values were input into Complex Terrain • No oil shale - 204,300 and Gaussian Puff air quality models to analyze air • Scenario I - 228,600 quality impacts from suspended particulates and sulfur • Scenario II - 266,900 dioxide (SO ). A limited analysis using a Regional • Scenario III - 329,000 Transport Mdel (RTM) was also performed. The Gaussian Puff model showed 24- and 3-hour violations would occur, These population projections were generated by a com- but when the results were adjusted to represent the RTM puter model developed by Mountain West Research, results, no violations of air quality were predicted. These Inc., and represent stabilized populations after the adjusted results are believed to be more realistic. No completion of construction of the energy facilities. annual violations of air quality standards were predicted. Land Impacts The study also evaluated visibility effects of energy development and found that the visual range would be The preliminary results of the study indicate that the reduced as follows: direct impact of energy development on agriculture will be minimal, but that the associated urban development • Scenario I - 2.9 to 7.3% could remove the following amounts of agricultural land • Scenario II - 7.3 to 9.5% from production: • Scenario Ill - greater than 9.5%

• No oil shale - 5,060 acres Solid and Hazardous Waste Impacts • Scenario I - 7,700 acres • Scenario II - 11,880 acres Although additional research is needed, the preliminary • Scenario III - 18,810 acres study results indicate that spent shale can probably be used to construct stable, non-leaching landforms. The These values assume all urban development will occur study also determined that the types and amounts of on agricultural land and that 110 acres are required for hazardous wastes from energy projects can not yet be each 1000 people. accurately assessed, but many wastes may be designated as hazardous. These wastes include: Additionally, the following amounts of agricultural lands in the area could be affected by the purchase of agricultural water rights for energy development:

2-32 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 BASE CASE PRODUCTION ESTIMATES FOR THE YEAR 2000

Coal Electrical Coal Natural Production Generating Gasification Oil Gas Uranium (tons Net Capacity (million SCF (barrels/ (million cubic (lbslyr) County per year) (megawatts) per day) yr) feet/yr) Delta 2,485,000 20 Garfield 2,810,000 --- 4,200 7,100 Mesa 3,700,000 570 --- 800 2,600 200,000 Moffat 9,795,000 1,290 60 457,000 22,400 70,000 Rio Blanco 3,126,000 ------17,878,000 31,600 Routt 6,290,000 460 --- 148,000 66 (Utah) (760) TOTAL 28,206,000 3,100 60 18,488,000 63,766 270,000

TABLE 2 OIL SHALE PRODUCTION SCENARIOS FOR THE YEAR 2000

Scenario I Scenario II Scenario III Site/Project Name (bbl/day) (bbl/day) (bbl/day) Parachute-Roan Creek Area 1. Colony-(Exxon) 48,000 48,000 48,000 2. Union Oil 50,000 90,000 90,000 3. Chevron-Clear Creek 50,000 100,000 100,000 4. Mobil Oil 15,000 50,000 100,000 5. Cities Service -0- -0- 50,000 6. Naval Oil Shale Reserve -0- -0- 50,000 7. Pacific Shale -0- 15,000 50,000 8. Getty -0- -0- 50,000 Piceance Creek Area 1. Cathedral Bluffs (C-b) -0- 21,000 90,000 2, Rio Blanco (C-a) -0- 50,000 100,000 3. Multi Mineral -0- 50,000 50,000 4. Exxon -0- -0- 60,000 Uinta Basin Area (Utah) 1. White River Project 15,000 57,000 106,000 2. Paraho -0- -0- 42,000 3. TOSCO/Sand Wash -0-S 0 50,000 4. Geokinetics(2 Projects) 2,000 31,000 70,000 5. Syntana -0- 17,000 57,000 Parachute -Roan Area 163,000 303,000 538,000 Piceance Area -0- 121,000 300,000 Uinta Area 17,000 105,000 325,000 Regional Total 180,000 529,000 1,163,000

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-33 TABLE 3

PROJECTED AIR EMISSIONS FOR NORTHWESTERN COLORADO FOR 2000 (tons per year)

Total Total Nitrogen Sulfur Suspended Carbon Scenario Sources Hydrocarbons Oxides Dioxide Particulates Monoxide Powerplants --- 58,050 34,840 6,810 5,920 No Shale Other Sources 10,370 12,360 4,050 180,220 54,350

TOTAL 10,370 70,410 38,890 195,030 60,270

Oil Shale 2,990 13,650 5,200 4,520 1,120 Scenario Powerplants --- 58,050 34,840 6,810 5,920 Other Sources 11,610 13,840 4,530 210,720 60,840

-- TOTAL 14,600 85,540 44,570 222,050 67,880

Oil Shale 3,740 49,750 14,690 8,970 15,150 Scenario Powerplants --- 58,050 34,840 6,810 5,920 11 Other Sources - 13,560 16,170 5,290 246,110 71,060

TOTAL 17,300 123,970 54,820 261,890 92,130

Oil Shale 8,510 75,900 34,520 18,720 22,300 Scenario Powerplants --- 58,050 34,840 6,810 5,920 Ill Other Sources 16,660 19,860 6,500 320,400 87,320

TOTAL 25,170 153,810 78,860 345,930 115,740

1. Oil/water separator sludge Potential Problem Areas 2. Retort water and gas condensate clean-up The preliminary draft report of the study concludes that wastes the following potential problems associated with energy development may exist: 3. Thermal sludge concentrate 1. The implications of converting agricultural 4. Oil upgrading wastes (some wastes may be land to urban uses to meet projected growth. valuable enough to recycle) 2. The agricultural implications of using 5. Green coke (possibly sold to industries for agricultural water rights for energy develop- fuel) ment. 6. Raw shale fines 3. Water quality problems associated with oil and chemical spills and heavy rainfall. 7. Mine water clean-up wastes. 4. The problems associated with increased levels Noise Impacts of hazardous waste generated by energy operations and municipal waste. Present noise levels at the sites of proposed oil shale projects are estimated to be 40 to 45 decibels and are 5. The problems associated with increased noise expected to increase to 80 to 90 decibels during opera- levels-particularly near airports, highways, tion. Noise levels near highways, railways, and airports railroads, and project sites. are estimated to also increase. Additionally, the study concludes that further research is needed concerning the following topics:

2-34 SYNTHETIC FUELS REPORT, DECEMBER 1982

1. The direct and secondary impacts of energy • Conventional petroleum production on the development on wildlife. outer eontinential shelf (OCS) from platforms in the Gulf of Mexico. 2. The impact of energy development on groundwater. • Coal liquefaction modelled after SRC II in Morgantown, West Virginia. 3. The impact of secondary sources, such as population growth and additional power- • Biomass to Alcohol by grain fermentation, plants, on air quality in Class I areas. Central Illinois.

4. The direct and secondary impacts of energy A ninth alternative for NOSE #1 also exists and that development on Class II areas. alternative is a "no action" alternative.

5. The effect of increased sulfur dioxide and The five development options for NOSR #1 are: nitrogen oxide emissions on acid deposition (rain) on high altitude areas. • NOSR #1 is leased to a private entity in the fashion of existing prototype oil shale leases. Study Status • NOSR #1 is developed by a quasi-utility ven- The draft report was widely distributed to solicit com- ture which would be regulated as a utility. ments from industry and the general public. The staff The government would guarantee a negotiated of the Colorado Department of Health is reviewing the rate-of-return in return for the private entity comments that have been received and, where appli- accepting a lower than normal rate-of-return. cable, is incorporating the comments into the final report. This final report is expected to be released in * NOSR #1 is developed by separate ownership early 1983. in which government would own a portion of the facility and a private entity would own the rest.

NOSR #1 and #3 - FINAL PROGRAMMATIC EIS ISSUED • NOSR #1 is developed by a 50-50 joint venture with a private entity wherein the government The Final Programmatic EIS on the Development Policy would receive earnings based on its share of Options for the Naval Oil Shale Reserves in Colorado the equity. has been issued. The object of the EIS is to evaluate and compare the impacts of eight (8) liquid fuel alter- V NOSE #1 is developed by a GOCO (govern- natives available to DOE and evaluate and compare five ment owned - company operated) venture. (5) development options for Naval Oil Shale Reserve Government would own the facility and pay a No. 1 (NOSR #1). NOSR #1 is located on the south- fee to a private entity to operate the facility. eastern flank of the Piceance Creek basin in Garfield County, Colorado. NOSR #1 consists of about 41,000 In each of the five cases, government would get its cut acres which has an inplace resource base of 18 billion off the top in taxes from the private entity. barrels from oil shale averaging greater than 10 gallons per ton (gpt). Of the 18 billion barrel resource only 2.3 Table 1 prepared by Pace after review of the EIS is a billion is projected to be recoverable from oil shale in qualitative summary of the evaluations and comparison of the Mahogany zone averaging 30 gpt or better. NOSR the environmental impacts of the eight liquid fuel alter- #3 (adjacent to NOSR #1) consists of about 14,000 natives. From Table 1 it is apparent that all of the acres and was set aside for the location of processing alternatives to development of NOSR #1 with the excep- facilities and spent shale disposal. NOSR #3 is not tion of "other oil shale development" would result in lower underlain by a significant quantity or quality of oil environmental impacts. shale. An evaluation of the five development options indicated The eight liquid fuel alternatives which were compared that required selling prices (based on 1979 dollars) would and evaluated are: range from a high of $26/barrel for a fully leased-to- industry case to about $17/barrel for the GOCO case. • Development of NOSE, #1 oil shale by One observation pointed out by the EIS is that the underground mining, surface retorting, and ownership by government has a large effect on revenue shale oil upgrading. sources by local governments (city, county, and State) because as the government ownership increases, the • Conservation in the transportation sector, revenue available through local taxes decreases. primarily light duty vehicles. The conclusison of the programmatic EIS is that develop- • Oil shale development on other land ment of oil shale on NOSR #1 was not necessary at the modelled after the Colony Project. time of the evaluations. Further that, a "no action" alternative is identified as the preferred alternative in • Enhanced Oil Recovery (EOR) by steam the EIS. The question of whether or not to develop NOSR injection, Kern County, California. #1 will be reexamined from time to time in the future as will information and analysis contained in the EIS.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-35 TABLE 1

QUALITATIVE SUMMARY OF IMPACTS OF LIQUID FUEL ALTERNATIVES RELATIVE TO OIL SHALE DEVELOPMENT OF NOSR #1

Other Targeted Oil Shale Coal Impact Conservation Development EOR OCS Liquefaction Biomass Energy Efficiency NA - + + - - Air Quality: SO2 - + - + * NO - + - - - UNK CO - - - - - UNK HC - + + + - UNK 'NP - + - - - UNK

Water Requirements - + + - - - Land Use - Solid Waste Production ------Water Quality Degradation - 0 - + - - - Health & Safety Hazards - 0 - - + - Population Impact 0 - - + +

+ Higher than Development of NOSR #1 - Lower than Development of NOSR #1 o Same As Development of NOSR #1 NA - Not applicable UNK - Unknown

AMC/API COMMENT ON PROTOTYPE OIL SHALE organizations found the DEIS to be seriously deficient in LEASING DEIS three areas: air quality, hydrogen, and socioeconomics. The Bureau of Land Management's (ELM) draft environ- The air quality analysis section was cited as being based mental impact statement (DEIS) concerning the Federal upon unrealistic assumptions and unvalidated models, agency's prototype oil shale leasing program was issued which results in erroneous conclusions. For instance, the in July 1982 and the comment period on the DEIS was assumption of wind persistence in a given direction for 24 extended to September 22, 1982. The content of the hours is extremely conservative and not representative of DEIS is discussed in an article on page 2-21 of the available data. The DEIS concludes that serious air September 1982 issue of the Pace Synthetic Fuels quality violations would occur in the baseline or "No Report. Action Alternative" which includes all of the development and land uses reasonably anticipated for the region in the In response to the ELM request for public comment on foreseeable future, but not additional federal leasing. the document, the American Mining Congress (AMC) Because development levels will be controlled by the PSD and the American Petroleum Institute through their permitting process, this implies that the responsible respective Synthetic Fuels Committees sent a letter to agencies, EPA and Colorado Department of Health, would ELM dated September 21, 1982. Based on the under- issue permits that would result in violations of the standing that the purpose of the DEIS is to examine the NAAQS and PSD increment limits. This presumption site specific and potential cumulative impacts of ignores the fact that, by law, developers must comply leasing up to two additional prototype tracts under the with applicable standards. Thus if permit agencies used original 1973 Prototype Oil Shale Leasing Program, the the same unvalidated models and emissions estimates,

2-36 SYNTHETIC FUELS REPORT, DECEMBER 1982 they would not permit the capacity projected in the No Further. information can be obtained by contacting: Action Alternative. Henry 0. Ash, P.O. Box 25007, The hydrologic system of the Piceance Creek Structural Federal Center, Denver, Colorado 80225 Basin is very complex. AMC and API state that the (303)-234-3275 DEIS treats this system in a highly qualitative manner despite the availability of a large amount of quantita- Refer to pages 2-30 and 2-31 of the September 1978 tive information that was not used, e.g., information Cameron Synthetic Fuels Report for additional infor- contained in numerous U.S.G.S. publications. AMC and mation regarding the Oil Shale Environmental Advisory API believe many observations in the DEIS are either Panel (OSEAP). unsupported by the information given, or inconsistent. They also state that the section is poorly organized and clear concise maps and figures are needed. Concerning socioeconomics, the discussion in the DEIS was described by AMC and API as superficial. Specific discussions and inventories of community needs, both collective and individual are believed to be inadequate. On page 10 of the summary, a statement is made to the effect that the key to the impact predictions presented is the actual growth (baseline conditions) which will take place in the absence of additional leasing. It is recognized in the statement that conditions in the area have changed markedly since the analysis of socioeconomic impacts was made. The baseline projections used in the analysis contain key assumptions of rapid and large-scale oil shale development. It now appears likely that development will occur at a more reduced level and spread over a longer period of time. Because the accuracy of the baseline is critical to the reason- ableness of the impacts predicted, the impact assessment as currently presented is considered to be invalid by AMC and API. The findings, if used in the decisionmaking process as intended, may lead to incorrect assumptions and ultimately less than optimal decisions concerning leasing policies. AMC and API state that the analysis is further weakened by the fact that it is incomplete. There is no analysis or discussion, for example, of existing and projected jurisdictional infrastructural requirements and impacts (e.g., schools, water systems, law enforce- ment) or of the existing fiscal conditions and subsequent fiscal impacts of the proposed action. Finally, the AMC/API letters points out a noticeable absence of discussion of key assumptions and metholo- gical procedures.

OIL SHALE ENVIRONMENTAL ADVISORY PANEL CHARTER IS RENEWED On December 3, 1982, the U.S. Department of the Interior announced that it had determined that "renewal of the Oil Shale Environmental Advisory Panel is necessary and in the public interest." The purpose of the Panel is to assist the Department of the Interior in attaining the objectives of the Prototype Oil Shale Program primarily through public review and advice on the environmental aspects of the development of oil shale resources on Federal lease tracts. The General Services Administration concurred in the renewal of this committee.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-37 WATER

WATER APPLICATIONS RELATED TO OIL SHALE No applications or amended applications were filed in the Office of Water Clerk, District Court, Water Division No. 5, Glenwood Springs, Colorado, for any specific uses related to oil shale. However, the United States of America; do John R. Hill, Jr., (U.S. Dept. of Justice; Land and Natural Resources Division) filed for absolute water claims to 28 wells to be used for stockwater and industrial uses. All wells are located in Rio Blanco county and were originally drilled or cored for resource exploratory purposes. information concerning the location and flow rates of the wells can be obtained from the Pace staff.

2-38 SYNTHETIC FUELS REPORT, DECEMBER 1982 RESOURCES

OAK RIDGE ASSESSES CHATTANOOGA SHALE elements. Table 2 is a summary of the elemental constituent data reported by ORNL. An assessment of Chattanooga Shale resources and applicable technology is reported in "Chattanooga From the assessment of resource data, ORNL believes Shale: An Assessment of the Resource and Technology that the Gassaway Member is more attractive for For the Recovery of Hydrocarbons and Minerals," pre- development than the Dowelltown Member because of the pared by the Oak Ridge National Laboratory, report no. geochemical character which would provide higher poten- ORNL/TM-7920, dated April 1982. Oak Ridge National tial recovery of minerals in addition to shale oil. Laboratory, operated by Union Carbide Corporation for the Department of Energy, conducted the study to In order to determine the potential resource base, ORNL assess the viability of commercial development of the considered only that area underlain by the Gassaway eastern Chattanooga Shale to produce hydrocarbons and Member that was greater than 3 meters (9.8 ft) thick and such strategic minerals as uranium. which extends only 8 kilometers (4.8 miles) from the outcrop. This area is shown on Figure 1 as the area "most The ORNL assessment was based on: a literature accessible for mining". The resource of recoverable shale review; a limited number of scouting experiments; and oil was then estimated for this limited area by assuming a the selection of design parameters. The selected design recovery of 0.5 barrels per ton. A recovery of 0.5 barrels parameters provided a basis around which the assess- per ton or 21 gallons per ton (GPT) was apparently based ment was made. The report discusses the resource on ORNL experiments using hydrogen at 500 psi for base, available technology, and presents the results of retorting and the fact that the lOT HYTORT process can economic analysis based on selected design parameters. recover up to 2.5 times more oil than the Modified The costs and selling price of producing only shale oil Fischer assay. Modified Fischer assays from coreholes in and by-products are compared with costs and prices of the area "most accessible for mining" varied from a low producing shale oil in conjunction with other minerals of about 5 OPT to high of 10.8 OPT. The results of contained in Chattanooga Shale. A summary and dis- resource estimates (assuming 21 GPT recovery) indicate cussion of the assessment is presented in the following. that the area most accessible for mining has an in-place resource of about 74 billion tons. Using the recovery Resource Location and Description factor of 21 OPT (0.5 Bbl/ton) there is an in-place resource in that area of about 37 billion barrels. ORNL The Devonian Chattanooga Shale is a black marine assumed a recovery factor for the resource of 50% which shale located in the states of Kentucky, Tennessee, resulted in a recoverable reserve of about , 18 billion Alabama, and Georgia as shown on Figure 1. The shale barrels. In addition to the 18 billion barrels of shale oil, is a stratigraphic equivalent of the New Albany Shale ORNL estimates that 2 million tons of uranium (U30 (located in Kentucky and Indiana) and the Ohio Shale could be recovered. This estimate is made assuming tle (located in Kentucky and Ohio). The Chattanooga Shale Gassaway Member has 60 ppm uranium and recovery outcrops around the Nashville Dome, which is a broad would be 80%. These reserve estimates are based on the upwarp structure. The Chattanooga Shale dips away area "most accessible to mining" only. The entire area from the outcrop along the Highland Rim at generally underlain by Chattanooga Shale would represent a much less than I degree. The shale is subdivided into two greater resource base. members: the Gassaway Member and the Dowelltown Member. The Gassaway overlies the Dowelltown and is Assessment of Mining and Processing subdivided into Lower, Middle and Upper units. The Dowelltown is subdivided into a Lower and an Upper ORNL's assessment of the resource indicated that surface unit. The Upper and Lower units of the Gassaway are mining would be able to recover very little of the total similar in that they consist predominantly of black resource base. Surface mining would be restricted to a shale. The Middle unit consists of dark gray to black contour stripping type operation with a maximum highwall shale with interbedded medium-gray claystone. The height on the order of 85 feet. Bench widths or the width Lower unit of the Dowelltown is primarily black shale of the contour strip would be about 240 feet assuming a whereas the Upper unit consists of gray to dark-gray 20 degree slope of the surface. The primary mining claystones and interbedded shales. Table 1 summarizes method would be underground room-and-pillar mining with the thickness of the Chattanooga Shale and subdivisions mines extending about 5 miles from the entries along the and shows the range in Fischer Assay and uranium outcrop. The mine or system of mines would produce content. 100,000 tons per thy (TPD) of raw shale for processing. ORNL estimated that approximately 55% of the spent ORNL's review of the literature indicates the mineral shale produced could be baekfilled into the mined-out make-up of Chattanooga Shale is predominantly quartz, portions of the mine. The remainder of the spent shale clay minerals, pyrite, muscovite, and sericite. The would have to be disposed of on the surface. other constituents consist of organic carbon and trace

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-39 2? C\ E U,

LEBANON OOKCL1 NASHVILLE CLINTON

TEN -

CHATTANOOGA

HUNTSVILLE G 0 dAT DA'

_ 7 _

KILOMETERS 11.025 5P 0 30 MILES CHATTANOOGA SHALE OUTCROP 1 BOUNDARY OF AREA UNDERLAIN '2 BY CHATTANOOGA SHALE MOST ACCESSIBLE FOR MINING \c (EXTENDING 8 KM (4.8 MILES) LS FROM OUTCROP)

FIGURE 1 LOCATION OF CHATTANOOGA SHALE

2-40 SYNTHETIC FUELS REPORT, DECEMBER 1982 • TABLE 1 CHATTANOOGA SHALE AVERAGE THICKNESS AND RANGES OF FISCHER ASSAY AND URANIUM CONTENT

Range Range Average Fischer Uranium Thickness Assay Content Member/Unit (feet) (OPT) (ppm) Gassaway Member: Upper Unit 8.0 1.5-10.25 65-75 Middle Unit 3.5 4.08.0 3743 Lower Unit 5.4 8.0-12.5 48-61 Total 16.9

Dowelitown Member:

Upper Unit 7.9 2.5-3.5 9-12 Lower Unit 5.6 8.0-10.5 25-35 Total 13.5 Total Chattanooga Shale 30.4

TABLE 2

AVERAGE CONCENTRATION OF ELEMENTAL CONSTITUENTS IN CHATTANOOGA SHALE

Gassaway Member Dowelitown Member Constituent Upper Middle Lower Upper Lower Al,% 5 7 6 9 7 C(organie), % 14 9 14 2 10 Fe,% 6 5 5 3 4 2 3 2 3 2 6 4 4 2 3 Si0 2,% 53 60 54 60 56 Co, ppm 48 35 42 39 25 Cr, ppm 98 103 107 108 142 Cu, ppm 122 118 176 94 192 Mn, ppm 156 216 208 340 266 Mo, ppm 174 107 152 30 129 Ni, ppm 213 137 154 88 222 Ti, ppm 2420 3380 2960 3900 3360 U, ppm 65 40 63 16 37 V, ppm 360 234 232 210 622 Zn, ppm 370 190 204 152 394

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-41 ORNL suggests that the processing plant could be TABLE 6 designed to recover a number of other products in addition to shale oil. Table 3 shows the estimated ASSUMED PRICES FOR PRODUCTS products to be produced from processing 100,000 TPD PRICE ESCALATION AND RATES utilizing four different recovery modes. ORNL's review of the literature and in-house scouting 1980 prices Escalation experiments indicated that the retorting method should Assumed prices ($) (%/Year) be based on the IGT HYTORT process wherein the shale is retorted with hydrogen at 500 psi and a temperature Oil, $/Bbl 35 9 of 12206F. Sulfur and ammonia would be recovered from the product stream. The raw shale oil would be U 309, $/lb 30 9 hydrotreated to produce 46,000 Bbl/d of upgraded oil. moo 31 $/lb 7.50 6 The other products would be recovered by roasting (in S, $/t 45 6 air) the spent shale to remove sulfur and oxidize some of the metals. The roasted spent shale would then be NH 31 $It 155 6 leached with sulfuric acid to recover 60-90% of the metals. ORNL believes that uranium and molybdenum Al 2031 $/t 200 6 could be recovered with only moderate extension of Mixed trace metals 1/2 market existing technology. Alumina recovery is apparently price feasible but would require additional research. Recovery of trace elements (Co, Ni, Cu, Cr, and Zn) are presently only speculative. ORNL selected the IGT FIYTORT process because Overall the assessment made by ORNL is interesting; hydroretorting will produce higher yields of oil than however, the resource at this point in time must be indicated by Modified Fischer assay. IGT has demon- considered as one of very low grade. The Gassaway strated that oil yield by hydroretorting can be 2.5 times Member is thin averaging less than 17 feet thick and the greater than by Fischer assay. Other, studies on potential oil yield even with hydroretorting (about 21 Devonian black shales indicate that methods other than GPT) is low. As an example, a room-and-pillar mine (16 retorting with hydrogen can increase oil yield from foot mine height and 50% recovery) producing 100,000 Devonian black shales above that indicated by Fischer TPO of shale (3,115 tons/ac-ft) for 330 days/yr would assay. These methods include: using an extremely require over 2 square miles of resource per year or over rapid heat up rate; and rapid stripping of shale oil while 40 square miles of resource for a 20 year life. still in the vapor state. Recent studies indicate that. retorting methods such as Chevron's plug flow process, # # # .#, the Lurgi process, and the TOSCO process which have rapid heatup rates may be able to recover up to 200% BLM EXAMINES ERTL CLAIMS of Modified Fischer assay. Retorting with steam The U.S. Department of Interior, Bureau of Land Manage- (steam stripping) is also suggested as a method to improve yield relative to the Fischer assay. ment has let a contract to Energy Minerals Technical Assessment of Golden, Colorado for the examination of a Economics large block of unpatented oil shale claims. These unpatented oil shale claims are located in the Piceance ORNL prepared a discounted cash flow, return on Creek basin in Rio Blanco County, Colorado. The group of claims are known as the Ertl Claims. The locations of investment economic analysis based on the assumed parameters required to recover oil and other products these claims are shown on Figure 1. The Ertl claims from a raw shale feed rate of 100,000 TPD for a plant consist of 132 individual oil shale mining claims (160 acres life of 20 years. Tables 4 and 5 are the estimated each) which total 21,120 acres. The examination was capital and operating costs for the mine, processing precipitated by the submittal to BLM of applications for plant, and spent shale disposal for the four recovery patents on the 132 claims by the claim owners. The modes. Table 6 lists the assumed selling prices of the approximate value of the contract to Energy Minerals products and the escalation rates of the prices per year. Technical Assessment is $190,000. The examination is Table 7 shows the results of the economic analysis. The required by mining law to determine the validity of the rates for general inflation, Federal income tax, and claims. As such, the objective of the examination is to state income tax were assumed to be 6%, 46%, and 6% gather evidence to indicate: if the claims were properly respectively. From the analysis, it appears that the located; if required assessment work was done; and if a valuable mineral deposit was discovered. Oil shale was economic potential of such a project would improve if uranium, molybdenum, and alumina were extracted in withdrawn from location by The Mineral Leasing Act of addition to shale oil. February 25, 1920; therefore, the examination must indicate whether or not the claims were physically located on ORNL's primary conclusion is that the recovery of the ground prior to February 25, 1920. The examination resource values from the Chattanooga Shale is not now and a final report was originally scheduled to be com- or over the future short term economically attractive. pleted by December 31, 1982. However, the schedule has They do, however, have some potential over the future been extended until the middle of January 1983 as ELM long term. In addition, they recommended more has increased the original scope-of-work. detailed analysis of the resource base and the technology required to develop the Chattanooga Shale.

2-42 SYNTHETIC FUELS REPORT. DECEMBER 1982 TABLE 3 ESTIMATED PRODUCTS FROM PROCESSING 100,000 TPD SHALE AT FOUR DIFFERENT RECOVERY MODES

Recovery Mode Oil oi+ u Oil + U Full Only + Me + Me + Al Recovery Oil, Bbl/d 46,000 46,000 46,000 46,000 Sulfur, t/d 2,500 0 0 0 Ammonia, t/d 350 0 0 0 U 309,t/d 0 6 6 6 moo 3,t/d 0 30 30 36 Al20 3,t/d 0 0 2,700 8,100 Mixed trace metals, tld 0 0 0 100 (Co, Cu, Cr, Mn, Ni, Vn, Zn)

TABLE 4

SUMMARY OF ESTIMATED CAPITAL COST (1980 Dollars in Millions) Recovery Mode Oil Oil+ U Oil + U Full Only + Me + Mo + Al Recovery Mining 170 170 170 170 Solid waste disposal 70 70 70 70 Oil recovery plant 1,700 1,700 1,700 1,700 Roasting 25 25 25 25 U + Me recovery 0 400 400 400 First aluminum step 0 0 75 75 Final recovery 0 0 0 710 Tailings treatment 0 85 85 170 Total 1,960 2,450 2,520 3,320

TABLES SUMMARY OF OPERATING AND MAINTENANCE COSTS (1980 Dollars in Millions)

Recovery Mode Oil Oil U Oil + U Full Only + Me + Mo + Al Recovery Mining 125 125 125 125 Solid waste disposal 35 35 35 35 Oil Recovery plant 130 130 130 130 Roasting 15 15 15 15 U + Me recovery 0 75 75 75 First aluminum step 0 0 60 60 Final recovery 0 0 0 380 Tailings treatment 0 35 35 70 Total 305 415 475 890

SYNTHETIC FUELS REPORT. DECEMBER 1982 2-43 ;If.In" ;k11';fl:I t)Ci4IiS;IrI4 ;4I'? P •1 __ 192. m.

- - -

FIGURE 1 LOCATION OF ERTL CLAIMS IN PICEANCE CREEK BASIN

2-44 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 7 SUMMARY OF THE RESULTS OF ECONOMIC ANALYSIS

Recovery Mode Oil - - Oil U Oil+ U Full Only + Mo + Mo + Al Recovery Return on investment, % 23.4 24.2 26.7 23.0 Return on equity, a 30.6 31.8 35.5 30.0 Revenue source,b %: Oil 93 70 59 43 S + NH 7 Uranium 16 14 10 Molybdenum - 14 12' 10 Aluminum 15 31 Trace metals

apor 67% equity and 33% debt at a 9% interest rate. bLevelized using project return on investment as the discount rate.

Phillips Petroleum leased the Ertl claims on April 3, The examination of the Ertl claims will lead to patent of 1980 (see Synthetic Fuels Report, September 1980, page some or all of the claims or result in Interior contesting 2-31). The majority of the ErtI claims ownership Is held the validity of the claims. Thousands of acres of oil shale by the estate of the late Tell Ertl. The lease with land are at stake for both claimants and Interior. From Phillips calls for a primary term of 11 years and has the request-for-proposal to do the claims examination and provisions for extending the lease for 25 years or as subsequent preproposal meetings and communications long as significant mining (over 10,000 TPD) continues. with BLM, it would appear that BLM Will attempt to The lease with Phillips required the claim owners to prove that discovery points in Marlstone tongues strati- undertake diligent efforts to patent the claims. graphically above the main body of the Green River Expenses incurred in taking the claims to patent would Formation are not in oil shales of the Green River be borne entirely by Phillips. The extended term of the Formation. Possible methods for achieving this are lease could begin when the owners secure patent to at arguments surrounding the definition of what is oil shale least 7,500 acres within the 21,120 acre block of in terms of minimum grade in gallons/ton by Modified claims. During the period 1964 to 1969, the Ertl claims Fischer Assay. Tongues of oil shale (marlstone) above the were under option to Shell Oil. During this option main body of the Green River Formation assay relatively period if any of the claims were patented then Shell Oil low (in some instances less than 15 gallons per ton). If would pay $2,000/acre and gain ownership of the BLM could redefine or accept a definition of oil shale patented land. based on a minimum grade of oil shale, certain discovery points could be shown invalid. From a geologic inference On June 2, 1980, the U.S. Supreme Court ruled in favor aspect, BLM may also try to prove that some tongues of of Shale Oil Company and D. A. Shale, Inc., and against oil shale above the main body of the Green River Forma- the Secretary of the Interior involving the discovery of tion Parachute Creek Member do not coalesce with the a valuable mineral deposit on pre-1920 oil shale claims. main body but are an isolated lens of oil shale in the In the early 1960s, Interior took the position that all overlying Uinta Formation. In this case they could argue unpatented oil shale claims were invalid because oil that in some instances there were no discoveries in the shale was not a valuable mineral deposit. Because of Green River Formation oil shale and therefore that that position, Interior would not even consider patent geologic inference prior to February 25, 1920 could not be applications. The Supreme Court decision means that used as evidence by the claimants as to the existence of Interior now must consider each patent application. underlying main body Green River Formation oil shale. Further, if the claimant or predecessors can show that rules of location, discovery and assessment work Many years have passed since the Ertl claims were first (General Mining Law of 1872) were abided by and prove located and the geology of the claims area as well as the the claims were located prior to February 25, 1920, thickness and grade of underlying oil shale have since then Interior is obliged to grant patent. become well known. The claims obviously overlie valuable oil shale, as intended by the original locators using geologic inference or intuition, or just blind luck. If

SYNTHETIC FUELS REPORT. DECEMBER 1982 2-45 the claimants or their predecessors did abide by the rules (of location, discovery, and assessment) and evidence indicates that the claims were located prior to February 25, 1920, then those claims should be patented as were hundreds of other oil shale claims between 1948 and 1954. The upcoming activities related to the Ertl claims "applications for patent" will undoubtedly affect other unpatented oil shale claimants either positively or negatively and therefore bear watching.

2-46 SYNTHETIC FUELS REPORT, DECEMBER 1982 SOCIOECONOMICS

IMPACT FUNDS REQUESTED BY COLORADO LOCAL TABLE 1 GOVERNMENTS COLORADO COUNTIES IN THE OIL SHALE REGION In late October the Energy Impact Advisory Committee RECEIVING IMPACT FUND ASSISTANCE received 72 separate requests from governmental (Through 1981) agencies for financial assistance. The agencies were requesting grants from the Impact Fund that was established by the Colorado state legislature in 1977 to assist communities in coping with energy impacts. The 11. Garfield County 16% $5,215,000 two-day meeting of the committee was the third and 2. Moffat County 12% $3,785,000 final round of requests for Impact Fund monies for 1982. Total amount of all requests was approximately 3. Delta County 11.5% $3,690,000 $13 million, but only $6 million remained in the Fund 4. Mesa County 10.7% - $3,438,000 for this year. The total amount of Impact Funds available for all of 1982 was approximately $25 million. 5. Routt County 10.3% $3,292,000 This amount is significantly more than in previous years 6. Montrose County 4.7% $1,512,000 due to the addition of a new Colorado severance tax on oil and gas. Approximatley $15 million was generated 7. Rio Blanco County 4.1% $1,326,000 by the severance tax while the remaining $10 million came from mineral leasing revenues paid to the Federal government and then returned to the State. NOTE: Percentages shown are relative to the total awards made from the Impact Fund through 1981. The Impact Fund is administered by the Colorado Department of Local Affairs headed by Morgan Smith. Other members of the Advisory Committee include: Ira McKeever, the industry representative from W. R. Grace; Jane Quimby, a member of Mesa County's Planning Commission; Bill Brennan, State Highway Commissioner; Chips Barry, Deputy Director of the state Department of Natural Resources; Gene Aiello, a banker from Trinidad; Roy Brubacher, Assistant Com- missioner of Education; Falven Cerise, Garfield County Commissioner; and B. J. Thornberry, member of the Craig City Council. In previous years, seven western Colorado counties have received approximately 69% of the available assistance from the Impact Fund. These counties, as listed in Table 1, encompass the oil shale region of the Piceanee Creek basin. However, with the addition of the oil and gas severance tax revenues, many other areas of the state are now eligible for assistance. Hence, the competition for the available Impact Funds is expected to become more intense. Additionally, some requests for assistance are now associated with the recent "bust" of oil shale following Exxon's postponement of the Colony project. The definition of impact has been expanded to include a lack of growth as well as the rapid growth during "boom" periods.

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-47 STATUSOFOIL SHALLE PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Amoco Rio Blanco Oil Shale Company (C-a) ...... 2-52 Atlantic Richfield Company Paraho-Ute Project ...... 2-51 Braun, C.F., & Company Naval Oil Shale Reserve Development ...... 2-55 Central Pacific Minerals Rundle Project ...... 2-51 Chevron Shale Oil Company Chevron Clear Creek Project ...... 2-50 Paraho-Ute Project ...... 2-51 Cleveland-Cliffs Iron Company Paraho-Ute Project ...... 2-51 Pacific Project ...... 2-51 Conoco, Incorporated Paraho-Ute Project ...... 2-51 Chevron Clear Creek Project ...... 2-50 CSR Limited Julia Creek Project ...... 2-54 Davy McKee Corporation Paraho-Ute Project ...... 2-51 Equity Oil Company Equity Oil Company ...... 2-54 Esso Australia Ltd. Rundle Project ...... 2-52 Exxon Company USA Exxon Colorado Shale Project ...... 2-54 Colony Development Operation ...... 2-50 Geokinetics, Inc. Geokinetics, Inc ...... 2-54 Agency Draw Project ...... 2-54 Wolf Den Project ...... 2-54 Gulf Oil Corporation Rio Blanco Oil Shale Company (C-a) ...... 2-52 Gulf Research & Development Co. Naval Oil Shale Reserve Development ...... 2-55 Husky Oil Company Paraho-Ute Project ...... 2-51 Magic Circle Energy Corporation Cottonwood Wash Project ...... 2-53 Mobil Oil Corporation Mobil Parachute Oil Shale Project ...... 2-50 Mobil Research & Development Corp. Paraho-Ute Project ...... 2-51 Mono Power Company Paraho-Ute Project Multi Mineral Corp. Multi Mineral Corporation ...... 2-55 Occidental Oil Shale, Inc. Cathedral Bluffs Shale Oil Company (C-b) ...... 2-50 Logan Wash Operations ...... 2-51 Placid Refining Paraho-Ute Project ...... 2-51 Paraho Development Corporation Paraho-Ute Project ...... 2-51 Petrobras Petrosix ...... 2-52 Phillips Petroleum Company White River Shale Project (U-a/b) ...... 2-53 Paraho-Ute Project ...... 2-51

2-48 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization - Project Name

Quintana Minerals Corporation Syntana-Utah Project ...... 2-55 Rio Blanco Oil Shale Company Rio Blanco Oil Shale Company (C-a) ...... 2-52

Southern California Edison Paraho-Ute Project ...... 2-51 Southern Pacific Petroleum Rundle Project ...... 2-52 Standard Oil Company (California) Chevron Shale Oil Company ...... 2-50 Paraho-Ute Project ...... 2-51

Standard Oil Company (Indiana) Rio Blanco Oil Shale Company (C-a) ...... 2-51 Standard Oil Company (Ohio) Pacific Project ...... 2-51 Paraho-Ute Project ...... 2-51 White River Shale Project (U-a/b) ...... 2-53

Sunoco White River Shale Project (U-a/b) ...... 2-53 Paraho-Ute Project ...... 2-51

Superior Oil Company Pacific Project ...... 2-51 Synthetic Oil Corporation Syntana-Utah Project ...... 2-55 Tenneco Cathedral Bluffs Shale Oil Company (C-b) ...... 2-50 Texaco Incorporated Paraho-Ute Project ...... 2-51

Texas Eastern Synfuels, Incorporated Paraho-Ute Project ...... 2-51 Tosco Corporation Naval Oil Shale Reserve Development ...... 2-55 Tosco Sand Wash Project ...... 2-53 TRW Naval Oil Shale Reserve Development ...... 2-55 Union Oil Company of California Parachute Creek Shale Oil Program ...... 2-51 U.S. Bureau of Mines USBM Shaft ...... 2-55 U.S. Department of Defense Naval Oil Shale Reserve Development 2- 55 U.S. Department of Energy Equity Oil Company ...... 254 Geokinetics, Inc ...... 254 Naval Oil Shale Reserve Development ...... 2-55 Occidental Oil Shale, Inc ...... 2-51 Paraho-Ute Project ...... 2-51 Williams Bros. Engineering Co. Naval Oil Shale Reserve Development ...... 2-55

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-49 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since September 1982) SYNTHETIC FUELS FROM OIL SHALE COMMERCIAL PROJECTS CATHEDRAL BLUFFS SHALE OIL CO. - Occidental & Tenneco (T3S, R96W, GPM) Bonus bid of $117.8 million paid to acquire rights to Tract C-b in 1974. original partners, ARGO and TOSCO, withdrew in 1975. A third original partner, Shell, withdrew 11/76. Occidental joined (with Ashland as remaining partner) 11/76. Ashland withdrew 2/14/79. On 9/4/79, Tenneco acquired half interest for $110 million. Modified DDP for 57,000 BPD modified in situ plant submitted March 1, 1977. ODP approved 8/30/77. EPA issued conditional P50 permit 12/16/77. Three headframes, two of concrete and one of steel, have been erected. Designated gassy mine 1/2/80. Ventilation/Escape, Service, and Production shafts completed in fall 1981. outfitting of head frames and shafts completed December 1982. A modified development plan is being prepared. No new construction is being started during the reevaluation period. Site workforce has been reduced to a standby crew of approximately 20. Project Cost: $50.5 million spent in 1980. $76.5 million spent in 1981. $31.0 million spent in 1982 CHEVRON CLEAR CREEK PROJECT - Chevron Shale Oil Company, Standard Oil Company of California, and Conoco, Inc. (TSS, R98W, GPM) Chevron plans to have a semi-works 350 TPD plant in operation in Salt Lake City by late 1983 using Chevron's Staged Turbulent Bed (STB) retort. The company has not chosen the processing technology it will use commercially, and process evaluation by Foster-Wheeler will continue while the STB retort is developed. The planning and front- end engineering contractor is Morrison-Knudsen. Construction of commercial plant northwest of Del3eque, Colorado would begin in 1987, and full capacity production by modular increases to 50,000 BPD would be achieved by early 1991. Continued modular increases to 100,000 BPD are expected in early 1990s. Foster-Wheeler awarded $45 million contract 10/81 to design and engineer 350 TPD STB retort in Salt Lake City. Work is underway on draft EIS. Permitting is being coordinated through the Colorado Joint Review Process. Under an agreement finalized January 31, 1982, Conoco exchanged about 690 million tons of recoverable coal from Illinois, Montana, and West Virginia for about 30% of Chevron Shale Oil Co.'s interest in the project. Project Cost: $5 million in 1979 $16 million in 1980 $28 million in 1981 Semi-Works - Estimated at $100 Million COLONY SHALE OIL PROJECT - Exxon (TSS, R95W, GPM) Proposed 47,000 BPD project on Colony Dow West property near Parachute, Colorado. Underground room-and-pillar mining and TOSCO II retorting planned. Production would be 66,000 TPD of 35 OPT shale from a 60-foot horizon in the Mahogany zone. Development suspended 10/4/74. Draft EIS covering plant, 196-mile pipeline to Lisbon, Utah, and minor land exchanges released 12/17/75. Final EIS has been issued. EPA issued conditional P50 permit 7/11/79. Land exchange consummated 2/1/80. On August 1, 1980, Exxon acquired ARCO's 60 percent interest in project for up to $400 million. Preferred pipeline destination is now Casper, Wyoming, and Final EIS is completed. Work on Battlement Mesa community commenced summer 1980. Colorado Mined Land Reclamation permit approval October 1980. Site development is proceeding. C.F. Braun awarded contract 12/80 for final design and engineering of Tosco II retorts. Brown & Root will construct the retorts. Stearns-Roger awarded contract 2/81 for design and construction liaison on materials handling and mine support facilities. DOE granted Tosco $1.1 billion loan guarantee 8/81. On May 2, 1982, Exxon announced a decision to discontinue funding its 60 percent share of the present Colony Shale Oil Project. Tosco responded to the decision by exercising its option to require Exxon to purchase Tosco's 40 percent interest. Exxon is undertaking an orderly phasedown of the project. Construction of Battlement Mesa will be continued on a reduced scale. An Exxon organization will remain in Parachute area to perform activities including reclamation, some construction, security, safety, maintenance, and environmental monitoring. Project Cost: Estimated in excess of $3.4 billion and up to $6 billion MOBIL PARACHUTE OIL SHALE PROJECT - Mobil Oil Corporation (T65, R95W, GPM) Mobil is proceeding with development plans for its shale property located four miles north of Parachute. Construction is now planned to begin in the late 1980's that would achieve 100,000 SPO production in the late 1990's. Underground room and pillar mining will be used along with on site surface retorting and upgrading. Mobil has asked the U.S. Bureau of Land Management to prepare an Environmental Impact Statement schedule in anticipation of

2-50 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 COMMERCIAL PROJECTS (Cont.)

future permit applications. Bechtel Petroleum, Inc., awarded contract 8/81 to provide engineering and construction services. Project Cost: Estimated $8 billion for 100,000 BPD production OCCIDENTAL OIL SHALE, INC., LOGAN WASH (T7S, 1197W, 6PM) Occidental has developed its modified in situ retorting technology on its Logan Wash Operations site near De Beque, Colorado. Field tests were begun in 1972. Initial tests were conducted on three experimental-size retorts, measuring 30 feet square by 72 feet high. Nearly thirty thousand barrels of oil were produced from the first commercial-size retort between December '75 and June 176. A $60.5 million cost-sharing contract was signed 9/30/77 with DOE. Production from Retort 5 was 11,287 barrels. Retort number 6 was rubblized 3/25/78 and produced nearly 55,000 bbls, of which 48,100 bbls were recovered and stored. P50 permit for Retorts 7 & 8 awarded 11/1/79. Retorts 7 and 8 which measure 165 feet square by 246 feet high were ignited in January and February of 1982 and have been processed simultaneously. Production as of November 1982 was over 192,000 barrels of shale oil. Project Cost: $177 million spent to 11/30/92 on Phase land II of DOE Cooperative Agreement with $38 million contributed by DOE. $60.5 million DOE cost-sharing contract PACIFIC PROJECT - Superior (20%), Sohio (60%), and Cleveland-Cliffs (20%) (T6S, 11981V, 6PM) Sohio, Superior, and Cliffs are evaluating development plans for the Pacific Property. Phase I, Superior's engineering design and environmental work for a 15,000 BPD demonstration plant utilizing Superior's circular grate retort under a cooperative agreement with DOE, was completed in September 1982 and will serve as a basis for finalizing the time schedule for detailed design, procurement, and construction on the demonstration module plant. Phase II, which is being handled by Sohio for the Venture Partnership, includes follow-on environmental baseline for a commercial size plant (50,000 to 100,000 BPD)- Phase II also includes geotechnical and engineering feasibility scenarios with economics for expanding to a commercial plant size. Phase II is expected to be complete early in 1983. Cleveland-Cliffs applied to the U.S. Synthetic Fuels Corporation (SFC) for a loan guarantee under the SEC's second soliciation that ended June 1, 1982. However, the project did not pass the SEC's maturit y tests. THE SUPERIOR RETORTING PROCESS - Superior continues to provide testing and process designs for various oil shale deposits both domestic and foreign Project Cost: Not available PARACHUTE CREEK SHALE OIL PROGRAM - Union Oil Company of California (T5S, R9W, 6PM) Union owns 30,000 acres of fee land in the Parchute Creek area in northwestern Colorado, including 20,000 acres of oil shale resource land. These lands contain some 1.6 billion barrels of recoverable oil in the high yield mahogany zone alone. Construction is underway on a 10,000 barrel per day facility which will become the first commercial shale oil facility in the United States when produciton begins in 1983. The UNISI-IALE "B" upflow retort is under construction. Union's "B' indirect retort is a modification of their direct-heated, rock pump retort which was field tested with a demonstration plant in the late 1950's which produced as much as 800 barrels of shale oil a day. A facilities area has been excavated in Union's underground room and pillar mine to accommodate a change house, warehouse, maintenance shops, and shale crushers which are now being installed. An upgrading plant which will convert the raw shale oil into high quality synthetic crude oil is also under construction. A rail spur to the upgrading plant was completed 5/82. Daniel Construction Company is the prime contractor for Union's project. Daniel also operates a housing complex on site for single status workers. DOE awarded Union a $400 million purchase agreement 7/81, under which the DOD will purchase 3,000 BPD of JP-4 and 7,000 BPD of DFM/DF-2, based on a June 30, 1981 price of $42.50 per barrel of product. The project cost is estimated to be $600 million. Union has entered the Colorado Joint Review Process to permit an expansion to total production of 90,000 BPD by 1993. Project Cost: Approximately $600 million PARAHO-IJTE SHALE OIL FACILITY - Paraho Development Corporation, Chevron, Conoco, Davy McKee, Mobil, Mono Power, Phillips, Sohio, Sunedco, Texas Eastern, Cleveland-Cliffs, Texaco, ARCo, Husk y, and Placid Refining (T95, R25E, Sec. 32, SUM)

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-51 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 COMMERCIAL PROJECTS (Cont.)

Paraho had a Phase I design cooperative agreement, signed 6/80, with DOE, leading to construction of an 18,000 TPD retort module producing 10,000 BPD. DOE funded $4.4 million of the 18-month study, and the Paraho Participants are providing $3.7 million. Paraho Development Corporation completed, in December 1981, the detailed engineering design of a 10,000 BPSD commercial Paraho retort, designated a module. Also completed as of April 1982 is the Commercial Feasibility Study (CFS), analyzing the general engineering and design of a three-retort Paraho commerical facility. The CPS concluded that such a facility is feasible. Paraho Development Corporation and Davy McKee Corporation have formed the Paraho/Davy McKee Shale Oil Systems, a joint venture to develop and market the Paraho process. Paraho and Davy McKee Corporation jointly submitted a proposal on June 1, 1982 for a loan guarantee and possible future price guarantees to the Synthetic Fuels Corporation. The project passed the SFC's project maturity and project strength tests and was advanced into Phase II consideration for financial assistance. However, on December 2, 1982, the SFC announced it had some past or possibly new sponsor The Paraho-Ute Facility will be located on shale land controlled by Paraho in Uintah County, Utah. Additional land acquisition is ongoing. The Facility is currently designed to produce nearly 40,000 BPSD of hydrotreated shale oil, with hydrotreating occurring on site. Paraho will take a phased development approach, operating the first retort for 14 months before construction begins on the second and third. Project Cost: $8.1 million for Phase I module design. $1.8 billion (1981 $) for 39,000 BPCD PETROSIX - Petrobras (Petroleo Brasileiro, S.A.) A 2,200 TPD Petrosix demonstration retort located near Sao Mateus do Sul, Parana, Brazil. The plant has been operated successfully new design capacity in a series of tests since 1972. A U.S. patent has been obtained on the process. A 50,000 BPD plant is now being designed. Preliminary indications favor a scaled-up facility about five miles from existing site. Part of commercialization project is underway, viz, mine expansion, engineering of the retort, and equipment procurement. Partial operation will begin in 1985, and full capacity will be reached in 1987. Cold flow tests have been completed on 11-meter kiln. This is a scale-up factor of four over the existing 18-foot inside diameter retort. Project Cost: Total expenditures in excess of $200 million Projected cost of 50,000 BPD plant is $2 billion RIO BLANCO OIL SHALE COMPANY - Gulf & Standard (Indiana) (T2S, R99W, 6PM) Proposed project on federal Tract C-a in Piceance Creek basin, Colorado. Bonus bid of $210.3 million to acquire rights to tract; lease issued 3/1/74. Completed four-year modified in situ demonstration program at end of 1981. Burned two successful retorts. First retort was 30' x 30' x 166' high and produced 1,876 barrels of shale oil. It burned between October and late December of 1980. Second retort was 60' x 60' x 400' high and produced 24,444 barrels while burning from June through most of December of 1981. Program cost $132 million. Company still prefers open pit mining-surface retorting development because of much greater resource recovery of five versus two billion barrels over life of project. Cannot develop tract efficiently in that manner without additional federal land for disposal purposes and siting of processing facilities. Need congressional legislation to permit Interior Secretary to lease such land. Rio Blanco is currently constructing a $29 million one to five TPD Lurgi pilot plant at Gulf's Research Center in Harmarville, Pennsylvania. Detailed engineering and planning for open pit-surface retorting development are being carried on at company's Aurora office. The company has not as yet developed commercial plans or cost estimates. Project Cost: Four-year process development program cost $132 million No cost estimate available for commercial facility. RUNDLE PROJECT - Southern Pacific Petroleum /Central Pacific Minerals (50%) and Esso Australia (50%) Development of the Rundle deposit in Queensland, Australia. In April 1981, two-module Phase I was shelved due to economic and technical uncertainties. New agreement between Esso and SPP/CPM on 5/27/81. Esso will commit to a minimum of A$30 million (US$33.6 million) directly on work program over first 3 years, and not less than a further A $20 million (US$22.4 million) should Esso elect to continue for a further 2 years (9/81 CSFR, 2-3). A similar project agreement (see 3/82 Synthetic Fuels Report, page 2-13) was signed on 12/18/81 and took effect in March 1982. Project Cost: See above

2-52 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 COMMERCIAL PROJECTS (Cont.)

TOSCO SAND WASH PROJECT - Tosco Corp. (T9S, R2IE, SLM) Proposed 47,000 BPSD project on 17,092 acres of state leases in Sand Wash area of Uinta basin near Vernal, Utah. State-approved unitization of 33 non-contiguous leases required $8 million tract evaluation, which has been completed. Minimum royalty of $5 per acre begins in 1984 and increases to $50 per acre in 1993. On site environmental assessments have been completed, and applications for right-of-way permits for roads, water pipeline, inter-block conveyors, utility corridors, and product pipeline were submitted to BLM in April 1981. EIS preparation is underway and final EIS is scheduled for issue in early 1983.. Application for the PSD permit was submitted to EPA in June 1981, and the permit was granted on December 10, 1981. Tosco has completed a core hole drilling program on the Sand Wash site as a preliminary step to shaft sinking and establishment of a development mine. The development mine would confirm economics and provide a basis for enhancing the mine plan and projected recovery ratios for the commercial project. Tosco plans call for the building of a TOSCO II surface retorting plant to process up to 66,000 TPD of 34 GPT oil shale, and to produce up to a nominal 50,000 barrels per day of shale oil. Project schedule is under review. The Ralph M. Parsons Company completed a contract for preliminary design and cost estimate in June 1982. Tosco is negotiating with potential additional equity participants in the project. Project Cost: In excess of $1 billion UNION LONG RIDGE PROJECT - Union Oil Company of California (T5S, R95W, 6PM) (See Parachute Creek Shale Oil Program - Union Oil Company of California (T5S, R95W, 6PM) WHITE RIVER SHALE PROJECT - Phillips, Sohio & Sunoco (Tie, R94E, SLM) Proposed joint development of Federal lease Tracts U-a and U-b in the Uintah Basin near Bonanza, Utah. Bonus bid for Tract U-a was $76.6 million by Sun (now Sunoco) and Phillips. Bonus bid for Tract U-b was $45.1 million by White River Shale Oil Corporation (jointly owned by Phillips, Sohio and Sunoco). Rights to Tract U-b subsequently assigned to Sohio. Both leases issued 6/1/74. Initial Detailed Development Plan (DDP) filed with Interior 6/76 proposes modular development with ultimate expansion to 100,000 BPD. The Final Environmental Baseline Report was issued on 11/15/77 by WRSP. Application for one-year suspension of lease terms granted 10/76 based on environmental considerations. This suspension was superseded by a court injunction suspending the lease terms based on property title questions. On April 30, 1980, WRSP filed suit in U.S. District Court (Salt Lake) to preserve its investment beyond statute of limitations date. On May 19 0 1980, U.S. Supreme Court ruled against Utah by reversing lower court's decisions in the in-lieu case. The injunction order suspending the U-a and U-b federal lease terms was uncontested and in full force and effect until March 1, 1982 when it was lifted at the request of White River. Updated draft DDP submitted to Interior November 1980. Final draft DDP was submitted for approval September 1, 1981. PSD permit application submitted to EPA/UBAQ 8/28/81. DDP was approved by the Oil Shale Office on March 2, 1982. PSD permit approval expected by August 1982. WRSP's planned Phase I facility includes two Union B demonstration retorts along with an upgrading plant to produce 15,000 BPD of upgraded shale oil. WRSP also plans additional pilot plant work on circular grate retort technology. Prime contractor is The Ralph M. Parsons Co. Ultimate configuration is planned to be four Union B, two Tosco II, and five circular grate retorts. The first phase of the project, scheduled to be operating by 1989, includes underground mining of 27,000 TPD. If successful, the plant will be expanded in two more stages to an ultimate capacity of 106,000 BPD by the mid 1990's. Project Cost: Estimated at $1.0 billion for Phase I Total project cost around $5.0 billion R&D PROJECTS COTTONWOOD WASH PROJECT - Magic Circle Energy Corporation The 76,000 acres of State of Utah oil shale leases currently owned by Magic Circle Energy Corporation were acquired from Western Oil Shale Corporation through a stock exchange in July 1980. The proposed project will be on a 6,370-acre parcel (10,254 acres when land trade in complete) called "Cottonwood Wash." The remaining acreage is in small, non-continuous parcels which are currently being evaluated for exchange purposes to provide for additional commercial properties. In December 1980, Magic Circle decided to initiate a project to explore development of the Cottonwood Wash site. Science Applications performed feasibility studies, permit applications, and environmental evaluatons. Synfuels Engineering and Development, Inc. has updated the feasibility studies, advanced permit applications, and submitted an application to the U.S. Synfuels Corporation for a loan guarantee and price support.

SYNTHETIC FUELS REPORT. DECEMBER 1982 2-53 STATUS OF SYNPUELS PROJECTS (Underline Denotes Changes Since September 1982) R&D PROJECTS (Cont.)

Small scale (20' diameter) retort (Paraho technology) will be used to process 70,000 tons/day of 26 gallons/ton oil shale. The room-and-pillar mine would be 1,500 to 1,900 feet below the surface. The production will be 33,000 BBLS/day of crude shale oil. The project is currently in the planning and preliminary design phase with Synfuels Engineering and Development Company, the primary contractor. The project sponsors applied to the U.S. Synthetic Fuels Corporation (SFC) for a loan guarantee and limited purchase agreement under the SFC's second solicitation that ended June 1, 1982. However, the project did not pass the SFC's project maturity tests. Project Cost: Capital cost estimated at $900 million. EQUITY OIL COMPANY Equity received a $6.5 million contract from ERDA in June 1977, for development of in situ technology using superheated steam. The work is being conducted on a one-acre site in the Piceance Creek basin of Colorado. The first phase of the contract has been completed which involved drilling two core holes near a previous steam injection site. Site evaluation has been completed. Start-up of field project occurred 6/79. Repairs and evaluations reduced operations temporarily. Small amounts of shale "tar" produced November 1980. DOE funding ended 9/30/81. Equity will continue the project at its own expense. Steam injection was stopped in January 1982 and the formation allowed to cool sufficiently to start secondary recovery techniques for removing deposited shale oil. Two corcholes will be drilled. DOE will use some residual funds for Sandia to keep instruments operating in exchange for Equity's test results of secondary recovery experiments. Project Cost: DOE cost-sharing contract for $6.5 million. EXXON COLORADO SHALE PROJECT - Exxon Coal USA, Inc. Exxon is studying the possibility of building a 60,000 BPCD shale oil plant in northwestern Colorado in two 30,000 BPD modules. Exxon has oil shale reserves in the Piceance Creek basin of Colorado which total about 9 billion barrels of oil-in-place. However, properties are in small scattered tracts. On 12/28/79 Exxon petitioned BLM to exchange scattered acreage for consolidated federal acreage. Delineation of work required for environmental impact study has been initiated. Status: Planning. Project Cost: Not determined

GEO1CINETICS, INC. - (TI4S, R22E, Sec. 2, SLM) in Uintah County, Utah Geokinetics has been conducting field tests in Uintah County, Utah to develop horizontal in situ retorting technology since 1975. Obtained ERDA contract 7/77 to develop technology in thin horizontal beds of oil shale. Porosity is established in formation by raising the shallow overburden during explosive fracturing of the shale formation. Total production to end of June 1, 1982, was about 50,000 barrels. Retorts 24, 25, and 26 are the same size (217' x 230' x 30' in 22 GPT shale). Retort 24 was ignited early December 1980; operation was stopped 7/23/81 with total production of about 12,000 barrels. Retort 23 (50' x 100' x 241), ignited late March 1981. Retort 25 blasted 8/7/81; ignited in early November 1981; operation was stopped 6/15/82 with total production of 21,000 881.. Average production was about 100 aND. Retort 26 blasted in October 1981. Retort 27 blasted on February 27, 1982. Retorts 27 and 28 will be the same size (300' x 330' x 30') and cover twice the area as 24, 25, and 26. FY82 funding was initially to have been $2.7 million, but was reduced by 4% to $2.59 million. All funds have been received. Under the U.S. Synthetic Fuels Corporation (SFC) second solicitation that ended June 1, 1982, Geokinetics requested both loan and price guarantees for two projects in Uintah County, Utah. The Wolf Den project would utilize Geokinetic's true in situ technology to produce 3500 BPD of shale oil. The Agency Draw project would employ Tosco II surface retorting to produce 16,000 BPD of shale oil. Neither proposed project passed the SFC's project maturity tests due to lack of equity sponsors.

Project Cost: DOE cost-sharing contract valued at $13.6 million JULIA CREEK PROJECT - CSR LIMITED Preliminary investigation underway to determine feasibility of a 100,000 BPD project in Julia Creek deposit of northwestern Queensland, Australia. Project would likely involve surface mining, aboveground retorting, and on site upgrading to produce a premium refinery feedstock. Average shale grade is 17 to 22 GPT by Fischer Assay. Detailed feasibility study planned before final technology selection. Goal is to reach full-scale production by 1990.

2-54 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since September 1982) R&D PROJECTS (Cont.)

Although no firm decision on process selection has been made, CSR's feasibility study is based on TOSCO II. Feasibility study indicates additional study is warranted. CSR is seeking partners in project. Project Cost: A$300 million for a 5,000 BPD pilot plant. MULTI MINERAL CORPORATION - U.S. Bureau Of Mines Shaft (T15, R97W, Sec.30, 6PM) USBM began drilling 10-foot diameter, 2,400-foot deep shaft 3/77. Objective was to mine samples of oil shale, naheolite, and dawsonite from shale formation. Shaft may be used for ventilation in future experimental mine. Drilling operations were completed 10/2/77 at 2,371 feet. Shaft classified as gassy mine. Shaft development was to commence in July 1982. Multi Mineral Corp. (MMC) has performed experimental mining and stope rubblization at the 2,130' level. Slope will measure 64 x 40 x 110' tall. Test mining is complete and project is in stand-by condition. Rock mechanics tests and methane monitoring were conducted. Construction is on hold on an 8' diameter, 40' tall, 80-ton true adiabatic retort in Grand Junction awaiting partners. Laboratory facilities have been completed, but the laboratory and administrative offices in Grand Junction have been closed. Project Cost: Over $8 million for shaft sinking. NAVAL OIL SHALE RESERVE DEVELOPMENT - TRW Inc. Navy issued RFP 6/77, calling for preparation of Master Development Plan for Naval Oil Shale Reserves 1, 2, and 3. Objective is to put NOSR in position for large scale development of resources within five years. Contract awarded 6/22/78 to team composed of TRW, CF Braun & Company, Gulf Research & Development Company, Williams Bros. Engineering Company, and Tosco Corporation. Comparative analysis of NOSR 1 and eight other Piceance Creek basin properties has been completed. Draft EIS issued September 1980. The U.S. Department of Defense formally transmitted a proposal to the U.S. Synthetic Fuels Corporation (SFC) in August 1982 seeking financial assistance to develop commercially NOSR-1. Project Cost: $2.16 million through 10/1/79 $60 million in 4 annual options SYNTANA-UTAH PROJECT - Synthetic Oil Corporation, Quintana Minerals Corporation In 1979, the Synthetic Oil Corporation of Oklahoma City was formed to pursue the development of facilities leading to production of a refinable crude derived from Utah oil shale resources. The founders of Synthetic Oil Corporation, in turn negotiated access to state-owned mineral leases in Utah as the basis for the available resource. In the third quarter of 1980, the Synthetic Oil Corporation was joined by Quintana Minerals Corporation of Houston, Texas, the two corporations forming a new joint venture known as Syntana-Utah. Syntana-Utah in turn was chartered to pursue the same objective as initially defined by the Synthetic Oil Corporation; however, in pursuit of this objective the joint venture now draw's on a broader base of management, technical and financial resources to develop a new private sector venture. An initial business plan for the joint venture was prepared in August 1980, and in October 1980 the Utah Department of Natural Resources (Division of Land and Forestry) was advised as to the long-term oil shale commercialization objectives of the joint venture. Subsequently, Syntana-Utah gave its approval for initial activities supporting the facility development, with fdurth quarter 1980 activities concentrating on further quantification of the in-place resources and assays as well as first efforts to develop an engineering definition of both the deep mine and surface retorting facilities. The project management submitted a proposal to the U.S. Synthetic Fuels Corporation with a request for financial incentive support to continue project development with total capitalization, to represent a combination of private sector funding along with that of the U.S. Synthetic Fuels Corporation. Syntana-Utah currently plans to produce 16,500 to 57,000 barrels/day by the early 1990s from 25 gallons/ton oil shale. Syntana-Utah has spent over $3 million, and it projects a cost fo $1.2 billion for a 16,500 barrels/day facility. The retort process has not been selected. Davy McKee and Morrison-Knudsen are the primary contractors for Syntana-Utah. Currently, the project is participating in a Regional EIS which was issued in draft form August 1982. Air quality (PSO) and other permits are being pursued. Project Cost: $1.2 billion for 16,500 BPD

SYNTHETIC FUELS REPORT, DECEMBER 1982 2-55 RECENT OIL SHALE PUBLICATIONS

Albulescu,, Peter, Foster Wheeler Energy Corp, "Upgrading Shale Oils Obtained in Vapor Phase," presented at the AIChE 1982 Annual Meeting, November 14-1, 1982, Los Angeles, California. Allred, V. Dean, "Oil Shale Processing Technology," available from The Center for Professional Advancement, Publications Division, P.O. Box H, East Brunswick, NJ 08816-0257. Basceanu, Valeriu, loan Hales, Constantin Cazacu, Institutual de Cercetari Si Proieetari Echipamente Termoenergetice, "Specific Problems of Rumanian Oil Shale Utilization by Firing in Energy Boilers," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982. l3ekri, Arneur, Chef de Divison Adjoint des S.B., ONAREP, "The Status of the Timandit Oil Shale Project," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982. Chakkaphak, Director General, Department of Mineral Resources, "Development of Oil Shale and Lignite in Thailand," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982. Crowl, Daniel A. and Robert A. Pieeirelli, Wayne State University, "Model Studies of Ignition and Retort Strategies for True In-Situ Retorting of Antrim Oil Shale," In Situ, 6(2), 77-106 (1982). Crawl, Daniel A. and Robert A. Piccirelli, Wayne State University, "An Assessment of Transport Processes Using a Combined Pyrolysis-Combustion Model for the Retorting of Oil Shale," In Situ, 6(3), 231-258 (1982). Daniels, Jeffrey I., Lynn R. Anspaugh, and John M. Ondov, Lawrence Livermore National Laboratory, "Summary of Air Quality Regulations and Recommended Guidelines for Oil Shale Development in the Colorado Piceanee Basin," February 1982, UCRL-52992. Exxon Company, U.S.A., Interim Site Plan: Development & Extraction Mining Permit No. 80-47. Ferraro, Paul and Paul Nazaryk, Colorado Department of Health, "Assessment of the Cumulative Environmental Impacts of Energy Development in Northwestern Colorado: Status Report," presented at the 15th Oil Shale Symposium, April 28- 30, 1982. Johnson, D. R. and R.S. Tolberg, Chevron Research Co., "Shale Oil Hydroproeessing," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Jones, James E., Shiela S. Farthing, Kentucky Department of Energy, and Tom RobI, Institute for Mining and Minerals Research, "Kentucky's Synthetic Fuels Program and Oil Shale Development Potential," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982. Lee, R. E., Jr. Syntana-Utah, "The Commercial Development of the Syntana-Utah Oil Shale Project," presented at the Synfuels' 2nd Worldwide Symposium, October It, 1982. Lew, Lawrence E., and Joseph M. McKee, Phillips Petroleum Co., "Upgrading Shale Oil for Processing in Existing Refineries," presented at the AIChE 1982 Annual Meeting, Los Angles, California. Mallon, Richard G.," Preparation and Injection of Grout from Spent Shale for Stabilization of Abandoned In-Situ Oil Shale Retort," Journal of Petroleum Technology, July 1982.

Mashin, V. N., at al, Ministry of Oil Refining and Petrochemical Industries, "Industrial Experience in the Production of Shale Oil from Large Particle Baltic Oil Shale," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982.

Ondov, J. M., at al, Lawrence Livermore Laboratory, "Measurements of Potential Atmospheric Pollutants in Off-Gases from the Lawrence Livermore National Laboratory's 6-Tonne Retort, Experiment L-3," available from National Technical Information Service, 5285 Port Royal Road, Springfield, VA 22161 ($6/copy). Reviewed in this issue.

2-56 SYNTHETIC FUELS REPORT, DECEMBER 1982 Paraho Development Corporation, "Paraho-Ute Project Technical Report," June 1982. Robinson, Earl T., and Charles G. Evin, Standard Oil Co. (Sohio), "Commercial Scale Hydrotreating of Paraho Shale Oil," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Rolniak, P., and Joseph J. Leto, Pace Company, "Upgrading and Refinery Acceptability of Western Shale Oil," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. - Ronchetto, J., et al, Lawrence Livermore Laboratory, "Application of Thermally-Activated Gas Canisters in MIS Oil Shale Retorts," presented at the 1982 Symposium on Instrumentation and Control for Fossil Energy Processes, June 7-9, 1982, Houston, Texas. Schamaun, John T., Richard J. McAniff, Larry K. Warne, Sandia National Laboratories, "Resistive Heating for Oil Shale Retorting," Sandia Report: SAND8I-2122, UC-91, August 1982. Schruben, Dale L., "A Down-Scaled Unit to Study lneompatibiit Reactions in Shale Oil-Petroleum Coprocessing," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Shang, J.Y., et al, "Oil Shale Utilization at Morgantown, WV," U.S. Department of Energy, Morgantown Energy Technology Center, Morgantown, WV 26505, DOE/METC-82-8 (DE82011781). Sikonia, John C, et al, "Shale Oil Upgrading for FCC Conversion," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Tait, A.M., et al, Amoco Oil Co., "Direct Upgrading of Whole Shale Oil Into Transportation Fuels," presented at the AIChE 1982 Annual Meeting, November 14-19, Los Angeles, California. U.S. Department of Energy, "Development Policy Options for the Naval Oil Shale Reserves in Colorado: Final Programmatic Environmental Impact Statement," August 1982, DOE/EIS-0068 F. Watson, George H., Standard Oil Co. (Indiana), Eugene A. Ziemba, Rio Blanco Oil Shale Co.; Paul Sissery and Dominique Namy, Soletanche & Rodio Inc.; Robert L. Griffis, Colorado School of Mines Research Inst.; and David E. Nicholson, USBM, "The Filling of Oil Shale Mines With Spent Shale Ash; Ash Characteristics and Grout Development," presented at the 57th Annual Fall Technical Conference and Exhibition of the SPE of AIME, New Orleans, LA., September 26-29, 1982. Violetta, D. C., Davy McKee Corp., "The Development of the U.S. Eastern Oil Shales," presented at the Synfuels' 2nd Worldwide Symposium, October 11, 1982.

Reviewed in this issue.

SYNTHETIC FUELS REPORT, DECEMBER 1982 1 - 2-57 V. PROJECT ACTIVITIES

GNC, CHEVRON PROCEED WITH TAR SAND PROJECT In the fall of 1981 GNC decided to demonstrate the process and initiated a large scale plant, up to 200 tons GNC Energy Corporation's interest in converting tar per day capacity. The design engineering contract was let sands to a salable syncrude dates back to 1976. to a metallurgical engineering firm with the criteria being Through 1977 and into 1978, the company studied the that every piece of equipment had to be of current geology, land ownership and location of U.S. tar sand manufacture and in the field of the 100,000 ton per day deposits. Utah's Sunnyside Deposit was chosen as most category. A plant site was chosen in downtown Salt Lake desirable because the vast majority of the deposit was City to further demonstrate the environmental accept- held in private hands and the U.S.G.S. had given it an ability of the process, the low water usage and the ease of indicated reserve of 4 to 6 billion barrels in place. The waste disposal. Ten thousand tons of material were deposit was amenable to modern large scale open pit quarried from GNC's deposit, 6,000 tons were crushed in mining methods and also environmentally acceptable. standard crushing equipment and 3,000 tons were hauled The location of Sunnyside is not close to scenic parks to Salt Lake City with the balance placed in storage on and recreation areas, nor too near a large population land at Sunnyside. The plant is exceeding design expecta- center to preclude permitting. It is in an area of tions and bulk samples of the concentrates and liquid intense coal mining activity with similar permitting products have been received by both ERCO and Foster- requirements. It has labor, water, power and markets Wheeler to complete the processing to marketable available in close enough proximity to satisfy the infra- synfueL structure requirements at minimum cost and the socioeconomic impact would be negligible. Delayed coking tests were made by Foster-Wheeler and theoretical ART CAT tests by Engelhard to prepare a Leases were acquired on the most favorable ground on feedstock for a Chevron hydrotreater to produce a stabi- terms and conditions that would lead to commerciali- lized feedstock, free of sulfur, metals and nitrogen, to zation for the leases and still give GNC the time to deliver to a common carrier crude pipeline some 35 miles bring such a large project to fruition. Figure 1 shows distant. the location and ownership of the GNC properties. The St. Mary/Cosby Lease consists of 600 acres of patented Pyrolizer tests on the concentrated product were run placer mining claims, 100% owned by GNC through simultaneously in Energy Resources Company (ERCO) lease with 1/12th royalty. At the Schonlan lease, they fluidized bed tests facility at Cambridge, Massachusetts, have 240 acres of patented placer mining claims and to obtain comparative cost and yield studies. 60% interest in another 640 acres of claims. GNC holds 8,000 acres of surface rights at Jay Pagano Ranch and The GNC Energy Corporation's Sunnyside Tar Sands 600 acres of both surface and mineral rights. GNC also Project produces 34,675 barrels per operating day of 350 has five 40-acre state hydrocarbon leases, 160 acres of API gravity synthetic crude oil (syncrude) from 37 million Federal oil and gas rights, and approximately 3,000 tons per year of tar sands ore with an average bitumen acres in Federal land claims. Detailed geologic content of 8.2 weight percent. mapping and diamond core drilling stretched through 1979, 1980, and 1981 seasons, delineating the deposit GNC Energy Corporation has developed the technology to and thoroughly defining the source. After considerable concentrate the bitumen in Utah tar sands to 30-percent research, the decision was made to extract the resource by weight utilizing ambient temperature flotation tech- via open pit mining methods and a contract was entered niques. The bitumen/sand separation is completed using into with Morrison-Knudsen to commence with a mine liquid/liquid extraction. This technology is now being plan utilizing large scale open pit methods. used in a semiworks plant in Salt Lake City to confirm the beneficiation unit design criteria. Consecutively with the mining research, the extractive technology was searched and R & D on the part of GNC The mine is designed to move 75 million tons of material was initiated. GNC decided to take the approach of a year using four 25-cubic-yard shovels and 170-ton treating the entire operation as a large scale mining trucks. Based on the average stripping ratio, 38 million project. The majority of the sand is concentrated tons of waste has to be moved so that 37 million tons of before purifying, reducing the material handling tar sands can be mined. problems. Over 250 bench scale flotation tests were run proving the theory to be correct. Keeping the The mine, primary crushing, and ore conveyor operate 19- bitumen in a solid form and treating it as such enabled 1/2 hours per day, 350 days per year. The secondary the engineers to design around equipment standard to crushing and all downstream processing operations are the mining industry. Drawing upon the experience of designed to operate 24 hours per day, 330 days per year. separating resin from coal via solvent extraction and Two ore piles located at the plant site provide the surge liquid-ion-exchange in uranium band copper, the purifi- capacity to allow for smooth operation at both the mine cation step again was resolved via standard demon- and the plant. strable procedures with known cost-- and materials.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-1

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SYNTHETIC FUELS REPORT, DECEMBER 1982 3-3 The ore from the mine containing 49,116 barrels of is used, syncrude production is estimated to increase by 9 bitumen per operating day (BPOO) is delivered directly percent to 37,835 BOPO, and there would be no by- to two gyratory crushers which crush the ore to minus product coke. However, several technical questions 10 inches. The crushed ore is conveyed 5.11 miles to require further testing before the process can be proposed the two ore piles at the plant site on a cable-belt as the primary process. The syncrude product will be conveyor. Since the conveyor is moving the material pumped from product storage through a 50-mile long 10- 2,360 ft downhill, the conveyor system is designed to inch pipeline to Myton, Utah, where it joins the Chevron produce 8.3 megawatts of electric power. This power Pipeline Company pipeline. From this point the syncrude feeds into the project electrical system, and reduces can be sent to Salt Lake City for refining. the purchased power requirements. Standard Oil Co. of California has signed an agreement in Figure 2 shows the process schematic. principle with GNC Energy Corp. to developed the proposed tar sand to synthetic crude oil facility. Under the The ore from the ore piles is conveyed to secondary agreement, Socal can acquire 75% in the holdings with an crushing where six seven-foot cone crushers reduce the investment of $18 million, or it can withdraw from the ore to minus two inch. project after investing a minimal $3 million. In the first phase of the project, the sponsors will be drilling and The minus two inch ore containing 52,091 BPOD of analyzing samples, as well as fine-tuning the commer- bitumen feeds tertiary crushing where seven seven-foot cialization of the GNC process. If the project proceeds, short head cone crushers reduce the ore to minus 3/4 Socal is expected to provide $50 million for a 2,000 BPD inch. demonstration plant. Ultimately, an expansion to a 40,000 SF0 facility, estimated to cost $1 billion is The crushed ore from tertiary crushing feeds fourteen planned. 15-foot by 20-foot rod mills in the milling section. In addition to the ore, trona, water and 2,500 SF00 of fuel oil are fed to the rod mills. The ore is ground at a pulp density of 50 weight percent solids. The round CEDAR CAMP TAR SAND PROJECT IS PROPOSED ore is 20 weight percent plus 28 mesh. During the spring of 1982, Mono Power Co. (a wholly The rod mills discharge into a sump from which the owned subsidiary of the Southern California Edison slurry containing 52,091 BPOD of bitumen is pumped Company) and Enercor submitted the Cedar Camp Tar into the conditioning tanks in the beneficiation units. Sand Project as a "site specific" synthetic fuel project to be included in the lJintah Basin Regional EIS. The project The conditioning tanks allow for the residence time and was based upon published resource data and upon labora- agitation required to achieve the effective separation tory technological process data. of the bitumen from the sand. In addition to the ore, a recycled tailings stream from the liquid/liquid extrac- Shortly after the EIS program began the proponents tion unit containing 2,492 BPOD of bitumen is fed to initiated a resource exploration/evaluation program to the conditioning tanks. verify the published data and to pinpoint the project's mining centers. In addition to this resource evaluation, The conditioned slurry containing 54,583 SF00 of bitu- Enercor began initial operations in its 50 barrel per day men is fed to the flotation unit where the bitumen is Salt Lake City pilot plant. The initial results of the concentrated to 25 weight percent. The 25 weight exploration program suggested that the published data percent product contains 49,772 SPOD of bitumen. The required further verification. In addition, the operation tailings, which have a bitumen content of 0.82 weight of the pilot plant on various tar sand ores from within the percent, contain 4,811 BPOO of bitumen. P.R. Springs deposit indicated that further refinement of the extraction process was also necessary. Therefore, the The concentrated bitumen from the beneficiation unit proponents subsequently changed the submitted project's is fed to the liquid/liquid extraction unit where it is status from "site specific" to "conceptual." contacted countercurrently with kerosene at 150°F. The bitumen is dissolved in the kerosene, the solids are Enercor and Mono Power hold tar sand bearing oil and gas water wet and stay in the aqueous phase. The hydro- leases in the southern area of P.R. Springs, as shown in carbon phase goes to solvent recovery where the kero- Figure 1. While not confirmed by an actual coring sene is distilled from the bitumen. The aqueous phase program, the present reserves held by the project partners is recycled to the conditioning tanks. The solids are are believed to be sufficient to support a major tar sand then discarded through the flotation unit to the tailings operation (maximum sized 50,000 BPD plant) for a period pond. This recycle reduces bitumen losses. of twenty years. Bitumen recovery through the liquid/liquid extraction The current conceptual studies envision the construction phase is 90.8 percent. Of the 52,901 BPOD of bitumen of a major 50,000 SF0 tar sand processing plant fed to the plant, 47,280 SF00 of bitumen are fed to the associated with a surface mine in the P.R. Springs area upgrading unit. (the Cedar Campsite). Construction of this facility could take place as early as 1985 with full production possible in The bitumen from solvent recovery will be processed the early 1990's. Road improvement, utility connections, either in a delayed eoker unit or using the Englehard and site development work would occur prior to actual Minerals and Chemical Corporation's Asphalt Residue plant construction. The conceptual P.R. Springs Tar Sand Treating (ART CAT) process. If the ART CAT process Recovery Project is outlined in the "Project Description

3-4 SYNTHETIC FUELS REPORT, DECEMBER 1982 .nn•

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FIGURE I ENERCOR-MONO POWER TAR SAND LEASE HOLDINGS

SYNTHETIC FUELS REPORT, DECEMBER 1982 - 3-5

For The Uintah Basin Regional £15" submitted by Mono It is anticipated that a large construction and permanent Power Company and Enercor. work force would be required to support a project of this size. The largest community in proximity of the concep- The process flowsheet for the proposed project is shown tual project is Grand Junction, Colorado which is 85 miles in Figure 2. The anticipated major process require- to the east of the proposed site. Because this is not ments include 300 tons per day of soda ash for an considered a reasonable commuting distance to the pro- approximate annual consumption of 100,000 tons ject site a new town nearer the plant is considered the (15,000 tons of the soda ash would be used in sulfur most reasonable option to support the potential project scrubbing.) The fuel for the plant's boilers would be workforce. The project proponents completed a "Land primarily obtained from burning the process gases and Evaluation Study and Concept Plan for New Town Alter- by-product coke which would be produced within the native" and have included it in the report as Appendix B. upgrading process. Should insufficient by-product fuel The study addresses four major topics for consideration be produced a portion of the product would be used. for a new town. They are 1) Existing conditions; 2) Site These fuels are expected to contain less than 0.5% of Reconnaissance; 3) Socio-economic Considerations and 4) sulfur. The burning of these fuels will require the Alternative Site Selection. utilization of best available control technology (BACT). For an ultimate 50,000 BBL/D process facility, approxi- The tar sand project would be planned in three phases. mately 12,000 annual acre feet of water would be Phase I would provide for all infrastructure (pipelines, required. This water would be used within the proces- roads, transmission lines, and support buildings) and an sing areas and for other miscellaneous needs such as initial productive capacity of 15,000 BPD. Subsequent mine dust suppression and water would be obtained additionsto productive capacity would be made in Phases from available water resources such as the White or the II and ill which could add 20,000 BPD and 15,000 BPD, Green Rivers. If the point of diversion is from either of respectively. Phase II could also include the erection of a these two rivers, the water would be pipelined to a 25- 6 MW power station to provide a portion of the facility's acre water storage pond (at the plant site) via an power consumption. underground pipeline. The total conceptual plant area would be expected to A project mining plant is contained in Appendix A of approximate 700 acres and would include the following the Project Description, titled "Preliminary Mining Plan facilities: for the Cedar Camp Mine, Grand and Uintati Counties Utah". The plan describes in detail the possible • A two belt 10,000 foot long conveyor system for sequence ofa mining program thorugh its various delivering ore from the mine and returning tailings phases to full production of an annual 50-million tons of (spent tar sand) to the mine for backf ill. tar sand mining operation placed at or near the Cedar Camp Canyon location. It addresses potential, but • Radial stackers for storage and bucketwheel unproven, mine reserves; production requirements, and excavators for reclamation of both tar sand ore stripping requirements. Equipment and personnel and subsequent tailings. requirements are also discussed in detail.

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3-6 SYNTHETIC FUELS REPORT, DECEMBER 1982 • A modular crusher building to reduce ore to the and hydrocarbon gas. The gas would be used for inplant proper size for processing. gas fuel needs and the petroleum coke burned in plant boilers to produce steam. Possible co-generation of • A modular processing building to extract the electric power is planned as an option. bitumen from the ore. All plant combustion gases would be cleaned in a common • A modular bitumen clean-up building to separate scrubber system using BACT to remove sulfur and parti- bitumen from entrained water and sand. culates prior to venting to the atmosphere. • A modular, outdoor coking, fractionating and Syncrude product would be pipelined to the rail terminal distillation facility to separate the bitumen into at Westwater for unit train transportation to customers. marketable products and recover processing All water would be recycled in the process with the solvents. exception of 10% to 15% which is retained in the waste sand. • A modular boiler house for production of steam for process heating and possibly for a small Enercor and Mono Power will continue to evaluate the turbine generator. feasibility of a P.R. Spring Tar Sand Project and will identify the associated impacts as the study progresses. • A modular building for dewatering of tailings. Included would be three outdoor thickeners approximately 400 feet in diameter. ENERCOR RAINBOW PROJECT OUTLINED IN PUBIS • A 25 acre lined water storage pond. A preliminary draft EIS has been issued for the Enercor • A 100,000 BBL product tank farm and pumping tar sands project. This project would be located in the station. north P.R. Springs tar sands deposit south of Bonanza, Utah on State of Utah land. The current plan calls for the • A modular flue gas scrubbing plant with 500 construction of an initial 2,000 BPD (syncrude) tar sand million SCFD total capacity. processing plant and associated surface mine that would be expanded to 5,000 BPD (syncrude). The present • A 25 acre lined waste water evaporation pond. reserves held by Enercor would sustain operation at 59000 BPD for 10 to 20 years. Construction of this facility • Maintenance building for both process facilities would take place in 1983 with production in 1985. The and mine equipment. plant would consist of a hot water extraction process plant and a delayed coker. • A change house for the 1,200 to 1,500 man operating labor force. Enercor Demonstration Plant Mine Plan • Warehouses, diesel storage tanks, soda ash silos, Enercor intends to develop a tar sand mine in connection and other raw material storage facilities. with the demonstration plant on State of Utah land. This mine area called the Rainbow Mine, is located in Uintah • An administration building for staff personnel. County in Section 32, T.125., R.25E., and Section 36, T.12S., R.24E., about 11 miles south of the former The operation of the P.R. Springs tar sand facility Rainbow, Utah townsite. The initial mining will occur as would occur in the following manner: partially crushed close to the plant site as is possible. The pay zone of tar sand ore would be moved from the surface mine interest is the top of the Douglas Creek member of the area via an overland conveyor to the plant site on a 24- Green River formation located approximately 20 feet hour per day, 330-day per year basis. below the ground surface. The operation of the mine could be increased by incre- Mine development at the Rainbow Mine will start with ments until a maximum of 50 million tons per year of topsoil removed from the plant site which will be stock- ore could be mined. It is expected that these tar sand piled for later use in reclamation of the plant site and reserves would be exhausted by the 20th year of full spoil areas. Excess earth not needed for leveling the operation. plant area will be spoiled in hollow or valley fill site. A stockpile (5 day supply) of tar sand would be stored at During construction of the plant, mine haul and develop- the plant to give surge capacity between mine and ment roads, sedimentation ponds, development drilling plant. From the stockpile the ore is further crushed and prestripping at the first mining area will proceed. and processed in the hot water extraction unit of the plant. The spent sand, from which the tar has been Mining for the first year of production is scheduled in the removed, would be stockpiled and subsequently returned eastern mining zone of Section 32, T.125., R.25E. The to the mine for reclamation via overland conveyor. eastern mining zone of Section 32, approximately 1,200 It x 3,900 ft, has an average net pay zone thickness of 15 The crude bitumen or tar would be mixed with a light feet. The tar sand from this area along with the tar sand hydrocarbon produced in the subsequent delayed coking mined from the plant site will supply the maximum step and further cleaned of sand and water. The requirement of 5,600,000 tons per year of tar sand ore cleaned bitumen would be fed to a delayed coker (17,000 T/day x 330 day). producing the syncrude liquid product, petroleum coke

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-7

The net pay zone in the western half of Section 32 is 20 Site Data feet thick. The maximum yearly plant feed requirement of 5,600,000 tons required mining of 85 acres per The plant site is generally typical of the semi-arid year, or put in other terms, a yearly mining block of western high desert with minor amounts of percipitation 1,950 feet square or equivalent will be mined. and surface vegetation. A truck haul back system using the ore haulers to The plant site is located in a Prevention of Significant return the damp plant sands back to the mine pit will be Deterioration (PSD) Class II area, which allows air quality used for all mining areas. Mine spoil will be placed in deterioration associated with moderate, well controlled the mined out areas along with the waste sands from growth. the plant. Reclamation of the spoil piles will follow the mining operation. During the mining of the tar sands in The soils at the plant sites are relatively unproductive, Section 32T., 12S., R.25E., a three mile long haul road shallow, and well drained, with moderate to slow per- will be constructed to provide access to the tar sands in meability. Run-off is rapid and erosion potential is high. Section 36, T.125., R.24E. This road will follow the ridges south of Section 32 and 36. Average barometric pressure at the plant site to be used for design purposes is 11.0 psia (198°F NBF). As the reserves are exhausted in Section 32, mining will Average maximum temperature 85°F US. commence in Section 36. The tar sands in this section Design maximum temperature 90°F 08. are about 20 feet thick. Average minimum temperature -15°F. Design wet bulb temperature 67°F. Mining in this section will continue in the same manner Maximum wind velocity 75 MPH in gusts. as in Section 32 with spoils being placed in the mined Average wind velocity 10 MPH from south and west. out area along with the damp sands hauled back from Design rainfall 2 inch/hour - 10 year maximum. the plant. The mining area will be returned to the Average rainfall 9 inch/year. approximate original contour and reclaimed in Maximum recorded snow depth 40 inches per storm. accordance with regulatory requirements. Excess spoil Minimum temperature above freezing from April 15 to generated at the initial cut and an amount equal to the October 15. volume increases of the overburden during mining will Average number of days below 0°F - 10 be placed in a properly designed head of hollow or below 32°F - 50 valley fill in accordance with regulatory requirements. below 60°F - 200 Reclamation of spoil areas in Section 36 will follow below 100°F - 360 mining in the same manner as for Section 32 reclama- Low risk seismic zone. tion. Frost penetration 36 inches. The stripping ratio is approximately 0.9 cubic yards of Process Description overburden per ton of tar sand in Section 32. Average overburden depth in Section 36 is 70 feet from which a The basic hot water extraction process developed for stripping ratio of 2.2 yards of overburden per ton of tar Utah tar sands consists of the operation of a series of sand is derived. processing modules in parallel. Each module has a capacity to recover from the tar sand ore feed approximately The specific mining equipment utilized at this mine will 1,200 BPD of crude bitumen. Two to five modules will be include a front-end loader and 100 ton truck operation installed in the demonstration plant. Enereor will demon- with dozer ripping of overburden and dozers pushing strate the technical and economic success of the basic material to the loaders. Mining operations are process module prior to undertaking the investment in a scheduled for three shifts per day, 330 days per year. large facility. The total mining operation will require 43 vehicles, including loading, hauling, drilling, dozing and auxilliary The process flow scheme for the proposed plant consists transportation. A total of 123 personnel are required to of the following unit operations as shown in Figure 1. operate the mine and maintain the equipment. Office, supervisory, and wage personnel are included in the Ore Preparation total. Run-of-mine ore is delivered to the plant site in bottom Demonstration Plant or rear dump trucks. After truck unloading, the ore is immediately moved via feeders and conveyors to a two Enercor plans to build the 2,000 to 5,000 BPD demon- stage crushing circuit where the ore is reduced in size stration plant on their Utah State combined hydro- from R.O.M. to 100% minus 1/4 inch. carbon lease property, at a location designated as the Rainbow site. Hot Water Processing Expansion of this demonstration facility to 25,000 BPD The crushed ore is processed in closed conditioning vessels is possible pending successful negotiations for addi- with hot recycle water containing a small amount of soda tional ore reserves in the immediate area. ash. During conditioning, bitumen is separated from the sand. The bitumen-sand-water slurry is then processed in an air flotation cell where the bitumen is separated from the sand and water.

3-8 SYNTHETIC FUELS REPORT. DECEMBER 1982 0

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SYNTHETIC FUELS REPORT, DECEMBER 1982 Sand-Water Separation Bitumen The water is separated from the clean sand in a spiral The bitumen associated with the tar sand ore has the classifier-thickner circuit for recycle in the process. following characterization and composition: The wet sand is returned to the mine site via truck or pipeline for disposal in the mine area from which it was Carbon, % 85 mined as part of the mine reclamation process. Hydrogen,% 11.4 Nitrogen, % 1.0 Bitumen Cleanup Sulfur, % 0.5 C/H atomic ratio .60 0 to .65 The crude bitumen produced in flotation is further Vanadium (ppm) 25 cleaned of sand and water in a mixer-settler system and Nickel (ppm) 120 distillation column. A recycle coker naphtha is added Specific Gravity 0.985 to the bitumen to reduce viscosity and assist in the API Gravity 12.0 cleaning process. Carbon Residue (rammsbottom) 7 Asphaltenes (pentane) 10 Bitumen Upgrading Average M.W. (VPO-benzene) 939 Heating Value (BTU/lb) 18,500 The crude bitumen is upgraded to naphtha and gas oil in % Volatiles at 530°C TBP 50 a delayed coking unit. These products are stabilized for Initial B.P. 450°F direct sales to oil refineries as synthetic crude oil. The gas produced is used as plant fuel along with the coke. Soda Ash Excess coke, if any, would be sold as fuel. The soda ash used in the process will be regular commer- Steam Production cial grade light soda ash delivered to the plant in 25 ton bulk pneumatic transfer trucks from manufacturers in the Coke and gas produced in the delayed coker unit will be Green River, Wyoming area. burned for production of steam for process heating. A small turbine generator may be incorporated to supply a Diluent portion of the plant's power needs. Bottom ash from the boilers will be returned to the mine as fill. Bitumen diluent used in the cleaning step in the process will be a normal coker naphtha with 300°F - 350°F Gas Cleaning boiling range, 100 6 ? flashpoint, 50 0 API. This material is prpduced in the process. Boiler flue gas and other process gas, totaling approximately 50 MMSCFD, will be treated in a spray chamber Flocculant with soda ash to neutralize sulfur gases and pass through an electrostatic precipitator to remove the The high molecular weight polyacrylamide flocculating particulates produced before discharge into the agent used in the process will be received in dry bulk and atmosphere. mixed to a working solution in the plant. Plant Feed Stocks and Storage Requirements Storage Tar Sand Ore An emergency five day stock pile of R.O.M. tar sand ore (ultimate capacity 85,000 tons-two acre area) will be Run-of-mine tar sand ore containing between 6-1/2 to maintained at the plant site for emergency processing 10% by weight bitumen wilF be delivered to the plant when the mine is not in operation. This ore would be site from the surface mine in 100 ton trucks on a 24- moved from the stockpile to the primary crusher by front- hour basis. Bulk density of R.O.M. ore is 100 lbs/ft3. end loader during mine production outages. A similar area will be set aside for spent sand. A maximum of 17,000 TPD of ore is required for full plant production at 6-1/2 wt.% bitumen content. The A 30 day supply (300 tons) of soda ash will be provided in sand associated with the ore is essentially 100% alpha a silo type storage bin. quartz cemented together with bitumen. The individual sand particulates have the following particle size distri- Synthetic crude oil product (naphtha and gas oil) storage bution: of 10 days (50,000 BBL) will be provided at the plant site. Floating roof tanks will be used with vapor recovery Volume fraction larger Particle Size systems. This product will be metered and loaded into than indicated size mesh 200 BBL tank trucks (25 per day), via two loadout stations for shipment to customers. 98% 250 85% 150 Tankage for crude bitumen intermediate product diluted 25% 75 with solvent of 5 days (50,000 BBL) will be provided 15% 35 (Floating roof tanks V.R.). 0% 20 Diluent storage of 25,000 BBL will be provided (Floating roof tanks V.R.).

3-10 SYNTHETIC FUELS REPORT, DECEMBER 1982 Plant Utility Systems time for plant startup. The planned storage capacity of 105,000 acre-feet and annual yield is estimated as 250,000 A 125 psig plant air system and a 100 psig plant instru- acre-feet. ment air system is considered. The quantity and quality of ground water near the Steam will be produced at 750 psig, 1000°F for plant Rainbow site are known mainly from the data collected turbine drives. Steam will also be available at 450 psig from oil wells. However, field investigations conducted saturated and 50 psig saturated for inplant usage. at the Rainbow site indicate that only small quantities of water are in storage in the unconfined alluvium of the Plant boilers will burn coke produced during bitumen area. upgrading. Some oil backup and startup fuel storage will also be provided from coker oil products. It is expected that clear water will be available from the White River Dam Reservoir. At the alternate locations, a Raw water will be available from off plot, via pipeline one-half acre clay lined mud settling pond may be delivery. A 5 day (125,000 BBL/three acre area) lined required adjacent to the river into which river water water storage reservoir will be required at the plant would be pumped. Clear water would then be pumped site for emergency and surge storage. from the pond into the cross country pipeline. High voltage power at 138 KV will be brought to the A plant waste disposal basin will be provided to compound plant site from off plot and reduced to 480 V and 110 V and hold, for recycle or for natural evaporation all plant for inplant usage. 7,500 KW is thedesign peak plant liquids originating from spills, upsets, cleaning of equip- usage. Nearby temporary power will be brought to the ment, and other related nonscheduled events which occur site for construction and startup. from time to time in a plant of this type. Plant site process area storm drainage will also be compounded in Air coolers will be maximized. Evaporative cooling this basin. water is for trim cooling only. The waste disposal and water storage basin will be diked, Plant Buildings clay or hypalon lined, fenced and provided with bird Administration Building repelling devices. It will cover approximately three acres. Any waste oil collecting in the waste pond will be 40 Admin. people 4000 ft2 skimmed from the pond using an API separator and Laboratory . 800 ft2 returned to the process. Storm drainage from other plant First Aid and Security 500 ft2 site areas would be collected in a sediment pond and then Total 5300 ft2 diverted into a seep canyon immediately west of the plant Change House site. 150 men's change 1000 ft2 Showers and R/R 400 ft2 Plant Emissions Temporary sleeping 1000 ft2 Kitchen 200 ft2 Water Total 2600 ft2 The Enercor hot water tar sand extraction process has Maintenance Building 6000 ft2 been developed to recycle the majority of the water used Control Room and Electrical 2400 ft2 in the process. Thus, the only water which leaves the Process Buildings 12,000 ft2 plant process area is that associated with the damp sand which is delivered back to the mine area for disposal as Water Requirements •part of the mine reclamation effort. It is expected that this damp waste sand will contain approximately 10-15% The ultimate plant operation at the 5,000 BPD level moisture by weight prior to disposal. The tar sand mine would require a maximum annual water usage of 5,000 will have an impervious tar bottom which would contain acre-feet (6 cfs), which if used continuously, would be and hold any water in the unlikelihood of some seepage 400 acre-feet per month. An on-site raw water storage from the spent sand. pond of approximately three surface acres would be located on the plant site, water would be delivered to Air the plant site via a pipeline from the White River Dam. The Enercor tar sand processing facility will be designed The White River is the proposed source of water for the and built to have no major air emissions of toxic sub- Rainbow site. The Green River is an alternative source stances other than those associated with fuel combustion. of water, ground water in the area is also a possibility. The Enercor tar sand processing scheme requires hot water for the process to be effective. These heating Due to low flow during the late summer and winter requirements are estimated to be on the order of 6-8 seasons, a reservoir is required on the White River to billion BTU/day. During the tar sand recovery and ensure adequate supplies of water for the plant. upgrading process, petroleum coke and light hydrocarbon gases are produced. Part of the petroleum coke and all of The Utah White River Reservoir proposed by the State the gases are allocated for plant fuel requirements, these of Utah has been approved for construction. This materials will contain some of the sulfur contained in the reservoir is located about 15 miles north of Rainbow. original bitumen. Construction could be completed by the fall of 1984 in

SYNTHETIC FUELS REPORT. DECEMBER 1982 3-11 The burning and cleanup scrubbing of these fuels in the Plant combustion gases will be cleaned in a common plant boiler and heater system is expected to produce scrubber system using BACT to remove sulfur and parti- approximately 50 million SCFD of stack gases con- culates prior to venting to the atmosphere. taining about 10 kg. per hour of sulfur oxides, 11 kg. per hour nitrogen oxide, and 23 kg. per hour parti- Syncrude product is moved via 200 BBIJ tank truck to culates. These gases will discharge to the atmosphere refinery customers in the area. 25 trucks per day are via a 150 foot tall and 4 foot diameter, at the top, required. stack. Maintenance of the plant is typical of that associated This level of emissions release is expected to be less with refinery and chemical plant planned procedures. than allowable P.S.D. increments. Waste oil is returned to the plant process and mixed with Solid Wastes the coker feed. A total of 150 plant operating and maintenance employees will be required. Some of these No known hazardous materials will be handled or pro- employees are expected to live in nearby company produced during tar sand processing. Tar sand ore is vided facilities. commonly used directly as road paving asphalt or in conventional crude oil refining, where it comes in Overall Plant Energy Consumption contact with plant workers on an every day basis. Soda ash has been handled in the industry for hundreds of An estimated overall energy balance for a 5,000 BPD years without any known hazardous toxic effect, how- syncrude plant is given below: ever, normal housekeeping precautions will be taken to Energy Content In minimize any human exposure to these materials. Equivalent Barrels Item Per Day of Oil The tar sand plant will produce 18,000 TPD of sand at Energy content of tar sand ore 6,366 maximum production. This material will be returned to Fuel purchased to operate mine the mine from which it came via ore haul trucks. The haul ore to mine and sand spent sand is expected to contain 5% of the original back 206 bitumen as unrecovered material (95% of the bitumen is Electric power purchased to operate removed in processing), approximately 10-15% mois- the plant (7,500 1(W) 100 ture, a trace of soda ash, and the rest as original silica Gas produced and burned in the sand present in the ore. A small amount (16 tons per plant 278 day) of air pollution control scrubber sludge will also be Tar left in sand and returned to mixed with the spent sand prior to disposal. This sludge mine 316 is expected to be composed of 75% fine sand originating Coke produced and burned in the from tar sand ore and 25% sodium bisulfate and sulfite plant 772 produced from sulfur dioxide scrubbing with soda ash Plant synfuel product 5,000 solution. Once placed in the mine, overburden will be replaced over the spent sand, then topsoil, and the mine area reclaimed per the reclamation plan. Emissions Estimate Plant Operating and Maintenance Plan AeroVironment, Inc. of Pasadena, California estimated the Enercor project emissions for a 5,000 BPD facility The operation of the Rainbow tar sand facility will be plus mine. The results are summarized below: on a 24-hour per day, 330 days per year basis. 35 days per year of down time is allocated for maintenance. Surface Mine Particulate Emissions Topsoil removal 23 lb/hr A stockpile (5 day supply) of tar sand will be stored at Overburden removal 255 lb/hr the plant to provide surge capacity between mine and Storage Piles Particulate Emissions plant. The spent sand, from which the tar has been Topsoil less than S lb/day removed, is also stockpiled to provide mine-plant surge, Overburden 33 lb/day and returned to the mine for reclamation using the ore Demonstration Plant trucks on a back haul basis. Dust suppression equip- Hydrocarbons ment will be installed in the ore crushing area if Valves, Flanges, Seals 160.0 lb/day required. Wastewater Streams 2.0 lb/day Tanks 15.7 lb/day No crude bitumen or tar will be stored in the plant Process Nil except as mixed with the diluent, this bitumen-diluent Carbon Monoxide storage represents the major internal plant surge Process 160 lb/day capacity. The cleaned bitumen will be fed to a delayed Particulates coker which is operated on a 24-hour cycle batch basis Plant Storage Piles 55 lb/day to produce coker liquids, petroleum coke and hydro- Stacks 1,214 lb/day carbon gas. The gas is used as produced for inplant gas Sulfur Dioxide fuel needs. The petroleum coke required along with Process 22 lb/hr supplemental synthetic crude oil will be burned in plant Nitrous Oxide boilers to produce steam. Process* 24 lb/hr From Enercor Estimate

3-12 SYNTHETIC FUELS REPORT, DECEMBER 1982 ENPEX PROJECT DESCRIBED gon would consist of 360 acres and contains 48 injection wells and 96 producing wells. At the center of each Introduction master hexagon will be the steam generation equipment. Treated boiler feedwater, diluent, power and steam The ENPEX Corporation of LaJolla, California has generation fuel will be provided to the center of each evaluated various combinations of in-situ tar sands master hexagon. Steam and diluent will flow from the production and upgrading. Basically, tar sands bitumen center to the injection wells. Crude tar, diluent, and is to be produced by steamflooding and upgraded to a water flow back to the center of the master hexagon from synthetic crude on-site. The steam is produced via the production wells. For 20,000 BPD of tar production, 5 fluidized bed combustion of low rank coal. The up- master hexagons must operate at the same time with a grading sequence is based on H-Oil hydroconversion of well life of 2.5 years. Approximately 2 master hexagons the 650°F+ fraction of the tar sands bitumen product. must be developed each year. Ten 50 MMBTU/hr boilers are needed to produce the necessary steam. An estimate Tar Production of the product tar properties is given in Table 1: ENPEX has 2,200 acres of leases in the South Texas Tar TABLE 1 Sands located about 130 miles southwest of San Antonio. The resource is formed by partially con- SOUTH TEXAS TAR PROPERTIES solidated sandstone and hydrocarbon layers with a gross thickness ranging from 20 to 60 feet. The formation is about 2,000 feet deep and the tar saturation varies Prooertv ENPEX Tar from 20 to 60 percent. Conoco has been running a pilot project adjacent to the ENPEX leases using fracture Gravity, -API -0.5 to 2.0 assisted steamflood technology (see the September 1982 Viscosity, CS, 175°F 520,000 Pace Synthetic Fuels Report.) ENPEX will probably use Sulfur, wt. % 9.5- 11 the same production technique. Con. Carbon, wt. % 24.5 Nitrogen, wt. % 0.36 Steam will be generated in 50 MMBTU/hr fluidized bed Asphaltene, wt. % in combustor steam generators. Low quality (high ash, pentane 37.4 high sulfur) coal will be used as fuel. Bed temperature Pour Point, °F 170 - 180 will be maintained around 1,500 to 1,650°F. At these Metals, ppm low temperatures, NO, production is low. Sulfur dio- Vanadium 85 xide is captured by calcium oxide added to the bed as Nickel 24 limestone. Steam is produced at 80% quality, 660°F, 1000°F + % Vol. 65 2,450 psig. The liquid portion of the product steam carries out the dissolved solids and potentially precipitated solids. The fluidized bed is about 5 feet high and 130 square feet in area; the disengaging zone above Tar Upgrading the bed is about 15 feet. ENPEX considered the following combinations of up- The areal development would consist of an array of grading processes: inverted five spot or seven spot patterns of steam injection wells and producing wells. Figure 1 shows a Delayed Coking plus hydrotrcating seven spot configuration of a central injection well Flexicoking plus hydrotreating surrounded by six producing wells. Each master hexa- Solvent deasphalting Hydrocracking /T The selection criteria were: T7\ Capital cost Commercial viability Product yields Disposition of products ENPEX selected ebullated bed hydroconversion, H-Oil, in combination with Texaco Partial Oxidation to supply hydrogen. Figure 2 presents the overall upgrading process. In this system, the 60,000 BPSD tar + diluent mixture is sent to a crude flash tower, where it is separated into 650°F and lighter and 650°F + material. The majority of the 650°F and lighter gas oil (40,000 \'_.:..•/ BPSD) is sent to the oil field as diluent, and the remainder (1,200 BPSD) is sent to a gas oil hydrotreater.

•*ODUCnON WELL The 650°F+ material (18,800 BPSD) is charged to a hydrocracking unit where about 75% of the 1000°F+ - INaCTION WELL material is converted into distillates and desulfurized.

FIGURE I SEVEN SPOT PRODUCTION PATTERN

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-13 FUEL GAS To STEAM PRODUCTION .4

H.S FROM PDX SUSULFUR PLANT SULFUR

LHT LIGHTS ENDS 1 50UR .-c, OVHD FROM 1405 R.covtRJ REMOY REFINERY FUEL 40, Sf0 OILIMHT 1 TO WELLS - 4 C,ID5HAPTHA I OYHD

CAME FLASH PS - 550' F TOWER . CRUDE MIXTURE •YRE ODUCT C.. F

7S%C F

OIL 1405 H, PARTIAL OXIDATION H, 01 HIS TO SULFUR PLANT ASH

IIUUHt a TAR SANDS UPGRADING SYSTEM

The conversion level is selected to balance out the TABLE 2 hydrogen demand when the unconverted material is sent to a partial oxidation hydrogen plant. The virgin IBP- OVERALL CAPITAL COSTS FOR 650°F material is combined with 400 0 - 1000°F gas oil THE TAR SANDS PROJECT and the mixture is further desulfurized. • Based on 20,000 BPD Tar Production The system produced fuel gas which is internally used • 1982 Million Dollars for upgrader fuel and the excess fuel gas (1240 BFOE) is piped to the oil field for use as steam generation fuel. The system produces 17,955 BPSD of all distillate Refinery Costs 380 - 480 syncrude estimated to be 27 0 AP! with about 0.15 wt.% Oilfield Costs 420 - 500 sulfur and 0.08 wt.% nitrogen. Infrastructure and Other Costs 90 - 100 Total Costs (at startup) 890 - 1080 The overall capital costs for the tar sands project based Operating Costs 129 - 215 on 20,000 BBL/day tar production and 1982 dollars are Oil Field Costs for 30 years 2000 - 2400 shown in Table 2. Operation

3-14 SYNTHEIC FUELS REPORT, DECEMBER 1982 CORPORATIONS

SIJNCOR TO INCREASE TAR SANDS RESERVES The board of directors of Suncor, Inc. approved expenditures of $700 million involving their tar sands operation. Of this, $335 million will be spent upgrading the Sarnia refinery. The remainder will be spent to expand the oil sands mine to increase reserves and for improvements at the oil sands plant. Construction on the refinery in Sarnia began in July and wilt be completed in 1984. Upgrading at Sarnia includes a hydrocracker, a vacuum unit, a sulphur plant, a hydrogen plant and related facilities. The project will allow for improving mine flexibility and effluent operations.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-15 GOVERNMENT

U.S. AND CANADA SIGN TAR SANDS AGREEMENTS Section 17 of the Mineral Lands Leasing Act which were filed prior to January 21, 1926, in Special Tar Sand Areas, The United States and Canada signed two agreements to convert those leases or mining claims to combined September 13, for cooperation in the research and hydrocarbon leases. development of tar sands and heavy oil. Under the regulations proposed by the BLM and the The agreements implement a memorandum of under- previously established division of responsibilities within standing (MOU) signed by the U.S. and Canada in 1979. the Department of the Interior, the MMS will have (See page 3-2 of the June 1979 Cameron Synthetic specific responsibility to approve operating plans prior to Fuels Report for background information concerning the conversion of existing leases and/or valid mining the MOU). The MOU provides that each joint project claims to combined hydrocarbon leases, and to supervise would be implemented subject to a separate operation on such newly issued leases. This rulemaking is memorandum. designed to provide regulatory authority for both requirements with the least actual regulatory burden by utilizing These most recent agreements as well as the original existing rules for both mining and oil field operations. MOU were signed by the Department of Energy for the United States and the Alberta Oil Sands Technology The proposed conversion regulations which would be Research Authority of the Province of Alberta, the administered by the ELM (43 CFR Part 3140) provide for Department of Energy, Mines and Resources of Canada, the approval of a plan of operations by the MMS prior to and the Department of Energy and Mines of the conversion. The content of these plans is already Province of Saskatchewan for Canada. governed by the regulation in 30 CFR Part 231. In addition, through cross reference, those proposals for in One of the agreements provides guidelines for the situ operations involving drilling similar to conventional dissemination of information. The primary objective of oil field exploration and production are referred to 30 the other agreement is to conduct a coordinated labora- CFR Part 221. tory experimentation program to evaluate in situ steam processes enhanced by various additives (solvents, sur- The Mining Supervisor shall advise the applicant and the factants, emulsifiers, gases, etc.) for recovery of oil ELM as to the initial completeness of the operating plan from Canadian and U.S. tar sands and heavy oils. The and the nature of any required additional information. experiments conducted in the U.S. and Canada will be Following review and ultimate determination of accept- coordinated so that data from the smaller U.S. experi- ability of the plan, the Supervisor shall notify the ments can be utilized in designing the larger Canadian authorized officer of the ELM and forward any specific experiments. stipulations which should be included in the lease. Since this process is similar to established practice, it has not Cost of the implementing agreements will be $600,000 been deemed necessary to establish a separate part within for both the U.S. and Canada. the regulations to govern operations for tar sands exploration and development. In Part 221.2, Oil and Gas Operating Regulations, the FINAL OPERATING REGULATIONS FOR TAR SANDS definition of oil has been amended to read: ARE ISSUED Oil - Any nongaseous hydrocarbon substance other The Department of Interior, Minerals Management Ser- than those substances leasable as coal, oil shale, or vice issued proposed rulemaking for Oil and Gas Opera- gilsonitc (including all vein-type solid hydrocarbons). ting Regulations in the May 12, 1982 Federal Register. For royalty rate consideration in special tar sand The final regulations were published in the Federal areas, any hydrocarbon substance with a gas-free Register on September 28, 1982. This rulemaking viscosity, at original reservoir temperature, greater amends 30 CFR, Parts 221 and 231 (the existing opera- than 10,000 centipoise is termed tar sand. Hydro- ting regulations for both oil and gas and exploration, carbon extraction from tar sand is also governed by development, and production of solid minerals other the regulation at 30 CFR Part 231 and applicable than coal), to facilitiate operations for tar sand orders and notices. development under the Combined Hydrocarbon Leasing Act of 1981. The objective is to provide procedures for In gPart 231.1a, the scope and purpose under Operating a wide variety of operational methods with the least Re ulations for Exploration, Development, and Produc- regulatory burden. tion, has been amended to read: The Act allows holders of Federal oil and gas leases The regulations in this part shall govern operations for existing as of November 16, 1981, and valid mining the discovery, testing, development, mining, and pro- claims to any hydrocarbon resources leasable under cessing of all minerals under leases or permits issued

3-16 SYNTHETIC FUELS REPORT, DECEMBER 1982 for Federal lands pursuant to the regulations in 43 CFR Group 3500 or Part 3140 and of all minerals (except coal, oil, and gas) on tribal and allotted Indian lands leased pursuant to the regulations in 25 CFR Parts 171, 172, 173, 174, and 176. For operations involving the extraction of hydrocarbon from tar sand or oil shale by in situ methods utilizing boreholes or wells, the regulations in 30 CFR Part 221 and applicable orders and notice also apply.

SYNTHETIC FUELS REPORT. DECEMBER 1982 3-17 ENERGY POLICIES

TAR SANDS MINING EVALUATED evaluated if possible; surface, underground, mine assisted in-situ. The factors involved in assessing the mineability of tar sands deposits were outlined in a paper entitled; Pro- Based on the mining scenarios in Table 2, capital and spects For Commercial Tar Sand Development by DR operating expenses associated with mining were developed H. Dike of Groundwater Technology, Inc. and Barry for each scenario. Capital and operating expenses are Resnick and Randall Metz of KETRON, Inc. There are determined from individual cost elements which include twelve key mineability factors were considered and site preparation, surface facilities, utilities, development these are given in Table 1. costs, equipment costs, labor costs, underground utilities, operating supplies, fixed costs, indirect costs, and con- The mineability factors were evaluated against the tingencies. Costs were compiled from various sources characteristics of tar sands deposits in eight states to during the 4th quarter, 1981 and the 1st quarter, 1982. determine potentially mineable resources. Based on The analysis does not include costs associated with tar these results, mining scenarios were developed for tar sand processing, nor does it include Federal, state, and sand resources in Alabama, Missouri, New Mexico and local taxes. Project financing was assumed to be 100 Utah. Each scenario was based on a set of general percent equity for each scenario; therefore, no interest geotechnical parameters characterizing the region. costs were incurred. Estimated mining costs per barrel Conceptual mine plans were developed, labor and equip- for each scenario are shown in Table 3. New Mexico and ment costs specified, and mining costs estimated. The Utah have the lowest estimated mining costs per barrel. location and mine related factors are summarized in It is important to note that both states also have low Table 2. Three types of mining technology were demand for either residual fuel oil or asphalt. Tar sands

TABLE 1 TECHNICAL, ECONOMIC, AND OTHER NONTECHNICAL MINING FACTORS AFFECTING MINEABILITY ASSESSMENT

Category Factors affecting mining technology • Structural characteristics of the ore body and surrounding strata • Geological characteristics of the deposit • Topographical features

• Location, variability, and extent of ore body

Factors affecting implementation of mining system • Water resources • Transportation infrastructures • Labor and community infrastructure

• Power resources

Factors affecting limitations on mining • Environmental • Socioeconomic • Political environment

• Ownership pattern

3-18 SYNTHETIC FUELS REPORT, DECEMBER 1982 bitumen would be valued at about the same as heavy to develop reasonable regulations for the control of crude and would be a source of residual fuel oil or wastewater discharges to surface waters. These regu- asphalt if the bitumen is not upgraded. Therefore, it is lations involve permits under the National Pollutant useful to compare these mining costs with current Discharge Elimination System (NPDES), mandated by the selling prices for these commodities. Residual fuel oil Clean Water Act. Discharge limitations are promulgated sold for as little as $16.00/Bbl in Salt Lake City during on the basis of development documents that reflect the this past summer. Current Gulf Coast price for EPA's understanding of the equipment and method used by residual fuel oil is about $28.00 - 30.00/Bbl and the industry in question. There is a potential for $22.00/Bbl for asphalt. California heavy crude is misunderstanding on the part of the EPA in the absence of $20.00- 22.00/Bbl at the wellhead. constructive input from industry. For the high risk aspects of bringing an essentially Other areas for cooperation between industry and the experimental-scale industry up to commercial scale, regulators abound. In essence, the requirement for a environmental regulation and public land policy are two permit to accomplish one or another aspect of developing areas that are especially susceptible to change, a tar sand project presents an opportunity for provided that the suggestions for change are reasonable improvement of the regulatory burden of the industry, in substance and reasonably presented. That is, these whether that improvement involves merely a loosening of suggestions for change may receive favorable review by discharge limitations to reasonable levels for certain public policy decisionmakers if they are presented in a pollutants, or results in the consolidation of multiple constructive context. permits into a single form. The burden for effecting these changes falls mainly to industry. For example, the Clean Air Act provides for two kinds of controls on a mining project. The first involves The overall conclusion of this study is that prospects for emissions limitations on each type of technology used in the development of commercial-scale tar sand mining development, including vehicles, electric generators, oil projects are not encouraging at present, given (1) the extraction vessels, and steam generators. Not all of costs and scale of the investments required to bring such these emission sources in a tar sand mine are regulated projects into production, as registered against a at present, but they are susceptible to regulation; that reasonable' return on investment via a via competing is, regulations may be promulgated in future to cover investment opportunities, (2) the uncertainties of long the emission sources that for now are not regulated. term developments in public land policy and The second Clean Air Act control requires a permit environmental regulation, and (3) the general instability providing for the prevention of significant deterioration of world oil prices, especially when considered in context to local air quality (PSD permit). Local areas are of geopolitical turbulence. designated as having pristine, average, or poor air quality (Class I, II, and Ill air quality areas, respec- Specific prospects for the commercial development of tar tively) for the purpose of setting increments limiting snad are most encouraging in the Sunnsyide and Asphalt the extent to which local air quality may be polluted. Ridge deposits of Utah and possibly in locations in New The PSD provisions of the Clean Air Act provide also Mexico. Prospects at locations in Missouri and Alabama for the regulation of local visibility values. - are less encouraging, given the projected mining costs associated with recovery. For large, western surface mines, the PSD regulations, and especially the visibility aspects thereof, present Potentially difficult compliance problems, especially for deposits that are located near Class I air quality areas, such as National Parks, Of particular interest is the ability of tribal councils to designate reservation as a Class I air quality area, which may have the effect of freezing development of surface mines upwind from the reservation. One approach to mitigating potential constraints to tar sand development is for the tar sand mining industry to participate in the redrafting of the Clean Air Act. Amendments to the PSD provisions of the Act could include special exceptions for tar sand mines. As another approach to relief from air quality regulations, the industry could work with the U.S. Environmental Protection Agency to develop reasonable emission limitations on tar sand processing equipment. A similar approach has been taken by other synthetic or alternative fuels industries, especially where coal conversion is concerned, so there is precedent for this kind of cooperation between the EPA and the industry. Other possibilities for positive change in regulation and policy include working with the EPA and state agencies

SYNTHETIC FUELS REPORT, DECEMBER 1982 3

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SYNTHETIC FUELS REPORT, DECEMBER 1982 3-21 ECONOMICS

RESULTS OF NATOMAS FEASIBILITY STUDY ARE • Plan in detail the next steps that will be required DISCUSSED to ensure expeditious commercial development of the Natomas tar sands extraction technology. Natomas Energy Company received a grant from the Department of Energy to assist financially in a feasibi- This article reviews the economic analysis portion of the lity study of the Natomas tar sands process. The grant report. from DOE was effective on October 29, 1980, through August 28, 1981. The purpose of the study was to Kaiser Engineers evaluated the bench scale and mini-pilot determine if, under a realistic scenario of location, plant process data and assessed the technological state of timeframe and economics, the Natomas process was the process development. Proven equipment was used in technically and economically feasible. Asphalt Ridge, the engineering design of the commercial plant except Utah was selected as the site for the study although where such equipment was not applicable to the unique another location could be chosen if the project pro- and novel process requirements. gresses through to commercial stage. A report on the results of the feasibility study was submitted to DOE The engineering and cost estimate of the designs are under Contract Number DE-FGO1-80RA50384 and pub- based on: lished in April 1982. • A preliminary facility design of a 2,000 BPD com- The basic Natomas process for recovering bitumen from mercial demonstration plant producing raw bitu- tar sand consists of crushing and dispersing the tar men extracted from the tar sands. No upgrading is sands in a recycled slurry of bitumen, toluene solvent, included at the mine-mouth extraction plant. Up- and fine sand. The coarse sand is separated from the grading equipment for this low level of production bitumen-toluene slurry in the extractor and is washed would not be economically justified. (Refer to with toluene before being conveyed to the thermal Table 1). dryers for the solvent recovery. Fine sand in the product stream from the recycle slurry is removed in • A conceptual 20,000 BPD commercial plant con- centrifuges. The bitumen is then separated from the sisting of four 5,000 BPD extraction modules plus toluene in a distillation column, and the recovered vacuum distillation and delayed coking for up- toluene solvent is returned to the extraction process. grading the bitumen. (Refer to Table 2). The specific objectives of the feasibility study were to: • A conceptual 20,000 BPD commercial plant consisting of four 5,000 BPD extracting modules plus • Prepare a development plan for production of vacuum distillation, delayed coking and hydro- 20,000 BPD of upgraded bitumen from domestic treating to produce a low sulfur and low nitrogen tar sands by application of a proprietary solvent content synthetic crude oil (syncrude). (Refer to extraction process on which Natomas holds Table 3). patents. A discounted, after-tax cash flow evaluation of the con- • Study the suitability of both the primary and ceptual 20,000 BPD tar sands project has been performed. alternative tar sands resource sites. Assumptions for the evaluation are summarized in Table 4. The analysis showed that on an uninflated or real basis, • Prepare preliminary design and cost estimate for the project would have an internal rate of return (IRR) of a mine and processing facility at the selected tar about 14.5% and a net present value (NPV) at a 10% sands reserve sites. discount factor of $93.53 million. The project's capital intensiveness and relatively long economic life make it • Assess the technical feasibility of the Natomas highly sensitive to the discount rate. Separate plots were process and estimate the economic viability of made of the project's NPV to determine its sensitivity to the commercial facility using this process. variations in capital cost and product price. A 10% revision in capital cost would change the NPV at 10% by • Plan the investigations of environmental, health 17.5 million or 18.7%; a 10% revision in the product price and safety, and socioeconomic factors that will of $37/Bbl would change the project's NPV at 10% by be needed to obtain the necessary permits and, $49.3 million or 52.7%. The project's economic viability to the extent possible, conduct an investigation is more sensitive to assumptions about product price than that will result in the definition of any clear capital costs. Accordingly, estimates that the real price environmental impediments to the development of energy will escalate faster than other costs would of a commercial plant. significantly and favorably affect project economics. • Determine markets for the upgraded bitumen Analysis of this project on an inflated or nominal basis produced. can greatly change the economics. For example,

3-22 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 COST ESTIMATE FOR NATOMAS 2,000 BPD SOLVENT EXTRACTION PLANT Basis Bitumen product - 2,034 BPD at 60°F - 679,350 BPY Tar sands supply - 4,068 TPD, 10% weight bitumen Operating DPY - 334 Cost base - March 1981 dollars Capital Costs $MM $ Annual Bbl Depreciable capital: Plant 24.68 36.3 Project Maintenance Building 5.09 7.5 TOTAL 29.77 43.8 Spare parts, startup supplies - .J.&! ii TOTAL CAPITAL (excluding land, startup, etc., as defined in the Estimate Criteria attached at the end of this section) 30.46 44.8 Operating Costs $MM/Y $/Bbl $3.77 5.55 Exclusions: Depreciation C & A expense Insurance - Taxes

TABLE 2 - COST ESTIMATE FOR 20,000 BPD FACILITY

Vacuum and coke distillate products (plus toluene) 18,504 BPD 6,180,000 SPY Bitumen produced 22,000 BPD 7,348,000 SPY Tar Sands supply 40,610 TPD Operating DPY 334 Cost Base March 1981 dollars 5/Annual Barrel s/MM Bitumen Distillate Capital Costs Tar sands extraction plant 188.09 25.59 30.50 Coke-fired Dowtherm heater 24.35 3.32 3.95 Total 222.44 28.91 34.95 Spare parts, startup supplies 5.13 0.70 0.83 Subtotal, extraction 217.57 29.61 35.28 Vacuum distillation, delayed coker, and Stretford plant 30.20 4.90 Tankage 1.15 Subtotal, upgrading 31.35 50.09 TOTAL CAPITAL (excluding land, startup training, pipeline pump station) 248.92 40.37 Operating Costs $MM/Yr $/Bbl Extraction plant 19.41 3.15 Vacuum distillation, coker 3.02 0.49 TOTAL OPERATING COST (excluding G&A expense, insurance, and taxes) 22.43 3.64 *It is an option to omit the process building and cranes. Allowing for a mobile crane, but not for the impact on the plant layout, this option reduces the capital cost of the extraction plant by $13.000 MM from $212.44 MM to $119.44 MM. The estimated emission of toluene will increase by 66 lb/hr from 33 lb/hr to 99 lb/hr from each of the 4-5,000 BPD modules.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-23 TABLE 3 COST SUMMARIES FOR HYDROTREATER PLANT Basis Hydrotreater product 17,690 BPD 5,908,000 SPY Hydrotreater feed 18,504 BPD Bitumen produced 22,000 BPD 7,348,000 SPY Tar sand supply 40,610 T/D Operating D/Y 344 Cost Base March 1981 dollars $/Annuai Bbl s/MM Product Capital cost 52.25 8.84 $/Bbl $ MM/Y Product Operating cost 4.81 0.81

TABLE 4 CASK FLOW EVALUATION FOR 20,000 BPD PLANT

Capital costs ($ in millions) $ 132.2 Mine (including reseeding) Plant Extraction 199 .7a Upgrading 31.35 Hydrotreating 52.25 Subtotal $ 283.3 TOTAL $ 415.5

Product price (hydrotreated) $ 37.00/Bbl Product yield (Bbl oil/Bbl bitumen) 0.841 Construction start 1985 On-line date 1989 Plant availability factor 91.5% Variable costs Plant and upgrading $ 4.33/BBI bitumen Mining $ 3.25/ton of ore Reclamation (seeding) $ 0.03/ton of spent ore

Tax Tax rate (state and federal) 50% Severance tax 4% Depreciationb 15 year DDB Investment tax creditsC 10%

aAssumes building not built at a savings of $18 million. bN0 reduction of equipment life for depreciation purposes if actual life less than 15. CTax credit taken in year of occurrence (assumes corporate entity has a tax liability against which to apply the credits).

3-24 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLES NATOMAS TAR SAND PROJECT - BITUMEN UPGRADING PROCESS OPTIONS

Capital Cost Conversion of Product Estimated $ *4 Bitumen to (wt%) Ii5avity Certainty Value of Upgrading Process (1981) Product sit 9C S 14 API of Market Use Product

None o 100 0.90 0.45 10.8 8-14 Uncertain Fuel $20/bbl

Vacuum distillation 25 47 0.36 0.36 11.5 14-16 Marginal-- Virgin gas $30/bbl refinery oil hy drotrea tar necessary

Vacuum distillation and Premium 75 47 0.05 -- 13* 34+ Pipelineable hydrotreating gas oil $36/bbl premium feedstock cat cracker

Coking iso 77 0.77 0.18 12.4 25-27 Marginal- - Potential $30/bbl refinery feedstock hydrotreater necessary

Vacuum distillation, 100 84 0.41 0.25 11.9 <15 Marginal-- Heavy $30/bbl coke residue refinery gas oil- hydrotreater refinery necessary stream

Vacuum distillation. 150 Premium 80 0_05 -- 13+ 34+ Bottomless $37/bbl coke residue, hydrotreating product premium gas oils syncrude

Vacuum distillation, coke 275 75 -- -- 14+ -- high demand Gasoline + $40/bb) residue. hydrotreat, cat diesel fuel crack/hydrocrack

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-25 assuming that capital costs will rise at a 12% annual rate and energy prices at a 10% annual rate over the project's life raises the NPV of the project at 10% to $768 million (8 times the unesealated value) and the IRa to just over 20%. Natomas Coal developed a detailed mining plan capable of supporting a 2,000 BPD extraction facility based on engineered reserves of approximately 20.8 million recoverable barrels in the southeastern most area of the Sohio holdings. The capital and operating costs associated with a mine capable of serving a 20,000 BPD plant have also been developed, but the existence of sufficient reserves to support such an operation has been assumed rather than proven. For the purpose of the 2,000 BPD facility, 267 mineable acres at the southeastern end of Asphalt Ridge were evaluated in detail. The area was conservatively estimated to contain approximately 20.8 million barrels of bitumen from Tertiary age tar sand recoverable by surface mining methods. A combination of dragline and truck/shovel operation was designed on the basis of these reserves. The capital costs in 1981 dollars required for such an operation were estimated at $19.1 million. Direct operating costs for mining, delivery to the plant, and reclamation (exclusive of irrigation and seeding) were estimated at $5.52 per barrel of bitumen. Capital costs for a mine capable of providing sufficient tar sands to supply a 20,000 BPD facility were estimated at $131.7 million. Operating costs were estimated at $7.46 per barrel (based on the existence of sufficient mineable reserves for an economic life of 15- 25 years). The upgrading schemes involves vacuum distillation, delayed coking of vacuum bottoms, and hydrotreating of a mixture of coker liquids and vacuum gas oil. A rough estimate of the capital costs of the process increments in the overall upgrading plan was prepared showing approximate costs of each step and the product properties and value derived from each step. The results are shown in Table 5. The nitrogen content of the bitumen and the product derived from bitumen is of concern. The nitrogen content of the bitumen is close to 1 wt.%, and that of the distillate products from bitumen ranges from 0.3 to 0.5 wt.%. A refinery with hydrotreating capability is required to reduce the nitrogen content to acceptable levels in the products. Overall, the analysis found that the raw bitumen itself is not readily marketable and requires significant upgrading requirements. The project economic viability is sensitive to capital requirements or product prices, but generally favorable for development. No major technical obstacles were encountered in the engineering design phase, nor were any major environmental or permitting obstacles identified in the study of permits and socioeconomic issues. The study concluded that given sufficient mineable resource, and ugprading facilities, the proposed project is both technically and economically feasible.

3-26 SYNTHETIC FUELS REPORT, DECEMBER 1982 TECHNOLOGY

OLEOPHILIC SIEVE PROCESS FOR TAR SANDS OUT- LINED MINED OIL SAND Kruyer Research and Development, Ltd. is developing an oleophilie separation process for bitumen (heavy oil), and solids. Details were given in a paper, Oleophilic Separation of Tar Sands, Oil-Water Mixtures and Minerals, given at the Second International Conference SLURRY PREPARATION on Heavy Crude and Tar Sands, Caracas, Venezuela in I February 1982. The process is claimed to be able to: 1. Separate bitumen from oil sands. 2. Recover bitumen from oil sands tailings. I OVERSIZE REMO REJECT 3. Separate bitumen from oil/water/sediment mixtures produced by secondary and tertiary recovery of heavy oil wells. 4. Remove oil from process water. I OLEOPHILIC SIEVING TAILINGS In addition, the oleophilic process recovers the remaining portions of bitumen from tailings; the residual bitumen from Canadian deposits appears to be unusually high in titantium. BITUMEN RECOVERY Process Description The following description is taken from the above cited paper. The oleophilic sieve process is built around the _ concept that bitumen will be attracted to and adhere to a sieve surface with an oleophilic coating. Water and BITUMEN REFINING b TAILINGS solids of appropriate size will pass through the sieve openings. A conceptual process flow diagram for primary oleophilic sieving of tar sands is shown in COKE Figure 1. Figure 2 shows how oleophilic sieving can be used to supplement current hot water extraction pro- SYNTHETIC CRUDE cesses. FIGURE I The Kruyer Oleophilic Separation Process was FLOW DIAGRAM, developed to provide an alternative to the Hot Water OLEOPHILIC SEPARATION OF MINED OIL SANDS Process for extracting bitumen from mined oil sands. Mined oil sands are prepared for separation by tumbling with steam and water in a conditioning drum such that water and solids pass through the apertures of the sieve. the sand grains are disengaged from the bitumen in the The oleophilic particles, mainly bitumen, upon contact produced slurry. The slurry is sieved to remove over- with the sieve surface, become attached to this surface size particles by a conventional size separation sieve and build up into a thick layer. If the sieve were and then passes to the oleophilic sieve to separate the stationary, this bitumen layer would continue to accumu- oleophilic material from the hydrophilic material. The late and then bridge the apertures. Then the blinded sieve oleophilic sieve consists of a perforated drum or an would not permit passage of the hydrophilic materials, open weave mesh conveyor belt; both are oleophilic. and the separation would stop. However, the bitumen Normally the drum is fabricated from steel and then loaded sieve is moving and conveys bitumen from a coated with a strongly adhering, abrasion resistant sieving zone to a recovery zone where bitumen is con- oleophilic coating. When an oleophilic belt separator is tinuously removed from the sieve to provide the bitumen used, the strands from which the belt is woven may be product of separation and to make sure that the sieve strongly oleophilic or their oleophilicity may be apertures are reopened for subsequent sieving. improved by a special tightly adhering oil and abrasion resistant coating. During oleophilic sieving, the slurry Another requirement of the preparation process is that contacts the sieve and hydrophilic material including the disengaged bitumen particles in the slurry be large

SYNTHETIC FUELS REPORT. DECEMBER 1982 3-27 FIGURE 2 FLOW DIAGRAM: THE USE OF OLEOPHILIC SEPARATION TO ASSIST THE HOT WATER EXTRACTION PROCESS enough and possess adequate adhesion properties to done is a rapid, efficient and very effective pretreatment contact the sieve surface and ' to adhere and remain method for oleophilic sieving. with this surface for subsequent recovery. Many grades of oil sand produce slurries that are conveniently The Oleophilic Sieve Process makes use of two opera- separated by the oleophilic sieve without difficult pre- tions. In the first operation, the mixture or slurry to be paration. However, when finely dispersed bitumen separated passes through the flowing or moving sieve. particles of very small size are present in slurries of Solids and water pass through the sieve apertures and some grades of mined oil sand, a part of these will pass bitumen remains on the sieve surface. The sieve opening through the sieve surface, and then additional pretreat- size is selected to optimize two opposing requirements. ment is required to increase the bitumen particle size. The one requirement calls for large opening size to An oleophilic agglomeration process has been developed increase the flow of slurry or mixture through the sieve by Kruyer Research and Development Ltd. to increase and the other requirement calls for small opening size to the particle size of oleophilic particles in a slurry or capture all the bitumen on the sieve surface and prevent suspension for the purpose of improving the efficiency the loss of small bitumen particles through the sieve of subsequent oleophilic sieving where required. The apertures along with the water and solids. Normally the agglomeration process makes use of free bodies that oleophilic sieve opening size is selected to optimize the tumble in a drum and have oleophilic surfaces. The sieving rate. Since oversize removal is done prior to drum is partly (and sometimes nearly) filled with these oleophilic sieving, the oversize removal sieve requires a free oleophilic bodies, and the slurry or mixture to be sieve opening size that is not larger than the oleophilic treated is passed through the horizontal rotating drum. sieve opening size or else solids accumulate on the As the mixture under treatment is tumbled with the oleophilic sieve that cannot pass through its apertures. free bodies, the dispersed oleophilic bitumen particles Selecting an oleophilic sieve of small aperture size is come in contact with the free bodies and accumulate on normally not practical for it may create a bottleneck in their surfaces into a layer that grows in thickness until the oversize removal sieve. Hence, slurry preparation the shear forces in the drum tear this bitumen off. The usually is tailored to produce mixtures that contain rela- thus sloughed off bitumen re-enters the mixture in the tively large bitumen particles for subsequent separation form of large droplets or streamers that are readily by the oleophilic sieve. The oversize removal sieve is captured by the sieve surface when this mixture flows designed so that it passes all of the bitumen, but retains to the oleophilic sieve for subsequent separation. The the oversize solids particles. shear forces in an agglomerator of this type vary from top to bottom of the horizontal rotating drum, resulting Recovery of bitumen from the olephilic sieve surface is in an agglomeration process that continually collects the second operation and is accomplished after the sieve dispersed bitumen particles from the mixture onto the conveys the bitumen out of the sieving zone normally free bodies and continuously sloughs off enlarged bitu- producing a ribbon of bitumen so that subsequent sieving men back into the mixture. The agglomeration thus is done again with open apertures. Some bitumen is

3-28 SYNTHETIC FUELS REPORT, DECEMBER 1992 always left on the sieve to lubricate the sieve and 1. Improved water resource management. essentially eliminate abrasion by the solids of the slurry. 2. Elimination of the settling ponds. When a conveyor belt is used for the oleophilic sieve 3. High overall bitumen recovery. this apertured oleophilic belt may contain several oleophilic sieving and bitumen recovery zones in sequence 4. Simplicity of the oleophilic process will permit along its total length. The belt may be totally development of smaller oil sand resources. immersed in the separating slurry, so that sieving and bitumen recovery both occur under immersion. Alter- Preliminary data from the early prototype studies are nately, the belt may be immersed for the sieving zones presented in Table 1. Initial studies with Oleophilic but emerge out of the slurry for the bitumen recovery, Separation of mined tar sands used high grade Athabasca or both sieving and bitumen recovery may be achieved sands from the GCOS (Suncor) site. Early studies with without immersing the belt. The merit of each con- oleophilic separation used pH controllers to operate the figuration depends upon the nature of the mixture under process in a strongly basic environment. Many problems separation. of emulsion formation were encountered. Continuing the work with high grade sands, it was found that better Other mixtures, in addition to tar sand have been separation was achieved when the pH was reduced and separated successfully with the oleophilic sieve, and the eventually no chemicals were added to the process at all. preparation steps for these were tailored to suit the This resulted in a tailings product that for some of the material to be separated. Middlings, tailings and test runs contained as low as 0.1% of bitumen. The high desanded tailings from the primary separation vessel of grade oil sand feedstock produced a coarse sand tailings a hot water extraction process have been separated product with a low percentage of fines that permitted directly as produced or were agglomerated to increase total recycle of the process water. As a result, the only the size of the dispersed bitumen particles. Either water leaving the process was the interstitual water approach works effectively but adding an agglomeration between the sand and silt grains; and bitumen recovery step generally permits a faster oleophilic sieving rate for the process was very high. and thus reduces the size of the sieving equipment required. No material balances were calculated for the early prototype development studies. Emulsions of bitumen in water produced from an in-situ steam drive have been agglomerated with a demul- Calculations indicate that for high grade the bitumen sifying chemical and oleophilic free bodies. The recovery with the oleophilic sieve was in excess of 97% chemical served to remove the repulsive electrical and for low grade the recovery was in excess of 70%. charges from the emulsion and the free bodies collected the dispersed bitumen particles to form large bitumen Bitumen Recovery From Tailings drops and streamers in the mixture which were easily recovered in the subsequent oleophilic sieving opera- An experimental study has been conducted with 45 tion. Imperial gallon drums of middlings, tailings and desanded tailings from one of the present Canadian operators of a Primary Oil Sand Process Hot Water Extraction Process. The recovery of bitumen by oleophilic separation was evaluated for each of these A flow diagram for mined oil sands is shown in Figure 1. feedstocks during the test program. The warm feedstock was tumbled in its original drum containers to obtain a In contrast with the hot water process, the Kruyer homogenous mixture after which it was dispersed to the oleophilic separation Process does not rely upon bitu- oleophilic sieve for separation. No water, steam or men flotation to achieve separation of the oil sands. chemicals were required. In alternate test runs, an This difference provides a number of commercial agglomerator was used to collect the dispersed bitumen advantages: into larger particles to improve the efficiency of the subsequent oleophilic sieve separation. A high bitumen 1. Less water is needed for the separation. recovery is claimed to have been achieved during this program. 2. Thermal energy requirements for separation are lower. Figure 3 indicates the percentage bitumen recovery that has been obtained with the hot water extraction process 3. Bitumen recovery is higher. when the process runs smoothly without upsets. This recovery drops off for lower grades of oil sand, resulting 4. Bitumen product contains less water. in large amounts of bitumen in the tailings that may be recovered by oleophilic separation. Process upsets may 5. Lower grades of oil sand may be included in the also be smoothed out when oleophilic separation is used to overall resource recovery. augment the hot water process. It is expected that impact of the process with mined During the tailings study the results obtained seem to sands will be felt in the following areas: indicate that in the hot water extraction process, within broad categories, there are at least three grades of bitumen that exist concurrently in an Athabasca Oil Sands slurry:

SYNTHETIC FUELS REPORT, DECEMBER 1982 . 3-29 TABLE 1 AVERAGED RESULTS, SEPARATION OF MINED TAR SAND WITH EARLY PROTOTYPE

Prototype: 1 2 2 3 4 5 Type: Drum Drum Drum Drum Drum Drum No. ofRuns: 6 4 2 2 6 1 Slurry Temp., °C: - - 66 57 55 Separation, °C: 44 34 40 40 45 40 pH: 8.1 9.6 8.0 8.2 7.0 7.0 Feed, KG/KR: 50 100 30 150 250 200

Feed, %Bitumen: 14.3 15.9 6.9 16.5 16.8 15.3 % Water: 1.8 1.5 12.6 2.8 2.0 3.4 %Solids: 83.9 82.6 80.5 80.9 81.2 81.3

Product, 96 Bitumen: 63.2 63.5 62.5 57.0 68.1 70.8 • Water: 19.4 11.6 19.5 14.3 17.8 16.2 %Solids: 17.4 25.1 18.0 28.7 14.1 13.0

Tailings, % Bitumen: 1.2 0.2 1.1 0.5 0.3 0.2 96 Water: 18.9 17.8 14.3 15.9 22.0 22.0 96 Solids: 79.9 82.0 84.6 83.6 77.7 77.8

lx 1. Low density bitumen, containing low solids content, that readily froths and floats in the primary separation vessel and is recovered as primary froth.

2. Medium density bitumen, containing higher solids content, that does not readily float but that 80, requires air for froth flotation and is recovered as secondary troth.

70 3. High density bitumen, containing even higher solids contents, that leave the hot water process along with the tailings of primary and secondary separation. The Oleophilic Process does not rely upon flotation to 5o recover the bitumen and is not influenced by the density of the bitumen or the solids content of the bitumen in the slurry to achieve effective separation. 40 As a result, the bitumen recovered from the tailings by oleophilic separation, tends to have a higher solids 30 content than the primary and secondary froths produced from the hot water extraction.

20 In comparison with hot water process combined froth, the bitumen product from oleophilic separation of effluent streams was low in water content. 10. It was also found that the bitumen product of Oleophilic Separation was unusually high in titanium ore content. It 0 • ./ appears that bitumen has an affinity for heavy minerals 0 2 4 6 8 10 and concentrates these out of the tar sands. The bitumen 12 14 16 particles, heavily loaded with titanium ore and other WEIGHT PERCENT BITUMEN IN TAR SAND FEED FIQLJRF 2 BITUMEN RECOVERY WITH HOT WATER EXTRACTION PROCESS SYNTHETIC FUELS REPORT, DECEMBER 1982 minerals, have some difficulty floating in the hot water trated the zirconium by a factor of about 40 and the process and thus sink along with the sand, silt and clay. titanium by a factor of about 20. As explained in a later section, oleophilic separation can capture this bitumen from the tailings. Traditionally, heavy minerals recovery has been considered from the centrifugal scroll tailings of the hot Economic Feasibility of Tailings Treatment water extraction process only. These centrifugal tailings represent the solids that remain associated with the In parallel with the above experimental work, an engi- bitumen throughout the extraction process. These solids neering study was done by Dynawest Projects Ltd. of are then removed when diluent is used to clean up the Calgary to evaluate the economic feasibility of bitumen bitumen prior to upgrading. recovery by oleophilic separation from hot water extraction process tailings. Recent studies conducted by Kruyer Research and Development Ltd. on hot water extraction tailings have Three grades of mined Athabasca feedstock were con- shown that the bitumen remaining in the primary tailings sidered; 12%, 10% and 8% bitumen content tar sand. (which is presently lost to the tailings ponds) is unusually high in titanium content. Oleophilic separation was used The study evaluated economic merit of the process for to recover this residual bitumen. In some cases, the three bitumen recovery efficiencies. The first effi- bitumen product of this separation contained in excess of ciency considered was that 70% of the bitumen present 15% heavy minerals. That is, 15 grams of minerals denser in the hot water process tailings could be recovered by than a specific gravity of 3.0 were contained in every 100 oleophilic separation. This was carried through the grams of bitumen product from the oleophilic sieve. detail in the study. The second efficiency was that 90% could be recovered, and the third was that 50% could be At the present time, all tailings from commercial hot recovered. These last two were carried through the water extraction accumulate in the settling ponds. study to a lesser extent. Usually the sand is used to build dykes for the pond and the liquid tailings run off into the pond where the residual These three recovery efficiencies were selected to bitumen accumulates into a sludge containing 5% permit plotting of the results of economic merit on a bitumen. - curve for guiding present or future experimental and pilot plant studies. Superimposing actual experimental Both minerals and bitumen may be recovered from the results upon the economic merit curves will permit a tailings by oleophilic separation, either before they are direct reading of the economics of the process at any deposited into the pond, or afterwards from the pond stage of its development. sluge. Research and development in both areas is of current interest. Two cases of adding oleophilic separation to the tailings end of a hot water extraction process were considered. ' Process of Deep Deposits In the preferred case, it was assumed that mining continued at the normal rate and that the dilution centri- Much of the world tar sands resource is too deeply buried fuging, coking and refining facilities were adequate to to be amenable to strip mining and various schemes are accomodate the additional bitumen entering the plant used to produce a flowing liquid in-situ that is pumped to from oleophilic separation. This was called "mining the surface and from which bitumen may be produced. limited": In the less preferred case, it was assumed When steam is used for the in-situ process, the bitumen is that dilution centrifuging, coking and refining were produced in the form of an emulsion with water that is operating at capacity and that the additional bitumen then separated above ground to produce the bitumen entering the plant would result in an overloading of the product and the water is disposed of or reused. Tests plant, necessitating a reduction in the mining rate. conducted with oleophilic separation of bitumen in water This was called "upgrading limited". emulsions from a steam drive pilot plant have shown high bitumen recovery and a water effluent that was very low The study considered oleophilic separation of primary in bitumen content. Research and development work is tailings, desinded primary tailings and centrifugal progressing in the direction of a moveable pilot plant that tailings. It also considered combinations of these will separate the'emulsions produced from one well at a streams to optimize the apparatus configuration. time. The configuration selected for the feasibility study is shown in Figure 2, and gave the results tabulated in Table 2. Mineral Recovery It is commonly known that during separation of mined tar sands these heavy minerals tend to associate with the bitumen. For example, a test with hot water extraction of a tar sand sample containing 0.05 per cent zirconium and 0.21 per cent titanium resulted in a bitumen troth containing 1.95 per cent zirconium and 0.04 per cent titanium. Thus the froth had concen-

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-31 TABLE 2 SUMMARY OF ECONOMIC EVALUATION

Tar Sand % Return on Investment Simple Payback Period(Yrs.) Grade % Ten Sieve Five Sieve Ten Sieve Five Sieve Bitumen Case Case Case Case Mining Limited Case 12 37.2 51.6 2.7 1.9 10 89.8 120.1 1.1 0.8 8 164.8 222.4 0.6 0.4

Uorading Limited Case Good Grade Oil Sand 11.7% Average Bitumen 10.5 16.8 9.5 5.9 Average/Lower Oil Sand 10.9% Average Bitumen 46.7 64.0 2.1 1.6

Basis: Synthetic crude at $38./Bbl.; Oleophilic sieve recovery rate 70%; Operating costs $10./Bbl. for additional bitumen produced; Cost savings associated for upgrading limited case $5.50/Bbl. and sieve operating costs $2.03/Bbl. of bitumen.

3-32 SYNTHETIC FUELS REPORT, DECEMBER 1982

RESOURCES

WESTERN KENTUCKY TAR SANDS large resource. (An article on page 3-35 the of December 1981 issue of the Pace Synthetic Fuels Report also A paper, "Tar Sand Reserves of Western Kentucky" by describes tar sand depositsof western Kentucky.) Martin C. Noger of the Kentucky Geological Survey, reports on the preliminary results of an inventory and Figure 1, from the report, shows the general location of evaluation study initiated by the Kentucky Geological tar sand outcrop occurrences and major regional tectonic Survey in 1981. The preliminary results of the study features. The reported occurrences of tar sands in are based on data obtained from: driller's logs, western Kentucky are located in the general proximity of published sample descriptions, geophysical logs, litho- the flanks of the fault bounded Moorman syncline. The logic core descriptions, and core analyses provided by location of the deposits would suggest that they are industry. The report points out that no reports have yet related to faulting; however, insufficient evidence exists been published on the subsurface tar sand potential of to adequately support this theory. To date, known oil western Kentucky and suggests that detailed explora- impregnated deposits are limited to Upper Mississippian tion and evaluation are needed to quantify a potentially and Lower Pennsylvanian strata. Figure 2is a generalized

EXPLANATION Fault

/Tar-sand outcrop area ? URBANAI . I INDIANAPOLIS t•SPRINGFIELD : * OHIO ILL. IND. Eastern I BLOOMINGTON Interior C Basin LOUISVILLE *FRA KFORT W. VA. I , •EXINGTON t , Appalachian - ENHYRILE F MO. Basin pi3 %ZA AH_—tjrnet.. VA. STUDY ARE Mississippi NASHVILLE* Embayment I TENN. KNOXVILLE

r'c- 0 25I- 50- 75 IOOMILES

FIGURE 1 LOCATION OF MAJOR TAR SANDS OCCURRENCES AND MAJOR TECTONIC FEATURES

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-33 stratigraphic section identifying the formations hosting the tar sand deposits of Western Kentucky. * BITUMEN IMPREGNATED UNITS The text of the paper contains a description of the known tar sands to date. This information has been summarized by Pace and is shown in Table 1. Not all of the tar sand Z occurrences are shown in Table 1 as some occurcnces were mentioned but no data was presented. Kentucky Z Bee Spring Sandstone* Geological Survey has targeted the Big Cifty Sandstone in the areas of Logan, Butler, Warren and Edmonson > E —I - Main Nolin coal bed Counties as the initial study area. The data provided on >-. w the Big Clifty Sandstone in Edmonson County indicates (F, that the inplace resource value of bitumen could approach Z on the order of 65,000 Bbls/acre. Kyrock Sandstone 3 The paper reports that during 1959 and 1960, Gulf Research and Development Company conducted a pilot field test of forward combustion in tar sand (Pennsylvanian Sandstone) located in northern Edmonson County. The tests indicated that forward combustion through an induced system of horizontal fractures was a technically feasible method of producing oil from the C .2 Pennsylvanian tar sand deposits. Another firm, TARCO, t —2-- is processing Big Clifty tar sand from a quarry in northern Logan County in a pilot plant. At this pilot plant the o -- - sandstone is crushed and the oil is extracted by a solvent. Err Also, Westken Petroleum Corporation is conducting an in- situ combustion project in Big Clifty Sandstone in western Edmonson County. .Z Vienna Limestone

Z Tar Springs SandstoneS a- -

Glen Dean Limestone F1

Hardinsburg Sandstone*

Haney Limestone

Is. a

S Big Clifty Sandstone5

Beech Creek u.

FIGURE 2 GENERALIZED COLUMNAR SECTION SHOWING STRAtIGRAPHIC POSITION OF TAR SAND UNITS IN WESTERN KENTUCKY

3_34 SYNTHETIC FUELS REPORT, DECEMBER 1982

V ii

C I liii IlllH

14'-1 11111 I 1 17 1 H

II Hill lllIll muO

a 11111 HHIII

t. I II II III I UI - 0 1H — a a. c.. II

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o o 0v'a.,,n Coin,., it!!-I-

2 zz '

a 243 V U 0) U V z n 0 -- = C a P s

SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF OIL SANDS PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name Aarian Development, Inc. A.D.I. Chemical Extraction ...... 3-42 Alberta Energy Company Ipiatik Lake Project ...... 3-47 Suffield Heavy Oil Pilot ...... 3-52 Syncrude Canada, Ltd ...... 3-41 Alberta, Province of Syncrude Canada, Ltd ...... 3-41 Alminex, Ltd. Sandalta ...... 3-41 Amoco Canada Ltd. Block One Project ...... 343 Peace River In Situ Pilot Project ...... 3-50 AOSTRA Block One Project ...... 343 Calsyn Project ...... 3-44 North Kinsella Heavy Oil Project ...... 3-50 Peace River In Situ Pilot Project ...... 3-50 Suffield Heavy Oil Pilot ...... 3-52 Surmont Project ...... 3-52 Taciuk Process Pilot ...... 3-53 Aquitaine Company of Canada Ltd. Beaver Crossing Thermal Recovery Pilot ...... 3-43 BP Exploration Canada Ltd. Cold Lake Pilot Project ...... 344 Marguerite Lake Phase A Pilot Plant ...... 3-48 C&A Companies MRL Solvent Process ...... 349 California Synfuels Research Corp. Calsyn Project ...... 344 Canada Cities Service, Ltd. Eyehill In Situ Steam Project ...... 3-46 Mine Assisted In Situ Project ...... 349 PCEJ Project ...... -50 Syncrude Canada, Ltd ...... 3-41 Canadian Reserve Oil & Gas Ltd. Eyehill In Situ Steam Project ...... 3-46 Canterra Energy Ltd. Calsyn Project ...... 344 CDC Oil and Gas, Ltd. Athabasca In Situ Pilot Project ...... 343 Chevron Standard Ltd. Beaver Crossing Thermal Recovery Pilot ...... 343 Conoco, Inc. Conoco South Texas Tar Sands Project ...... 3-45 Cornell Oil Co. HOP Kern River Commercial Development Project ..... 3-47 Dome Petroleum Canada Ltd. Lindbergh Thermal Project ...... 3-48 Morgan Combination Thermal Drive Project ...... 3-49 Dynalectron Corp. Calsyn Project ...... 344 Enereor Asphalt Ridge Pilot Plant ...... 3-42 Cedar Camp Tar Sand Project ...... 344 Enpex Corporation Enpex Tar Sands Project ...... 344 EOR Petroleum Company Chetopa Project ...... 3-44

3-36 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name

Esso Resources Canada Ltd. Cold Lake Project ...... 3-40 Mine Assisted In Situ Project ...... 3-49 PCEJ Project ...... 3-50 Syncrude Canada Ltd ...... 3-41 Getty Oil Company Cat Canyon Stearnflood Project ...... 3-44 Diatomaceous Earth Project ...... 3-40 Glenda Exploration & Development Corp. Burnt Hollow Tar Sand Project ...... 3-48 Great National Corporation Sunnyside Project ...... 3-52 Guardian Chemical Corporation Aqueous Recovery—Polycomplex ...... 3-42 Gulf Oil Canada Ltd. Mine Assisted In Situ ...... 349 Pelican-Wabasca Project ...... 3-50 Resdeln Project ...... 3-51 Sandalta ...... 3-51 Surmont Project ...... 3-52 Syncrude Canada, Ltd ...... 3-41 Haliburton Services R.F. Heating Project ...... 3-51 Home Oil Company Sandalta ...... 3-51 Hudson's Bay Oil and Gas Cold Lake Pilot Project ...... 3-44 Marguerite Lake Phase A Pilot ...... 3-48 Syncrude Canada, Ltd ...... 3-41 Husky Oil Operations, Ltd. - Aberfeldy Project ...... 3-41 Mine Assisted In Situ Project ...... 3-49 Scotford Synthetic Crude Refinery ...... 3-49 Hydrocarbon Research, Inc. Calsyn Project ...... 3-44 lIT Research Institute R.F. Heating Project ...... 3-51 Imperial Oil Ltd. Commercial Extraction Plant, Cold Lake ...... 3-40 Leming Project ...... 3-46 International Hydrocarbons Inc. - International Hydrocarbon Tar Sands Project ...... 3-47 Japan Canada Oil Sands, Ltd. PCEJ Project ...... 3-50 Japan Oil Sands Co. (JOSCO) Primrose Project ...... 3-50 Kirkwood Oil and Gas Company Burnt Hollow Tar Sand Project ...... 3-43 Tar Sand Triangle ...... 3-43 KSA Resources ICensyntar Project ...... 3-47 Laramie Energy Technology Center LETC-TS-1S Reverse Combustion ...... 3-48 (U.S. Department of Energy) Minerals Research Ltd. MRL Solvent Process ...... 3-49 Mobil Oil Canada Ltd. Celtic Heavy Oil Wet Combustion ...... 344 Cold Lake Stratigraphic Test Program ...... 3-45 Mobil Oil Company Asphalt Ridge Pilot Plant ...... 3-42 Mono Power Cedar Camp Tar Sand Project ...... 344 Murphy Oil Canada Ltd. Eyehill In Situ Steam Project ...... 3-46 Lindbergh Steam Project ...... 3-48

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-37 Company or Organization Project Name

Lloydminster Fireflood ...... 3-48 Musketeer Energy Ltd. Suffield Heavy Oil Pilot ...... 3-52 Natomas Energy Company Natomas Solvent Extraction Process ...... 349 Noreen Energy Resources Ltd. Primrose Project ...... 3-51 Nova, An Alberta Corporation Genstar ...... 3-40 Ontario Energy Resources Ltd. Suncor, Inc...... 3-41 PanCanadian Petroleum Cold Lake Pilot Project ...... 3-44 Marguerite Lake Phase A Pilot Plant ...... 3-48 Syncrude Canada, Ltd ...... 3-41 Petro-Canada Block One Project ...... 3-43 Canstar ...... 3-40 Ipiatik Lake Project ...... 34? Mine Assisted In Situ Project ...... 3-49 North Kinsella Heavy Oil ...... 3-50 PCEJ Project ...... 3-50 Primrose Project ...... 3-50 Syncrude Canada, Ltd ...... 3-41 Pittston Company Kensyntar Project ...... 34? Rio Verde Energy Co. Rio Verde Energy Co. Project ...... 3-51 RTR Oil Sands Alberta, Ltd. RTR Pilot Project ...... 3-51 Sandia Laboratories Deepsteam Project ...... 3-45 Santa Fe Energy Company Santa Fe Tar Sand Project ...... 3-52 11200" Sand Steamflood Project ...... 3-54 Saskatchewan Oil and Gas Corporation Meota Steam Drive Project ...... 349 Shell Canada Resources, Ltd. Block One Project ...... 3-43 Peace River In Situ Pilot Project ...... 3-50 Scotford Synthetic Crude Refinery ...... 3-40 Shell Explorer, Ltd. Peace River In Situ Pilot Project ...... 3-50 Sohio Natural Resources Company Asphalt Ridge Pilot ...... 3-42 Solv-EX Corporation Santa Rosa Oil Sands Project ...... 3-52 Standard Oil of Indiana (Amoco) Sunnyside Project ...... 3-52 Sun Oil Company Block One Project ...... 343 Fort Kent Thermal Project ...... 3-46 Suncor, Inc ...... 3-41 Superior Oil Company Enpex Tar Sands Project ...... 4-45 Syncrude Canada, Ltd. Syncrude Canada, Ltd ...... 3-41 Tareo, Inc. Tarco Tar Sands Project ...... 3-53

3-38 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name

Tenneco Oil Company Calsyn Project ..... 3-44

Tenneco Oil of Canada, Ltd. Athabasca In Situ Pilot Project 3-43 Tetra Systems, Inc. Chetopa Project 3-44 Texaco Canada, Ltd. Texaco Athabasca Pilot 3-53 Texas Gulf, Inc. Meota Steam Drive Project 3-49 Texas Tar Sands, Ltd. Enpex Tar Sands Project 3-45 Total Petroleum Meota Steam Drive Project 3-49 Underwood McLellan & Associates Taciuk Processor Pilot. 3-53 (IJMA Group)

Union Oil of Canada, Ltd. Grosmont Thermal Recovery Project 3-46

Union Texas of Canada, Ltd. Ardmore Thermal Pilot Plant 3-42 United International Research, Inc. Aqueous Recovery - Polycomplex 3-42 U.S. Department of Energy Cat Canyon Steamflood Project 3-44 Deepsteam Project..... 3-45 R.F. Heating Project 3-51 "200" Sand Steamflood Project 3-54 University of Utah Asphalt Ridge Pilot Plant 3-42 Sunnyside Project...... 3-52 Westcoast Petroleum, Ltd. Suffield Heavy Oil Pilot 3-52 Western Tar Sands, Inc. Ultra Sonic Wave Extraction 3-53 Westken Petroleum Co. Kensyntar Project ..... 3-47 Whitler Group Enpex Tar Sands Project 3-45 Worldwide Energy Fort Kent Thermal Project 3-46

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-39 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982) OIL SANDS COMMERCIAL PROJECTS CANSTAR - Petro-Canada, Nova - An Alberta Corporation An oil sands mining complex is planned on a site in the Athabasca deposit. Both Husky Oil Ltd., and Alberta Natives have an option for up to 10 percent interest in the project. Plans to submit a regulatory application for approval have been indefinitely deferred. Studies continue on determinng plant size, extraction and upgrading technology, and oil sands geology. Project Cost: Not yet determined. ESSO RESOURCES CANADA LIMITED - Cold Lake Project Esso Resources Canada Limited has completed the design of a 141,000 BPD commercial oil sands extraction project near Cold Lake, Alberta. Esso Resources is a wholly owned subsidiary of Imperial Oil Limited, encompassing the latter's upstream assets and operations. The Cold Lake project will recover heavy oil from the reservoirs by in situ steam stimulation with subsequent fluid pumping. About half of the Project investment involves bitumen upgrading facilities. The primary conversion step in the upgrading is the Exxon Research and Engineering Flexicoking process, followed by hydrotreating to reduce sulphur and aromatics content, and to adjust yield patterns. The resulting upgraded crude will be suitable for most Canadian refineries to satisfy product demand slates with existing processing equipment. Esso Resources will act as the plant operator and is inviting financial participation by other interests. The Alberta Energy Resources Conservation Board held extensive public hearings on the Cold Lake Project and submitted a favorable recommendation to the Alberta Provincial Government on October 29, 1979. The final step in the public approval process for the Project is the decision of the Alberta Government. This decision was deferred, pending an agreement between the Federal and Province of Alberta Governments on future Canadian crude price increases and the sharing of the resulting revenues between the two levels of government. While these agreements were being negotiated, the Federal Government advanced $40,000,000 to Esso Resources to maintain its Cold Lake project team intact, through July 1, 1981, permitting implementation to proceed promptly on receipt of Alberta approval of the project. In July, work on the project was suspended and personnel re-assigned to other projects. The next steps would be the commencement of field construction and equipment ordering. Esso felt unable to undertake these major financial committments in the absence of agreements with the Federal and Alberta Governments to provide a satisfactory return for the project. On September 1, 1981, the Alberta and Federal Governments signed a new Energy Agreement. The terms of this agreement do not achieve the target of 20% discounted cash flow return. In view of the reduced availability of investment funds in the Canadian petroleum industry as a result of the additional taxation under the National Energy Program, and the uncertain outlook for world crude prices, Esso Resources does not anticipate any revival of the Cold Lake Project in the next few years. Project Cost: Estimated cost $12 billion GETTY OIL COMPANY - Diatomaceous Earth Project Getty Oil Company is studying the feasibility of commercial oil production from oil-saturated deposits of diatomaceous earth located in the McHittrick area of California's San Joaquin Valley. The deposits, which lie at depths of zero to 1,200 feet beneath a 1,680-acre parcel of land owned by Getty, are estimated to contain about 380 million barrels of recoverable oil, which will be recovered using open pit mining and backfiuing techniques. Two extraction processes, the Dravo solvent extraction method and a Lurgi-Ruhrgas retort, are being tested in pilot plants. Both pilots have been completed. The plants will be operated for a year, after which Getty may choose a process for a full-scale plant. Project life for the commercial plant is estimated to be 48 years, with approximate average crude oil production of 20,000 barrels per day throughout the life of the project. Getty estimates crude oil produced from the project will average 13 to 18-degrees API gravity. Commercial plant start-up is tentatively scheduled for no earlier than 1987. Project Cost: Undetermined at this time. SCOTFORD SYNTHETIC CRUDE REFINERY - Shell Canada Ltd., Husky Oil Operations Ltd. The project will be the world's first refinery designed to use exclusively synthetic crude oil as feedstock, to be built in the Edmonton area. Initial capacity will be 50,000 barrels per day with the design allowing for expansion to 70,000 barrels per day. Feedstock will be provided initially by the two existing oil sands plants and will be supplemented by the proposed Alsands project in the late 1980's. The refinery's petroleum products will begasoline, diesel and jet fuel and stove oil. The refinery will also produce 4,800 barrels per day of benzene which will be used as feedstock for a world scale styrene plant presently under construction in the refinery vicinity. The refinery was to have been owned 60 percent

3-40 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNPUELS PROJECTS (Underline denotes changes since September 1982 COMMERCIAL PROJECTS (Cont.)

by Shell Canada Limited (operator) and 40 percent by Husky Oil Operations Ltd. In April 1982, Shell and Husky (68% owned by Nova, an Alberta Corp.) decided to end the joint venture, leaving Shell with 190% interest in the project. The benzene manufacturing facilities associated with the refinery will also be owned by Shell Canada Limited as planned. An application for a permit to construct has received the approval of the Energy Resources Conservation Board of Alberta and the Government of Alberta. The prime contractor is PCL-Braun-Simons Ltd. (P-B-S) of Calgary, Alberta. Engineering and construction of the refinery has progressed to the 80% and 30% completion points respectively, with installation of underground piping, erection of storage tanks and construction of foundations now largely completed.

Project Cost: $1 billion (Cdn.) total final cost. SUNCOR, INC. (formerly Great Canadian Oil Sands, Ltd.) - Sun Oil Co. (72.8 percent), Ontario Energy Resources Ltd. (25%), publicly (2.2 percent) Commercial oil sands plant located 40 kilometers north of Fort McMurray, Alberta, which has been in production since 1967 with authorized annual production of 7 151 m3 per day from the Athabasca bituminous sands deposit. Annual production for 1980 was 7,421 m 3 per day. Mining is carried out with buckctwheel excavators; extraction is by hot water process. Upgrading is by delayed coking and hydrogen saturation (Unifining). Coke and, to a lesser extent, natural gas, fuel the on-site power plant. Production capacity was 7 150 m 3 until September of 1981 when an expansion was completed. The expansion added a third mining bench and bucketwhecl excavator, a fifth line in the extraction plant and an additional pair of coking drums. A 250,000 lb. gas-fired boiler was added in the Utilities plant. Capacity is now 9 217 m 3 per day. Suncor Inc. was formed in August, 1979, by the amalgamation of Great Canadian Oil Sands and Sun Oil Co. Ltd. From April 1979 to January 1, 1981, Suncor received world price for its synthetic crude production. However, the National Energy Program (NEP), announced in November 1980, rolled back prices of the Oil Sands Division. Under the NEP, domestic wellhead price was received for the first 7 151 m 3 per day (pre-expansion nominal capacity) and world price for any daily production exceeding that figure. In 1981 the company was returned to Canadian wellhead prices. Effective Januyry 1, 1982, Suneor's Fort McMurray, Alberta, plant received a standard price (New Oil Reference Price) for all production. This is about $45 per barrel (Canadian) and was part of the September 1981, Energy Agreement. In November 1981, Ontario Energy Resources Ltd. acquired a 25% interest in Suncor Inc. Suncor plans to move toward 51% Canadian ownership by 1984. In late July, Suncor Inc. announced plans to expand and go ahead with the 'Large Pit" project at a cost of $355 million Canadian. Of this, $170 million will be spent to improve operations while $185 million will be spent to increase reserves by about 90 million barrels and add five years to the life of the mine lease. SYNCRUDE CANADA, LTD. - Esso Resources Canada Limited (25 percent); Canada Cities Service, Ltd. (13.2 percent); Gulf Canada Resources Inc. (13.4 percent); Petro-Canada Exploration Inc. (17 percent); Alberta Energy Company (10 Percent); Province of Alberta (12.4 percent); PanCanadian Petroleum Limited (4 percent); Hudson's Bay Oil and Gas Co., Ltd. (5 percent) Plant at 93+92-10 W4M with an allowable production of 129,000 HPCD has been in early stages of production since July 31, 1978. Mining - electric draglines; extraction - hot water flotation process; upgrading - two fluid cokers: Canadian Bechtel Ltd. was managing contractor. Start-up in progress, now producing. Initial production of 52,000 BPD; by 1982, 109,000 BPD; by 1984, 129,000 BPD. In 1979, 18 million barrels of synthetic crude were delivered. Production in 1980 was over 28 million barrels, production in 1981 was over 29.7 million barrels. All major equipment in place and operational; four draglines and four bucketwheels working. Syncrude's staff is now 4,200. Project Cost: Total cost $2.3 billion R&D ABERFELDY PROJECT - Husky Oil Operations, Ltd. An in situ steam drive with steam stimulation project is being developed at Aberfeldy Section 20-49-26 W3M in Saskatchawan. Installation of equipment and flow lines is complete. Steam injection commenced February 1981.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-41 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

A.D.I. CHEMICAL EXTRACTION - Aarian Development, Inc. Aarian Development Incorporated will use A.D.I. Chemical Extraction technology to produce 20,000 barrels of bitumen per day from Eastern Utah oil sands. The plant would be built in three phases, with construction beginning in 1982 and initial production starting later that year at 5,000 to 8,000 barrels per day. Phase two will increase to 14,000 barrels per day in the third year. Phase three would reach 20,000 barrels per day in 1986. Loan guarantees and price guarantees have been requested from the Synthetic Fuels Corporation. Project Cost: $28.3 million. AQUEOUS RECOVERY - Dicore Process, United-Guardian, Inc. The aqueous recovery process investigates the feasibility of using a low concentrate solution of a Polycomplex to extract bitumen from oil sands. The pilot plant will initially operate in Long Island, NY.

Project Cost: $1.0 million plus ARDMORE THERMAL PILOT PLANT - Union Texas of Canada, Ltd. Union Texas of Canada, Ltd., is operating in an in situ recovery pilot in the Cold Lake tar sand deposit of northeastern Alberta. The purpose of the project, consisting of 15 wells drilled on 5 acre spacing, was to evaluate both steam stimulation (huff and puff) and steam drive. The reservoir crude is immobile at original conditions, but by using steam stimulation, the reservoir temperature around the well bore was increased enough to allow the heavy crude (10-12° API) to be produced. After several steam stimulation cycles, interwell communication was established between 4 of the 15 experimental wells. At that point, (approximately January 1, 1980), the project was converted to a steam drive with one injector and three producers (the other 11 wells were shut-in). Since then the production rate of the three producers has averaged in the order of 50 BOPD/well. To date a total of more than 250,000 BBLs of heavy crude have been recovered since the pilot was initiated. Project Cost: Capital Costs estimated at $3.0 million ASPHALT RIDGE PILOT PLANT - Enercor, University of Utah, Mobil A pilot project to test the University of Utah Hot Water Extraction process on various Utah tar sands. November 9, 1981, was the official start-up date for the 50 BPD pilot plant which is to operate for six to eight months. Enercor is the prime contractor, Ford, Bacon, and Davis handled plant design and construction, and the University of Utah Research Institute is responsible for plant operation. Enercor received a $450,000 grant from the Utah State Advisory Council on Science and Technology, who will, according to provisions of the appropriation legislation, monitor pilot plant activities through the'Utah Engineering Experiment Station. Pilot plant completed Phase I operation on April 15, 1982. Results were favorable. A large quantity (5,000 - 6,000 tons) of tar sand ore from P. R. Springs, White Rocks, and Asphalt Ridge were run through the pilot plant. General tar recoveries from the ore were in the 95% range. Twenty to 1 water recycle to purge was achieved. Bitumen produced was of high quality and performed well in delayed coking pilot tests. Phase II work of six months duration to start soon, testing ore from other areas of P. R. Springs and Sunnyside. Project Cost: Estimated at $1.5 million ASPHALT RIDGE TAR SANDS PILOT PLANT - Sohio Shale Oil Company A surface mining project using solvent/water extraction, located on approximately 8,550 acres in liintah County, Utah. The extraction process is a process called "continuous counter current solvent extraction process" developed by Sohio in the laboratory. Phase I of the project, completed in 1981, involved completion of the laboratory process development work, design of a 24 BPD pilot plant by Bechtel, securing necessary permits and approvals and completing notification procedures. This was completed during 1981. Bechtel studied the feasibility of a 20,000 BPD commercial plant. The pilot plant will process about 60 tons of mined tar sands daily. Bechtel's design of the

3-42 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

plant has been completed. A decision is expected in 1983 to proceed with Phase II, the construction and operation of the pilot plant. Project Cost: Undisclosed ATIIABASCA IN SITU PILOT PROJECT - CDC Oil and Gas, Ltd., Tenneco Oil of Canada, Ltd. The COC/TECAN steam flood pilot, scheduled for startup in late 1981, will begin with steam stimulation of production wells folloWed by continuous steam injection into the injection wells. Two separate patterns will be tested to compare the effect of different well spacing. Anticipated peak oil production rate is about 2,000 BOPD. All pertinent data concerning the volumes and pressures of steam injected, steamfront movement through the formation, and the volumes and analysis of the produced fluids will be recorded and stored on a micro-computer for future analysis. A total of 50 wells will have been drilled and completed during the 1980-81 winter drilling season including 10 producers, 16 injectors, 15 temperature observation wells inside the patterns, three observation wells outside the patterns, three water source wells, and three water disposal wells. The pilot project commenced ooerations durinif December. 1981. Initially only the one well nattern received in jection. Plans are to commence

If the pilot is successful during the first few years of operation, it would be expanded in 1984. Also, other supplemental techniques (nitrogen or carbon dioxide injection) might be tested. An intensive corehole program and geological analysis would be conducted on the in situ lands of Lease 87 to determine the best location for a commercial project. Project Cost: $40 million (estimate) BEAVER CROSSING THERMAL RECOVERY PILOT - Chevron Standard Ltd. The original project, an experimental in situ project located at 36-61-2-W4M, was terminated. ERCB approval No. 2269 was issued April 18, 1977 for a cyclic experimental scheme for the recovery of crude bitumen from the Cold Lake Oil Sands Deposit. This approval was amended to locate the pilot in Section 31-61-1 W4. Construction began in early May 1977 with operation commencing in March 1978. Approval was further amended in November 1981 to convert to drive operation and extend expiration to 12/21/1984. Project consists of six producing wells, one steam injection well and eight temperature observation wells. A steam drive-producing well stimulation procedure is followed utilizing a 25 MM Btu/HR generator. Canterra Energy Limited acquires information from the project under an agreement subject to annual renewal. Project Cost: Undisclosed BLOCK ONE PROJECT - Amoco Canada Petroleum Company Ltd., AOSTRA, Petro-Canada, Ltd, Suncor, Inc., Shell Canada Resources This experimental in situ recovery pilot is located in section 27 .85.8 W4M, Gregoire Lake, Athabasca deposit, Alberta, Canada. The project, called Block One, consists of nine 2-1/2 acre patterns, expected to produce nearly 1,000 BPD. This in situ project is utilizing a 3-step process including COECAW, Amoco holds patent rights to this process. A total of nine injection, 16 production and seven observation wells are contained within the patterns. Operations commenced in August 1977 and Phase A is scheduled to end in 1981. The venture will be assessed at that time to see if it should be renewed until project completion in 1985. An agreement was signed with AOSTRA to undertake this project as a 50 percent working interest partner in 1976. Petro Canada Ltd, Shell-Canada Resources and Suncor Inc. each acquired a 12.5 percent interest in the project, reducing Amoco's share to 12.5 percent. Project Cost: Phase A $46 million (Cdn.) Phase B $25 million (Cdn.) BURNT HOLLOW TAR SAND PROJECT - Kirkwood Oil & Gas Company, Glenda Exploration & Development Corp. A 7.5-acre pilot project for in situ recovery of oil from the Burnt Hollow tar sand deposit near Devils Tower in Crook County, Wyoming. A steam drive process will be applied to the 600-1000 feet deep reservoir containing 9 0 to 12 0 API oil with a viscosity up to 1 million centipoises in the reservoir. Start-up was delayed until September 1982. Kirkwood Oil & Gas leased the tar sand property to Glenda as the general partner of a joint venture group who provided financing, and Technical Enterprises was responsible for most of the engineering and design work. The pilot consists of two injection wells and six producing wells. The project was run for several months and the information gathered is currently being evaluated. Project Cost: Unknown

SYNTHETIC FUELS REPORT, DECEMBER 1982 - 3-43 STATUS OF SYNPUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

CALSYN PROJECT - California Synfuels Research Corp. (Tenneco Oil Co., Dynalectron Corp., Alberta Oil Sands Technology and Research Authority, and other equity partners) Dynalectron subsidiary Hydrocarbon Research, Inc. (HR1) is working with California Synfuels Research Corporation, operators for joint venture to build a commercial-scale heavy oil upgrading plant near Pittsburg, California, capable of handling heavy oil, tar sand bitumen and shale oil. The facility is designed to initially handle 5,100 barrels per day of vacuum residue. The plant will use an HRI-patented process known as "Dynacracking." The project has received letter of intent from the Synthetic Fuels Corporation for a loan Guarantee. Project Cost: $72.1 million total cost, including construction, start-up, interest, and contingencies

CAT CANYON STEAMFL000 PROJECT- Getty Oil Company, U.S. Department of Energy. The objective of this pilot program is to evaluate the feasibility and economics of the steam displacement process for future full-scale development of the Cat Canyon Si-B oil sand reservoir and in similar deep heavy crude oil reservoirs. The pilot consists of four inverted five-spot patterns of five-acre spacing. Initial steam displacement began in April 1977. Steam injection was continuous through February, 1980 except for brief down-time periods for well or steam generator maintenance. Steam injection was shut-in until January 1982 to dc-water the pilot area. Steam injection operations have been resumed. Ultimate Project Cost: $8,700,000 CEDAR CAMP TAR SAND PROJECT - Enercor, Mono Power Conceptual project to include a 50,000 BPD (maximum) tar sand processing plant associated with a surface mine in the PR Spring area. Modified hot water extraction would be employed. At present, reserves for a 20 year, 50,000 BPD plant are estimated, but not yet confirmed by an actual coring program. Construction of the first 15,000 BPD phase could begin as early as 1984. Project Cost: Unknown CELTIC HEAVY OIL WET COMBUSTION - Mobil Oil Canada, Ltd. Mobil's wet combustion heavy oil project is located in T52 and R23, W3M in the Celtic Field, northeast of Lloydminster. Pilot project entails twenty production wells and five injection wells, on 5-acre spacing, with the intention of testing an in situ wet combustion recovery method to determine the technical and economic feasibility of applying it commercially to the Celtic field. Stimulation techniques such as steam injection will be investigated to improve individual well productivity. Wells have been drilled; construction of injection and production facilities were completed by March 1981. Air injection started in late October 1980. One well is currently on air injection with ignition of the reservoir taking place in August. Total cost for facilities and wells is $20 million. Project Cost: $30 million (Cdn.) CHETOPA PROJECT - EOR Petroleum Co., Tetra Systems EOR and Tetra Systems are developing a joint venture agreement, operating agreement, and an initial evaluation plan to confirm reservoir extent and ascertain reservoir rock and fluid properties. The evaluation will include the drilling of three (3) or more wells, coring, logging, and laboratory analysis of the rock and fluid samples obtained. Future plans will be predicated upon this information. The Chetopa Project, located in Labette County, Kansas, could use technology for heavy oil recovery developed by Tetra Systems. This process involves the excavation of aseries of shafts, approximately 12 feet in diameter and 100-200 feet deep, and the insertion of steam pipes into the formation beneath each unit. "Flip-Flop" technology is used to extract heavy oil from the reservoir. EOR has requested that the U.S. Synthetic Fuels Corporation enter into a loan guarantee commitment for $21 million. COLD LAKE PILOT PROJECT - BP Canada, PanCanadian Petroleum Ltd., Hudson's Bay Oil and Gas A second pilot plant is being considered by HP Canada, located near the Alberta-Saskatchewan border in the Cold Lake area, on 75,000 acres of land. The plant will cost approximately $190 million and produce 7,000 barrels of oil per day. Twenty-two (22) wells were drilled in 1981 to determine a site for the plant. An application approved by the ERCB in September 1982. Preliminary field work has commenced with roadwork and drillsite preparation.

* New or Revised Projects

344 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

Engineering work for the field facilities is underway and bids have been received for detailed engineering, procurement and construction on the plant. Project Cost: Approximately $190 million (Cdii.) COLD LAKE STRATIGRAPHIC TEST PROGRAM - Mobil Oil Canada, Ltd. A stratigraphic test program was conducted on Mobil's 75,000 hectares of heavy oil leases in the Cold Lake area. Approximately 100 holes have been drilled to date for the evaluation program. Heavy oil zones with a total net thickness of 30 meters have been delineated at depths between 290 and 460 meters. This pay is found in sand zones ranging in thickness from 2 to 10 meters. A program is currently underway to evaluate several of these zones by obtaining reservoir fluid samples and production testing. A stimulation program using steam and solvent including formation fracturing techniques will also be carried out. These data are required prior to selecting a site for a possible pilot.

Project Cost: Unknown CONOCO SOUTH TEXAS TAR SANDS (SOnS) PROJECT - Fracture Assisted Steamflood Technology (FAST) This Maverick County, Texas project involves the use of a novel and newly patented fracture assisted steamflood process (FAST) to recover -2° API gravity (i.e. viscosity over 2,000,000 cp) tar from the San Miguel 4 formation at a depth of 1500 feet. The first 5-acre inverted 5-spot pilot test conducted during the 31 month period beginning December 1977 and ending June 1980 was succesful in producing 169,000 barrels of tar which corresponds to better than 50 percent recovery efficiency. To confirm the performénce of this first pattern, a second 7 1/2-acre inverted 7-spot pattern is presently being conducted at a location 2 miles west of the previous pilot site. Continuous steam injection and production at the new pilot began in August 1981. Tar response started at 300 BPD and peaked at nearly 600 BPD during November before beginning a gradual decline. Steam injection was terminated in June of this year and the pilot is presently in the final stages of post-steam water injection. To date, about 130,000 barrels or 49 percent of the original tar-in-place have been recovered and the energy requirements have been reduced 25 percent relative to the prior test. Because low cost steam significantly improves the economic feasibility of a large scale tar sands project, part of the steam for this second pilot test was provided by a solid fuel fired fluidized bed steam generator. During the year, the 50 MMBTU/HR FEC demonstration unit operated for more than 4000 hours and completed successful test burns on a wide variety of fuels ranging from low sulfur (1.5 wt %) coal to high sulfur (7.1 wt. %) petroleum coke. Reportedly, this is the world's first application of the FBC concept to oil-field steam generation. Currently, Conoco plans to continue ongoing process development work at the existing pilot plant location. Project Cost: Unknown DEEPSTEAM PROJECT - U.S. Department of Energy, Sandia Laboratories This project includes use of a downhole steam generator developed to operate at the base of the oil-bearing formation. Field testing started in February 1980 on the Chevron lease near Bakersfield, California. During the first phase of the test, steam will be injected from above ground. In the second phase of the test, foam will also be used to control movement of steam through the reservoir. The generator will be lowered into the hole in the following phases. Trials of three downhole steam generators began in the summer of 1980. During a 5-month test, 25,000 BBL of heavy crude were recovered from the Kern River Field in California by using the downhole generator on the surface. Longer term tests are in progress at Long Beach, California. Two downhole steam generators are used in the Long Beach test, one using air and diesel fuel, the other oxygen and diesel fuel. The program is intended to produce commercially designed units by 1982-1983. DYNACRACKING UPGRADING PLANT - Hydrocarbon Research, Inc. (see Calsyn Project)

ENPEX TAR SANDS PROJECT - Texas Tar Sands Ltd. An in situ steam drive pilot project located in Maverick and Zavala Counties, Texas. Texas Tar Sands, Ltd. is comprised of ENPEX Corporation, Managing General Partner and Operator; Ray M. Southworth, General Partner; Superior Oil Co., Limited, Partner; and Whittier Group, Limited Partners. A 300 BPD pilot is scheduled for start-up in June 1982. A 50 mm Btu/Hr, coal-fired, fluidized-bed steam generator designed by Energy Resources Company, Inc., will be employed on site. The generation and production facilities will be contructed by CE-NATCO. ENPEX has requested price guarantees from the SFC for 10,000 BPD of production of tar in Maverick and Zavala

New or Revised Projects

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-45 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

Counties, Texas. The Empex Syntaro Project will employ steam drive for production and LC-Fining for upgrading. Construction is scheduled for 1984 with initial operation in 1986. Project Cost: Unknown

ESSO RESOURCES CANADA LIMITED - Cold Lake Pilot Projects Esso operates two steam based in situ recovery projects, the May-Ethel and Leming pilot plants, using steam stimulation in the Cold Lake Deposit of Alberta. Tests have been conducted since 1964 at the May-Ethel pilot site in 27-64-3W4 on Esso's Lease No. 40. Current project approval is 1,500 BOPD with productivity around 700 BPD from 30 wells on a five spot pattern. Esso has sold these data to several companies. Esso's Leming pilot is located in Section 5 through 8-65-3W4 and currently produces 7,000 BOPD. The Leming pilot uses a seven spot as well as an oblong line drive pattern. A horizontal well was drilled in 1978. Esso expanded its Leming field and plant facilities in 1980 to increase the capacity to 14,000 BOPD at a cost $60 million. Operating wells at Leming by year-end 1981 will total 206. Major prototype facilities for the commercial-scale Cold Lake Project will be tested in the expanded Leming pilot including 175,000 It/hour steam generators, and a water treatment plant to convert the saline water produced with the bitumen into a suitable feedwater for the steam generators. A 150 mile pipeline system to transport diluted bitumen from Cold Lake to Edmonton, Alberta and return the diluent material to Cold Lake was commissioned in May 1982. The diluent is required to reduce the bitumen viscosity to an acceptable level for pipeline shipment. Project Cost: $200 million

EYEHILL IN SITU STEAM PROJECT - Murphy Oil Company Ltd, Canada Cities Service, Ltd., Canadian Reserve Oil and Gas Ltd. The experimental pilot is located in the Eyehill field, Cummings Pool, at Section 16-40-28-W3 in Saskatchewan six miles north of Macklin. The pilot consists of nine five spot patterns with 9 air injection wells, 16 producers, 3 temperature observation wells, and one pressure observation well. The pilot covers 180 acres. Ignition of the nine injection wells was completed in February 1982. The pilot is now fully on stream. Partial funding for this project was provided by the Canada-Saskatchewan Heavy Oil Agreement Fund. The pilot was given the New Oil Reference Price as of April 1, 1982. The pilot has 40 feet of pay with most of the project area pay underlain by water. Reservoir depth is 2,450 feet. Oil gravity is 14.3°API, viscosity 2,750 Cp at 70°F, porosity 34%, and permeability 6,000 nd. Project Cost: $13.7 million

FT. KENT THERMAL PROJECT - Worldwide Energy Corporation and Suneor, Inc. Worldwide Energy Corporation and Suncor, Inc. have completed Phase H of a three phase program to develop heavy oil deposits on a 4,960 acre lease in the Fort Kent area of Alberta (28-61-4-W4M). Thirty-eight wells have been completed, current production exceeds 1,200 BPD. Under an agreement between Worldwide and Suncor, Suncor became the operator of the project on January 1, 1980. Engineering evaluation of Phases I and II proceeded throughout most of 1981. Current plans project the start of a commercial development in 1982. Preliminary engineering designs for the expansion have been completed, involving the drilling of 112 wells and construction of additional steam facilities at an approximate cost $88 million. The 112 wells will be drilled in three and one-half (30 clusters of 32 wells in 1982 and 1983, using a slant hole rig. The expansion will boost production to 5000 BPD. ERCB approved the expansion and granted the partners a five percent experimental royalty rate, and world level oil prices (determined by the New Oil Reference Price) for both existing and future production, effective April 1, 1982. Agreement in principle has been reached with the nearby town of Bonnyville to use its sewer effluent as water source for steam injection. Suneor will spend 55 percent of the first $137 million (Cdn.) and the companies will share the remaining cost equally.

Project Cost: Estimated Total Cost $448.6 million (Cdn.) (escalated for cost of living). GROSMONT THERMAL RECOVERY PROJECT - Union Oil Company of Canada Limited Since 1975, Union has operated three in situ steam tests and two in situ combustion tests in the Grosmont formation of Alberta's carbonate heavy oil deposit. In 1982, a new single five spot pattern is to be tested using stimulation and drive processes in section 28-87-19 W4. Participants in this project include the Alberta Oil Sands Technology and Research Authority (50 percent), Canadian Superior Oil Ltd. (25 percent) and Union Oil Company of Canada Limited (25 percent). Operations are programmed to continue to the end of 1984.

3-46 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since September 1982 R&D PROJECTS (Cont.)

At the pilot site, the Grosmont formation is a consolidated, highly porous dolomite of Devonian age. Project Cost: Unknown. HOP KERN RIVER COMMERCIAL DEVELOPMENT PROJECT - HOP Kern River Development Associates, Ltd. A project to product 6000 BPD of 14°API crude oil from a 255 acre site in Kern River Field, California. A recovery technology known as the Heavy Oil Process (HOP) willbe employed. The HOP technology has been licensed to the Project pursuant to a license agreement with Cornell Heavy Oil Process, Inc., who obtained rights to the HOP through its acquisition of Barber Heavy Oil Process, Inc., in June 1981. The process involves steam injected through boreholes drilled radially from the bottom of a large diameter shaft. The Project will consist of six HOP units, situated in three complexes, each of which will be capable of independent operations. The modular nature of the complexes will permit a phased construction and startup schedule, with construction of one complex beginning approximately 14 months after the construction start date of the preceding complex. Construction is scheduled to begin in 1984 with initial production beginning in 1986. The anticipated life of the Project is 13 years. Over $1.0 million was spent by Barber Heavy Oil to develop the project. A Demonstration Unit has been constructed on an additional 25 acres in the center of the Project site, and operations are scheduled to start in the summer of 1982. Major construction on the unit was initiated in April 1980, with the sinking of a seven-foot diameter shaft to the base of the oil sand to be produced. A 25-foot diameter cavern was then dug out so that eight horizontal wells could be drilled into the reservoir. Loan and price guarantees have been requested of the Synthetic Fuels Corporation for the project, which was selected for Phase II consideration under the SFC's Second Soliciation. Project Cost: Estimated at $15 million total INTERNATIONAL HYDROCARBON TAR SANDS PROJECT - International Hydrocarbons Inc. Tar sand recovery project located in Grand County north of Green River, Utah (T21S R16E). International Hydrocarbons has 600 acres of state land and 200 acres of fee land which provide a resource base of approximately 396 MMBBL recoverable oil. Thermal extraction with open pit mining will be applied to produce up to 60,000 BPD. Construction is scheduled to begin in late 1982. Although International Hydrocarbons was not selected to receive assistance from the SFC, the company is progressing on its own. Project Cost: $700,000 IPIATIK LAKE PROJECT - Petro-Canada, Alberta Energy Company This project is a multi-well exploration program operated by Petro-Canada under a farmout agreement with Alberta Energy Company. The project is located in a 195 section area of the North West Corner of the Primrose Bombing Range new Cold Lake, Alberta. Seventy-eght wells of a proposed 100 wells were drilled by the end of 1981. Heavy oil in place is estimated to be 1000 x lob cubic meters. A thermal recovery pilot two km north of this acreage started up in April 1982. Project Cost: Undetermined KENSYNTAR PROJECT - Kensyntar Partnership In May of 1981 the principals of Westken Petroleum formed the Kensyntar Partnership with the Pittston Petroleum Corporation and KSA Resources. Kensyntnr has acquired a 19,000 acre lease-hold in Edmonson County and is developing techniques for the recovery of the heavy oil or tar sands on this lease. Westken Petroleum Corporation acts as lease operator and technical advisor to the Kensyntar Partnership on this project. A one acre inverted seven spot pilot pattern was constructed in the summer and fall of 1981. Injection of steam was commenced in November of 1981 followed by steam plus air. Combustion initiated on February 4, 1981. Heavy oil production commenced in February of 1982. Nearly 1,000 barrels of oil were produced over a 56-day period. Assuming favorable recovery and economic data the Kensyntar Partnership plans to proceed with a 10,000 BPD commercial facility in Edmonson County. Loan and price guarantees have been requested from the Synfuels Corporation for the project, which is in Phase II consideration under the Synthetic Fuels Corporation's Second Solicitation. Project Cost: $200 minion $7 million invested through mid-1982

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-47 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

LETC '1'S-iS, Steam Drive - U.S. Deportment of Energy U.S. Department of Energy Tar Sand Program conducted by the Laramie (Wyoming) Energy Technology Center. Field experiments with in situ thermal recovery technologies terminated in January 1982, due to severe reduction in proposed FY 83 Tar Sand Program Budget. Field experiment site on Sohio Shale Oil Company fee property in Utah's Northwest Asphalt Ridge deposit west of Vernal, Utah, has been prepared for abandonment. Currently planned future tar sand oil recovery research will consist of laboratory experimentation. Continuation of environmental, upgrading, resource characterization and oil recovery research is underway. Included is a 3 year U.S.-Canada cooperative project on "steam-drive with additives." Project Cost: FY 83 funding is $500 thousand plus the cost of the U.S.-Canada cooperation. LINDBERGH STEAM PROJECT - Murphy Oil Company, Ltd. Experimental in situ recovery project located at 13-58-5 W4, Lindbergh, Alberta, Canada. The pilot produces from a 60 foot thick Lower Grand Rapids formation at a depth of 1600 feet. The pilot consists of one inverted seven spot pattern enclosing 20 acres. Each well has been steam stimulated and produced roughly 8 times. Steam drive from the center well was initiated in September 1980. Production rates from the seven-spot area have been encouraging to date. Oil gravity is 10 0 API and has a viscosity of 102,500 Cp at 70°F. Porosity is 33% and permeability is 2500 md. Separation of the water from the oil emulsion has been a severe problem since steam drive was started. A modification of the cleaning plant to improve the water removal will be completed December 15, 1982. Project Cost: $2 million to date LINDBERGH THERMAL PROJECT - Dome Petroleum Limited Dome Petroleum Limited has completed a 56 well drilling program in section 18-55-5 W4M in the Lindbergh field in order to evaluate an enriched air and air injection fire flood scheme. The project consists of nine, thirty-acre, inverted seven spot patterns to evaluate the combination thermal drive process. The enriched air scheme involves three, ten-acre patterns. Currently 95% of the battery facilities are completed. Air is currently being injected into one pattern to facilitate sufficient burn volume around the wellbore prior to switching over to enriched air injection in July 1982. The surroundin production wells have shown some response to the fire flood scheme resulting in average well rates of 10.0 m 4/D/well versus 6.0 m 3/D/well under primary production. Project Cost: $22 million LLOYDMINSTER FIREFLOOD - Murphy Oil Company, Ltd. An experimental wet in situ fireflood project located in the Lloydminister area, Silverdale (Sparky Pool Formation), Saskatchewan, Canada, was operated from August of 1973 until May of 1980. The pilot consisted of a nine spot pattern enclosing 40 acres. The drive system appeared technically successful. However, severe operating problems associated with the production wells resulted in unfavorable economics. The pilot is now suspended. Project Cost: Initial capital investment approximately $1 million MARGUERITE LAKE PHASE A PILOT - BP Canada, Hudson's Bay Oil & Gas, and PanCanadian Petroleum BP Canada, Hudson's Bay Oil and Gas, and PanCanadian Petroleum entered into arrangements in 1977 whereby Hudson's Bay and PanCanadian joined BP in a pilot in situ project to produce 900 BPD bitumen from the Cold Lake heavy oil deposit of northeastern Alberta. The project, which is to last until 1985, involves the use of steam and combustion for bitumen recovery and is located at 7-66-115-W4M. It is funded 50 percent by the Alberta Oil Sands Technology and Research Authority and the remaining project costs are shared in the following manner: BP Canada (20 percent), Hudson's Bay Oil and Gas (17 1/2 percent), PanCanadian Petroleum (12 1/2 percent). HBOG and PCP have the right to purchase from BP their respective percentage interest in the 75,000 acre block of leases now wholly owned by BP on which the pilot plant is located. The project utilizes cyclic steam stimulation followed by in situ combustion in the Mannville "C" zone at a depth of about 500 metres. The pilot initially consisted of four 5- spot well patterns with 5-acres per well spacing, plus four "out-of-pattern" test wells. Five infill wells were drilled in 1981. Initial steam injection (Phase A) commenced in mid-1978 and will continue through mid-1980's. Preliminary testing of the in situ combustion stage began in several special test wells located immediately adjacent to the main pilot wells. Recently the partners agreed to test oxygen injection in addition to the current air injection combustion test. Project Cost: $44 million

3-48 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

MEOTA STEAM DRIVE PROJECT - Texas Gulf, Inc., Total Petroleum, Saskatchewan Oil and Gas Corporation. The project is located approximately 20 miles northwest of North Battleford and started in 1974 with one well. Nine oil production/steam injection wells on 2.5 acre spacing have been drilled and subjected to cyclic steam stimulation between 1974 and 1980. The nine-spot was converted to an o pen pattern steamdrive in late 1980 and has been under

Project Cost: The Saskatchewan and Canada (Federal) Governments contributed $1.5 million in funding assistance during 1977 and 1978. MINE ASSISTED IN-SITU PROJECT - Husky Oil Operations, Ltd., Esso Resources Canada, Ltd., Gulf Canada Resources, Inc., Canada-Cities Service, Ltd., and Petro-Canada Work has been completed on the Mine Assisted In Situ Project located in section 34-92-10 W4M of the Mildred Lake Area. The project consisted of three horizontal wells, 8 m apart which were drilled and completed to a total length of 310 m. The steam injection phase began in December 1979. The experimental plant which ran for a period of one year has been shut down and site reclamation begun. Evaluation is complete and the project was highly successful. Preliminary preparations are underway for a 2nd phase feasibility study which would involve 2 shafts and 16 horizontal wells. Project Cost: $s million (Cdn.) MORGAN COMBINATION THERMAL DRIVE PROJECT - Dome Petroleum Company Dome Petroleum Limited has completed a 44 well drilling program in Section 35-51-4 W4M in the Morgan field in order to evaluate a combination thermal drive process. The project consists of nine, thirty-acre seven spot patterns. Currently, 40 wells have been steam stimulated. The average peak rate is approximately 25 m 3/d/well compared to 7 m 3/d/well under primary production. The steam-air injection and battery facilities are in place. Plans are to ignite one pattern using air in June 1982 Project Cost: $20 million MRL SOLVENT PROCESS - C & A Companies, Minerals Research Ltd. C & A Companies has proposed a 20,000 BPD tar sands facility on private land in the PR Springs Deposit, Brand County, Utah. The project will employ surface mining and the Mineral Research Limited solvent extraction process. Minerals Research Ltd. has concluded the laboratory development and Pilot Plant testing phase for their Solvent Process for recovering Bitumen from Tar Sands. The design for construction and operation of a 200 BPD module to evaluate the process under field conditions and actual production has been completed. Phase I includes a 200 BPD commercial demonstration plant which will be on-line mid-summer 1983. The 20,000 BPD production facility, Phase U, would begin construction a year later with completion in four years. The 20,000 BPD plant would be constructed in five steps of 4,000 BPD each. C & A is requesting loan guarantees from the SFC for the commercial project. Project Cost: Unknown NATOMAS SOLVENT EXTRACTION PROCESS - Natomas Company Natomas Energy Company received a grant from the Department of Energy to study the "Feasibility of Natomas Process For Extraction of Bitumen From Domestic Tar Sands." DOE would contribute $363,594 towards the expected total project cost of $450,000. The feasibility study, which was completed in October 1981, indicates that Natomas Company's patented process to extract oil from tar sands is both technically feasible and economically viable. Further evaluation of the study results is under review, with a 20,000 BPD commercial facility still a viable objective by 1990-1992. Kaiser Engineers, Camp Dresser & McKee, and SRI were participants in the study.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-49 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

NORTH KINSELLA HEAVY OIL - Petro-Canada & AOSTRA Heavy oil teritary recovery experiment conducted in the North Kinsella field, in Alberta Canada. The experiment is underway and features the contrasting of two recovery methods; (1) a steam-driven mobilization, and (2) an in situ combustion method. Twelve wells have been drilled for each scheme. Pilot plant construction was completed in October 1979. The steamflood, which began operating in June 1981, was suspended in December 1981. Operations continue in the combustion pilot. Project Cost: $17.7 million PCEJ PROJECTS - Petro-Canada, Canada-Cities Servine Ltd. and Esso Resources Canada, Ltd., Japan Canada Oil Sands, Ltd. Project is designed to investigate the extraction of bitumen from Athabasca Oil Sands using an in situ recovery technique consisting of electric preheat process followed by more conventional steam flood recovery mode. Site is located at Stoney Mountain, some 35 km south of Fort McMurray. The plant is presently in operation. Twelve wells were drilled, consisting of four electrode wells and eight observation wells. Electric current was connected by April 1981. The steam flood phase commenced in early 1982. A three phase 15 year farmout agreement has been executed with Japan Canada Oil Sands, whereby Japan Canada Oil Sands could earn an undivided 25 percent in 34 leases covering 1.2 million acres in the in situ portion of the Athabasca Oil Sands by contributing a minimum of $75 million. Japan Canada Oil Sands has completed its interest earning obligation for Phase I by contributing $30.8 million. At a different site, the PCEJ group is investigating vertical well steam stimulation where the steam is injected at a pressure high enough to fracture the formation. Project Cost: Undetermined. PEACE RIVER IN SITU PILOT PROJECT - Shell Canada Resources, Ltd./AOSTRA, Amoco Canada Petroleum Co., Ltd, Shell Explorer, Ltd. Experimental in situ recovery project located about 20 miles northeast of Peace River, Alberta. Project consists of 7 seven-acre 7-spot patterns producing a peak of 3,500 BPD bitumen. Field site preparation commenced October 1977. Phase A covering engineering design, procurement and construction was a fixed $58 million. Phases B and C provide for five and four years of operation respectively, which could bring total cost to $170 million. Cost of the project being shared 50 percent by Alberta Oil Sands Technology and Research Authority (AOSTRA) and 18.75 percent each by Shell Canada Resources, Ltd. and Shell Explorer Ltd. and 12.5 percent by Amoco Canada Ltd. Construction and drilling completed October 1979 with Phase B operations now in progress. Project Cost: Phase A cost $58 million (complete) Phase B cost currently estimated at $65.7 million. PELICAN-WABASCA PROJECT - Gulf Canada Resources, Inc. Construction of fireflood and steamflood pilot facilities is underway in the Pelican area of the Wabasca region. Phase I of the project commenced operations in August 1981, and Phase 11 (fireflood) will commence operations by mid-1982. The pilot, when completed, will consist of a 31 well centrally enclosed 7 spot pattern plus nine additional wells. Both steam stimulation and fireflood processes will be tested. Project Cost: Not Specified PRIMROSE PROJECT - Noreen Energy Resources Ltd. & Japan Oil Sands Co. Noreen is the operator of an experimental in situ project located 25 miles north of Cold Lake, Alberta, Canada. Delineation drilling was completed in the spring of 1975 on lease No. 60. Drilling of production-injection wells for the pilot project was completed in the fall of 1975, with construction of facilities essentially completed in September of 1976. Steam injection operations have proceeded continuously since that date. Project Cost: The agreement with JOSCO stipulates that they must expend 75 percent of $15 million in order to obtain a 50 percent working interest in the lease. To date, expenditures have reached the committed amount. The project, under the current financial arrangements, terminated in October 1981.

3-50 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

PRIMROSE - KIRBY PROJECT - Petio-Canada This land includes 40 sections under 100% Petro-Canada PN&G licenses. Based on 14 exploration wells completed to April 1981, a significant volume of bitumen has been identified. A field steam stimulation test pilot, with eight injection-production wells and four observation wells, is being developed as a follow up to an encouraging single well steam stimulation-oil production test. Steam injection began in April 1982. Project Cost: Unknown RESDELN PROJECT - Gulf Canada Resources Inc. The Resdein Project, located approximately 60 miles South of Fort McMurray, comprises six wells which are undergoing steam stimulation. This project is totally sponsored by GCRI and is intended to evaluate the producing characteristics of the McMurray formation. Production operations commenced in early 1981. The Project will close June 30, 1982 as a result of damage from a fire April 2. This closing is two months earlier than previously planned. Project Cost: $4.2 million (Cdn.) R.F. HEATING PROJECT - LIT Research Institute, U.S. Department of Energy, Haliburton Services The Illinois Institute of Technology Research Institute of Chicago (11TRI) has completed a 27 month cooperative program which included field tests of the radio frequency process in oil shales and tar sands along with supporting laboratory and analytical studies. Technology development has been funded by ITTRI, the U.S. Department of Energy ($3.6 million) and by Halliburton Services ($1.4 million). The process was further tested during 1981 at the Asphalt Ridge tar sands deposit near Vernal, Utah. A 25 m3 block of oil sands containing about 24 BBL of oil was heated using the RF process to between 400 and 485°F in a 20 day test. About 8 BBL of tar were produced for a 30 to 35% recovery. IITRI now seeks industry backing to fund another three to five years of research. The RF process has been under development since 1976. Project Cost: $6.0 million total program funning to date. RIO VERDE ENERGY CO. PROJECT - In Situ Combustion Rio Verde Energy holds 160,000 acres of Kentucky oil sands leases. The company is presently exploring joint venture possibilities with other firms to develop these leases. RTR PILOT PROJECT - RTR Oil Sands (Alberta) Ltd. The Oil Sands Extraction pilot project is situated on the Suncor, Inc. property, north of Fort McMurray, Alberta. The pilot plant was operating in cooperation with Gulf Canada Resouces Inc., during the second half of 1981. Data from the operation will be evaluated during the first half of 1982. Project Cost: Undisclosed SANDALTA-Home Oil Company, Ltd., Alminex, Ltd., Gulf Canada Resources, Inc. Home Oil Company Limited, in October 1979, announced the farmout of its Athabasca oil sands property to Gulf Canada Resources, Inc. The property, Oil Sands Lease #0980090001 (formerly BSL #30) consists of 15,086 hectares (37,715 acres), situated 43 kilometers (26 miles) north of Fort McMurray on the east side of the Athabasca River. Under terms of the farmout agreement, Gulf, through expenditures totalling some $42 million, can earn up to an 83.75 percent interest in the lease with Home retaining 10 percent and Alimex Ltd. 6.25 percent. An exploratory drilling program was carried out in the 1980 and 1981 drilling seasons, and evaluation of the results will be continued in 1982. A decision to proceed with commercial development will not be made until 1986. Project Cost: Gulf Canada Resources, Inc. only $42 million. SANTA FE TAR SAND PROJECT - Santa Fe Energy Company Santa Fe has proposed a 2 year pilot project in Wayne County, Utah. In situ combustion would be tested on the Tar Sands Triangle Deposit, Gorden Flats Unit (T30S R16E). A feasibility study is underway. Santa Fe has also acquired

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-51 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

34,000 acres of oil and gas leases in the vicinity. A decision to proceed has been pending, awaiting the resolution of some leasing and environmental uncertainties. Project Cost: Unknown SANTA ROSA OIL SANDS PROJECT - Solv-Ex Corporation, Foster Wheeler Synfuels Cor A project to recover 4,000 BPSD of oil from a deposit in Santa Rosa, New Mexico. A small open-pit mine will provide 13,000 TPD of ore to the extraction plant, which will employ a proprietary solvent extraction technology. Solv-Ex has operated a 25 BPD capacity test plant at their Albuquerque laboratory. For Stage I of the project, additional facilities for full recycle solvent and recycle water operation will be added. It will be operated for three months. Stage II is construction of a 4,000 BPD plant. Stage Ill will be start up of plant to reach design capacity and Stage IV is the operation at capacity. Price and loan guarantees were received from the SFC on December 2, 1982. Foster Wheeler Svnfuels Corooration are eauitv nartners with Solv-Ex throu gh this oroiect. Stage 1: $ 3 million Stage II: $18.5 million Stage Ill: $ 2.5 million operating capital SUFFIELD HEAVY OIL PILOT - (SHOP) - Alberta Energy Company Ltd., AOSTRA, Westcoast Petroleum Ltd., Dome Petroleum Limited An in situ combustion project located in southeastern Albeçta within the Suffield Military Range and operated by Alberta Energy Company. Phase A of the project consists of one isolated five-spot pattern. The reservoir is a Glauconitic sand in the Upper Mannville formation which is underlain by water. The wells, including three temperature observation wells, were drilled during the summer of 1980. Completion of facilities construction occurred in the fall of 1981 and injection started in early 1982. Phase A is expected to continue for four years. AOSTRA holds a 50 percent interest in the project, Alberta Energy Company holds a 25 percent interest and Dome Petroleum and Westcoast Petroleum each hold a 12.5 percent interest. Project Cost: $11 million (Cdn) SUNNYSEDE PROJECT - Great National Corporation, University of Utah, Standard Oil Co. of California A 240 TPD tar sands pilot employs ambient water flotation concentration followed by solvent extraction (developed by the University of Utah). Start-up 'was in March 1982. The company has 2,000 acres in the Sunnyside deposit of Utah. Cleaning or coking will be done either by Englehard or Airco fluidized-bed technology, and Chevron's proprietary hydrotreating technology will be employed. The company has contracted Foster Wheeler and Morrison- Knudsen for upgrading and mining. Great National plans to scale up its processto 34,000 BPD by 1985 at its Sunnyside Utah property at a cost of $720 million. Price guarantees for the commercial project has been requested of the Synthetic Fuels Corporation for the project, which was selected for Phase II consideration under the SFC's second solicitation. Project Cost: $1 billion for ultimate 40,000 BPD facility SUNNYSIDE PROJECT - Standard Oil Company of Indiana (Amoco) Standard is conducting a feasibility study for a commercial project in the Sunnyside deposit in Carbon County, Utah. Various extraction technologies are being studied. Coring is now being done to determine the extent of the resource. The water supply is under study and data for environmental purposes is also .being collected. The feasibility study is slated for completion in 1983. The study is totally funded by Standard. Project Cost: Undisclosed SURMONT PROJECT - Gulf Canada Resources, Inc., AOSTRA The first phase of the feasibility studies for the project have been completed and the implications of the study are under review by the two participants, Gulf Canada Re&ources Inc., and the Alberta Oil Sands Technology and Research Authority (AOSTRA). The feasibility study assessed the technical, economic and environmental feasibility of recovering bitumen from oil sand formations with a system of horizontal wells utilizing in situ steam methods. Two methods of access to the formation were considered; the drilling of wells from the surface which would be deviated to the horizontal plane and the drilling of wells from tunnels placed above, within or below the pay zone. Both methods of horizontal wells were deemed to be feasible.

3-52 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline denotes changes since June 1982) R&D PROJECTS (Cont.)

Project Cost: $130 million total (Cdn) TACIUK PROCESSOR PILOT - The UMA Group Ltd./AOSTRA A pilot of an extraction and partial upgrading process located in Southeast Calgary, Alberta. The pilot plant finished construction in March of 1978 at a cost of $1 million, and has been in operation since. The process was invented by William Taciuk of The UMA Group. Development is being done by UMATAC Industrial Processes Ltd., a subsidiary of The UMA Group. Funding is by the Alberta Oil Sands Technology and Research Authority (AOSTRA). The processor consists of a rotating kiln which houses heat exchange, cracking and combustion processes. The processor yields cracked bitumen vapors and dry sand tailings. Over 2400 tons of Athabasca oil sand have been processed. Performance information has been compiled and a study on comparative economics has been completed. A non confidential information release has been prepared and made available to prospective participants in the development of the process. Information agreements have been made with a major oil company and joint venture company between two majors. The information agreements provide, in exchange for a funding contribution to the project, full rights for evaluation purposes to the information generated by the project. Further pilot work planned for 1982 will evaluate modifications now being made to improve coke burning characteristics and to demonstrate extended operation in runs spanning several days. Project Cost: $2.4 million (AOSTRA) TAR SAND TRIANGLE - Kirkwood Oil and Gas Kirkwood Oil and Gas drilled some fifteen coreholes by the end of 1981 to evaluate their leases in the Tar Sand Triangle in south central Utah. They are also evaluating pilot testing of inductive heating for recovery of bitumen. Additional holes are being drilled to maintain the unit and to further evaluate the area. Project Cost: Unknown TARCO TAR SANDS PROJECT - Tarco, Inc. A 250 BPI) synthetic crude from tar sand plant located near Homer in Logan County, Kentucky. The plant began operating in 1981 and produced some oil before mechanical difficulties and winter weather forced it to shut-down in November. Tarco plans to scale up the project to 5,000 BPD with construction resuming in spring 1982. The company is also negotiating to test the extraction process at a 1600 BPD pilot in Utah. The mobile plant facility is gas fired. Hexane extraction technology is being tested. Project Cost: Undisclosed TEXACO ATHABASCA PILOT - Texaco Canada Resources Ltd. Texaco Canada Resources Ltd. is continuing to operate the experimental in situ recovery project located within Section 15-88-8 W4M on the Bituminous Sand Lease No. 81 in the Athabasca Oil Sands in Alberta, Canada. Construction was started in 1972, and initial recovery operations commenced in 1973 with thirty-four wells on a 10- acre pattern. Steam flooding and low temperature oxidation with steam flooding were tested between 1973 and 1978, and more recently, caustic flooding was also tested. Eighteen new wells were drilled in 1975 on a second (Pattern II), 3.75 acre, inverted, 7-spot pattern, and expansion of surface facilities was completed in 1976. Steam and light hydrocarbon flooding with pressure cycles was tested extensively on Pattern II. The remedial workover of the central injection well in Pattern II was successful and alternate recovery methods are being considered. During the winter of 1980-1981, a third pattern (Pattern III) consisting of three horizontal wells was drilled. The first and third wells have received remedial workovers and are now awaiting the completion on tests on sand control technology which has been developed for horizontal wells. The second well is undergoing steam injection. Construction of a second horizontal well pilot at Steepbank Bituminous Sand Lease No. 49, approximately 40 miles north of the existing pilot, has been delayed awaiting the development and testing of downhole horizontal well sand control equipment, and new produced bitumen-water separation and heat scavenging technology. ULTRA SONIC WAVE EXTRACTION - Western Tar Sands Inc. A 30 BPD pilot plant located on a 640-acre site at Raven Ridge in Uintah County, Utah. Open pit mining, crushing and surface extraction will be employed. The facility will use solvent, condensed natural gas, or a paraffinic fluid, enhanced by ultrasonic vibration for extraction. Tracor, Inc. will build and operate the pilot plant. Science Applications, Inc. is responsible for design and engineering. The company had a ground-breaking ceremony for the

SYNTHETIC FUELS REPORT, DECEMBER 1982 3-53 STATUS OF SYNPUELS PROJECTS (Underline denotes changes since June 1982)

R&D PROJECTS (Cont.)

project in March 1981, but construction has been delayed by lack of funds. Western is negotiating with other companies to form a consortium. Construction could begin in September with initial production in August 1983. Corkhill Drilling, Inc. was engaged by Western to drill 14 holes to an average depth of 100 feet to determine the extent of tar sand resources on the site location. Project Cost: $2.0 million "200" SAND STEAMFLOOD DEMONSTRATION PROJECT - Santa Fe Energy Company, U.S. Department Energy. This is a jointly-funded steamflood project in the Midway-Sunset Field of Kern County, California. The reservoir contains approximately 50 million barrels of oil-in-place between 400 and 700 feet deep. The project consists of five phases: Pilot site monitoring and evaluation; Pilot area expansion; Site selection for full-scale project; Expansion to full-scale steamflood, and a Production monitoring phase. The project is currently in its fourth year. The pilot evaluation report was prepared during 1979 and a decision was made to go to an expanded program of fourteen patterns with drilling anticipated to start in April 1980. Current expenditures on the project total $4,927,696. Injection rates for the pilot project averaged 450 B/D/well with production from the ten pilot producers averaging 136 B/D/oil and 276 B/D/ water for 1979. The project has indicated that it is rate sensitive. Expansion to a full scale steamflood was started in April 1980. Currently, 21 wells have been drilled. Steam injection and production facilities are being constructed. The expansion was to have been completed in June 1981. Project Cost: Total cost $8.25 million

3_54 SYNTHETIC FUELS REPORT, DECEMBER 1982 RECENT OIL SANDS PUBLICATIONS

Adams, D. M., "Experiences With Waterflooding Lloydminister Heavy Oil Reservoirs," Journal of Petroleum Technology, August 1982. Berry, Holland J., Husky Oil Operations Ltd., Calgary, Alberta, "Heavy Oil Community Relations - The Husky Experience," Journal of Canadian Petroleum Technology, Vol. 21, No. 13, May-June 1982. *Dike, David H., (Ground Water Technology, Inc., Chadds Ford, PA), Barry S. Resnick, and Randall D. Metz, (Ketron, Inc., Wayne, PA), "Prospects for Commercial Tar Sand Development: An Appraisal of the Institutional, Technical, and Economic Factors that Affect Decisionmaking." Doscher, Todd M., at a!, "Steam Drive Definition and Enhancement," Journal of Petroleum Technology, July 1982. Doscher, Todd M., et al, University of Southern California, "The Anticipated Effect of Diurnal Injection On Steamdrive Efficiency," Journal of Petroleum Technology, August 1982. Ekinci, E., Professor, University of Newcastle, S. Turkey; Professor, Instanbul Technical University, "The Development of Synthetic Fuels from Turkish Asphaltites," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. • ENERCOR, "Rainbow Tar Sand Project," Project Description Technical Report, June 28, 1982. Garon, Allan M., at al, Gulf Research & Development Co., "Scaied Model Experiments of Fireflooding in Tar Sands," Journal of Petroleum Technology, September 1982. flertzberg, Richard H., Fereidun Hojabri, Joseph P. Kearney, and Larry LI. Ellefson, "Tar Sands Development By ENPEX," 17th IECEC. Hutchinson, H. L., J. H. Kennedy, L.A. Johnson, Jr., and D.W. Fauset!, "Simulation of the LETC/DOE TS-IS Steam Drive Experiment," presented at the 57th Annual Fall Technical Conference and Exhibition of the SPE of AIME, New Orleans, LA., September 26-29, 2981. Isaacs, E. Eddy, Daniel R. Prowse and Joseph P. Rankin, Alberta Research Council, "The Role of Surfactant Additives In the In-Situ Recovery of Bitumen From Oil Sands," Journal of Canadian Petroleum Technology, Vol 21, No. 13, May-June 1982. MeRory, Robert E., Alberta Energy and Natural Resources, "Energy Heritage: Oi Sands and Heavy Oils of Alberta," 1982 Mono Power Co. and Enercor, "Uintah Basin EIS Conceptual P.R. Spring Tar Sand Recovery Project Description." Moughamian, J. M., at al, "Simulation and Design of Steam Drive In a Vertical Reservoir," Journal of Petroleum Technology, July 1982. Schumacher, M.M., "Heavy Oil and Tar Sands Recovery and Upgrading: International Technology," Energy Technology Review No. 78. Smith-Magowan, Arne Skauge and Loren G. Hepier, "Specific Heats of Athabasca Oil Sands and Components," Journal of Canadian Petroleum Technology, Vol 21, No. 13, May-June 1982. Tiab, Ojebbar, at al, University of Oklahoma, "Caustic Steam Flooding," Journal of Petroleum Technology, August 1982. Vonde, Thomas R., Husky Oil Co., "Specialized Pumping Techniques Applied To A Very Low-Gravity, Sand-Caden Crude- Cat Canyon Field, California," Journal of Petroleum Technology, September 1982.

*Reviewed in this issue.

SYNTHETIC FUELS REPORT, DECEMBER 1982 3_55

PROJECT ACTIVITIES

STATUS OF COAL PROJECTS APPLYING TO THE liquid and gaseous products. Details of the project can be SPC FOR ASSISTANCE found in the June 1982 Pace Synthetic Fuels Report beginning on page 4-1. Bechtel Petroleum, Inc., was the As described on page 4-6 of the September 1982 Pace only other equity partner in the project, but other poten- Synthetic FuelsReport, six coal conversion projects tial sponsors rumored to be interested in the project that applied to the U.S. Synthetic Fuels Corporation include Airco, Ruhrkohle, and the Commonwealth of (SFC) have been involved in detailed discussions to Kentucky. determine the types and amounts of support. Of these six projects, one has made significant progress toward Ashland and Bechtel applied to the Synthetic Fuels Cor- receiving aid, two are continuing negotiations with the poration (SFC) for financial assistance under the SFC's SEC, one has been asked to reapply to the SFC's third first solicitation. The project had passed the SFC's solicitation, and two have been cancelled or postponed project maturity and strength tests and the partners were by the sponsors of the projects. A description of recent negotiating with the SEC concerning the types and SFC actions is included in the General Section of this amounts of assistance needed by the project. issue of the Pace Synthetic Fuels Report. A brief summary of the status of the six coal conversion The pilot plant at Ashland's Catlettsburg refinery success- projects is as follows: fully demonstrated the H-Coal technology. However, the decision to withdraw from the project was based on • First Colony peat-to-methanol project - uncertainty about future oil prices, the large investment transferred from the SFC's first solicitation to required for the project, exposure to possible cost over- the second; negotiations have now progressed to runs, and recent tax-law changes that reduced potential the point where the SEc is considering signing a tax benefits. letter of intent The SEC responded to Ashland's announcement with the • Cool Water coal gasification combined cycle following statement: project - negotiations proceeding as a result of an application under the SEC's second solicita- "The United States Synthetic Fuels Corporation tion regrets but understands the decision by Ashland to suspend its Breckinridge project in Kentucky. The • North Alabama coal-to-methanol project - Corporation regrets the decision because it recognizes negotiations proceeding as a result of an applica- that more than eleven years have been invested in the tion under the SFC's second solicitation project developing the technology to the point where commercial scale construction could seriously be con- • New England Energy Park coal-to-electricity sidered. The decision also highlights the importance (and methanol or SNG) project - applied under of a strong, stable federal program of limited assis- the second solicitation and encouraged by the tance to share the risks associated with projects with SFC to reapply under the third solicitation end- the size and lead-time of Breckinridge..... ing January 10, 1983 "Recognizing the types of risks associated with the • Hampshire Energy coal-to-gasoline project - private development of a totally new commercial applied to the SFC under the first solicitation, scale industry, the Corporation has steadfastly but postponed by the project sponsors attempted to strengthen the projects seeking assistance, thereby minimizing the risks to the private • Breckinridge direct coal liquefaction project - sector and the taxpayers. applied to the SFC under the first solicitation, but cancelled by the project sponsors. "The suspension of the Breckinridge project demon- strates that, even with maximum federal assistance, A brief discussion of these two postponed/cancelled which is limited under the Energy Security Act, the projects is presented in the following articles. current oil market and other economic conditions dictate serious problems for projects as large as Breckinridge." ASHLAND WITHDRAWS FROM THE BRECKINRIDGE PROJECT HAMPSHIRE ENERGY PROJECT POSTPONED On November 22, 1982, Ashland Oil Inc. announced it was withdrawing from the Breckinridge Project in On December 8, 1982, the sponsors of the Hampshire Kentucky. The proposed plant was to use the H-Coal Energy Project near Gillette, Wyoming, announced they a process to convert 9000 TPD of coal into a slate of were delaying the start of construction on the project.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-1 The primary reason given for the decision was the in- the proposal to the SFC eventually became public know- ability to attract additional equity sponsors to the ledge. In the proposal, the projected range of gasoline project. A replacement was needed for the Standard prices (1982 $ per gallon) from the plant were $0.76 to Oil Company of Ohio (Sohio) . which withdrew from the $1.14 in 1985, $0.77 to $1.55 in 1990, $0.85 to $1.79 in project on October 19, 1982. The remaining four 1995, and $0.92 to $2.08 in 2000. The gasoline was to be sponsors (Northwestern Mutual Life Insurance, Metro- primarily marketed in the northeast Wyoming area near politan Life Insurance Company, Hoppers Company, and the plant and in Denver. Total cost of the plant, as l{aneb Services) expressed their commitment to the itemized in Table 1, was approximately $2 billion. Annual project and hope to reactivate it in the future. operating costs shown in Table 2 were estimated to be approximately $115,000,000. Based on assumptions that Prior to the announcement, the project had made the real interest rate would be 6%, the tax rate would be several significant advancements toward construction. 46%, and a debt/equity ratio of 75:25, the project was The project had passed the U.S. Synthetic Fuels Cor- expected to yield a 7.8% real rate of return. poration's (SFC) project maturity and strength tests. Hampshire was the only project still under consideration from the SFC's first solicitation after the Breckin- TABLE 2 ridge Project was cancelled by Ashland and after three other projects were transferred to the SFC's second and HAMPSHIRE ENERGY PROJECT third solicitations. On December 2, 1982, the SFC ANNUAL OPERATING COSTS agreed to continue negotiations with the Hampshire Energy project until April 1983. (4th Quarter 1981 Dollars) Another project milestone occurred when two of the Operating and Maintenance $ 72,267,000 sponsors, Kaneb (through a subsidiary, Texas Energy) Material and Labor and Northwestern Mutual Life, successfully bid on a large tract of Federal coal near the plant site. The Catalysts, Chemicals, Royalties & 26,295,000 sponsors' original bid for the Rocky Butte Tract that Ash Disposal was submitted in the Powder River lease sale on April 28, 1982, was rejected by the Mineral Management Property Tax & Insurance 16,460,000 Service as being too low. However, when the tract was reoffered on October 15, 1982, the sponsors approxi- TOTAL OPERATING $115,022,000 mately doubled their bid to $22.3 million and were awarded the tract. The project also secured its needed water supply in August 1982 when the Wyoming State Engineer issued a permit allowing 15 wells to be drilled In responding to the announcement by the sponsors that to supply 4608 acre-feet of water per year. the project was being postponed, the SFC stated: Lastly, on November 20, 1982, the project received "The sponsors have made significant progress toward unanimous, conditional approval from the Wyoming obtaining environmental permits and reaching agree- Siting Council for a permit to build the plant. The ments with the affected communities. They have conditional approval followed a 15-day "megahearing" achieved an advanced technological design. The pro- - during which the Council received testimony concerning ject's inability to attract additional equity partners at the project technology, product marketing plans, en- this time, however, remains. Over the past months, vironmental impact, funding, and socioeconomic we have worked closely with the sponsors and have impact. At the conclusion of the hearing, the Siting expressed our willingness to continue working with Council agreed to issue the permit if the Hampshire them. sponsors agreed to certain conditions in the permit. These conditions were to be determined after the "The advanced state of this pioneer project and its Council reviewed the testimony from the hearing and ability to overcome the initial obstacles should stand evaluated written comments from interested parties. as an indication that, even with an emerging industry, the serious environmental, technical and permitting The original plant design involved gasification of questions can be addressed responsibly." approximately 15,000 TPD of Wyoming sub-bituminous coal in 14 Lurgi gasifiers and 3 KEW gasifiers. The synthesis gas was to be treated and converted to methanol with subsequent conversion to unleaded ACTIVITIES AT SASOL ONE, TWO, AND THREE gasoline by the Mobil-M process. Finished products from the plant were to include approximately 19,377 In its annual report, Sasol Limited summarized the status BPD of gasoline, 914 BPD of propane LPG, 1618 BPD of of the various Sasol projects and briefly discussed future mixed butanes, 87 TPD of ammonia, 47 TPD of sulfur, plans. Additional details of the proposed construction and and 216 MM SCFD of carbon dioxide. A more complete testing of a Westinghouse gasifier at Sasol were presented description of the process can be found on pages 4-1 to by Louis A. Salvador at the Ninth Annual Conference on 4-3 of the December 1981 issue of the Pace Synthetic Coal Gasification, Liquefaction, and Conversion to Elec- Fuels Report. tricity. The following article is a combination of information from both sources. Although the economic data concerning the plant was considered to be proprietary, some information from

4-2 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE I HAMPSHIRE ENERGY PROJECT COSTS (4th Quarter 1931 Dollars) DIRECT FIELD COSTS:

Lurgi Gasifiers $ 66,920 ,000 Shift Conversion 18,765,000 Gas Cooling 9,637,000 Phenosolvan 9,032,000 Gas Liquor Separation 24,358,000 Ammonia Recovery 8,900,000 KBW Gasification 112,342,000 Air Separation Plant 163,237,000 Heavy Oil Partial Oxidation 11,435,000 / Rectisol 95,697,000 Sulfur Recovery System 6,917,000 Methanol Synthesis 77,423,000 Naphtha Hydrotreater 3,427,000 LPG Drying 489,000 Raw Water Treating 13,712,000 Steam & Condensate System 18,202,000 Coal Preparation 65,350,000 Ash Handling 26,277,000 Product Storage 31,489,000 Gasoline Blending 979,000 Effluent Water Treating 24,621,000 Power Generation 43,072,000 Fuel Gas System 9,153,000 Fire Water System 1,440,000 Plant & Instrument Air 3,640,000 Utility Cooling Water 28,432,000 Process Cooling Water 23, 120,000 Flare System 4,733,000 Interconnecting Facilities 138,939,000 Mobil MTG 46,260,000 Distillation 5,487,000 H.F. Alkylation 5,833,000 Heavy Gasoline Treater 5,308,000 Product Shipping 1,907,000 Bulk Chemical Handling 551,000 Site Preparation 60,690,000 Buildings 25,822,000 TOTAL DIRECTS $ 1,193,596,000 INDIRECT COSTS

Indirect Field Costs $ 269,783,000 Construction Community 89,977,000 Engineering Office Costs 206,600,000 Sales Tax 30,000,000

TOTAL INDIRECTS $ 596,360,000 OTHER PROJECT COSTS

Owners Costs $ 212,880,000 Start-up and Training Costs 74,100,000 Working Capital 18.760,000

TOTAL OTHER $ 305,740,000

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-3 Sasol History. duced in early 1982 and the first liquid fuels were produced in mid-1982. Full production is not expected In the early 1950's, a government-controlled company until 1984/85. Efforts continue to recruit and train a was formed in South Africa to build the first plant staff to operate and maintain the plant. located in Sasolburg to produce oil from coal. This plant, Sasol One, began production in 1955 and became Technology profitable in 1959. The decision to construct a second plant, Sasol Two, was made in 1975 as the price for Sasol Limited continues to promote its oil-from-coal conventional crude oil began to increase rapidly. Sasol process to other nations. The process is depicted and Two, located in Secunda, was commissioned in 1980 at a explained in Figure 1 and a more complete description of final cost of approximately $3.0 billion (U.S.). In early the Synthol reactor can be found in the March 1981 issue 1979, the decision to construct Sasol Three at Secunda of the Cameron Synthetic Fuels Report on page 4-27. was made and in mid-1982 the plant began operation. Sasol also is acting as a consultant and co-licensor to the The estimated cost of Sasol Three is $3.8 billion (U.S.). Great Plains project at Beulah, North Dakota (USA). Fluor Corporation has conducted several studies of Also in 1979, Sasol Limited was incorporated as the marketing the Sasol technology in the United States and holding company for the Sasol group. The South other nations. African government retained 30% of the stock of the company and the remaining 70% was sold to the public. Research continues to be conducted at Sasolburg to Sasol One is controlled 100% by Sasol Limited. Sasol develop a direct coal liquefaction process. A 50 TPD Two and Three are owned 50% by Sasol Limited and demonstration unit using the process has been proposed by 50% by the government. The structure of Sasol Limited a consortium of Japanese businesses for construction in is described more completely beginning on page 4-27 of Victoria, Australia. Sasol will not contribute funding for the September 1981 Cameron Synthetic Fuels Report. the project, but will receive licensing fees if commercial units are built using the technology. During 1981, Sasol Limited decided that a fourth plant will not be contemplated before the second half of the A large pilot plant at Sasolburg is under construction to decade. It was decided that the Sasol organization develop Fischer Tropseh technology in a fixed bed reac- needs a "breather" after the construction of Sasol Two tor. The fixed bed process is expected to have certain and Three. Attention will be focused on rounding out advantages over the fluidized bed process used in the the two new plants. commercial Synthol reactors at Sasol. Sasol One Status and Plans The Mark V Lurgi gasifier is one element of Sasol's involvement in gasification research and development. A large number of experienced employees at Sasol One Additionally, tests using Lurgi gasifiers have been con- were transferred to Sasol Two and Three. Therefore, ducted with American coals; one test involving modifi- Sasol One has been attempting to restore operational cations to a gasifier to handle caking coals. Finally, Sasol competence by an accelerated training program. has undertaken the construction and testing of a commer- Recruiting within South Africa has been hampered by cial-scale Westinghouse gasifier. The gasifier can utilize limited availability of skilled manpower, but recruiting fine coal that cannot be fed to Lurgi gasifiers. Greater has been successful overseas. quantities of fines per ton of coal mined is expected as Sasol increasingly uses automated mining methods. In 1981, the experimental Mark V Lurgi gasifier was successfully commissioned. The gasifier, which is much Joint Westinghouse/Sasol Gasifier Testing larger than those at Sasol Two and Three, is expected to substantially reduce capital costs of the gasification Sasol Limited and Westinghouse Electric Corporation have plants when fully commercialized. jointly undertaken a project to design, construct, and operate a nominal 1200 metric-ton-per-day demonstration Much of the equipment at Sasol One is over 20 years unit at the Sasol Two complex. The project is designed to old. Therefore, attention will be focused on replacing demonstrate the viability of the Westinghouse pres- aging equipment. A new boiler and an oxygen pipeline surized, ash agglomerating, fluidized bed process (PAFB). between Sasolburg and Secunda were also started. A The commercial scale unit will operate in the slip-stream new pipeline for product gas was completed. mode utilizing the existing coal supply, wastewater treatment system, oxygen, and utilities at Sasol Two. Design Sasol Two Status of the unit began in 1982 and commissioning is scheduled for late 1984. The project schedule is shown in Figure 2. All production units at Sasol Two were put into operation during 1981. During 1982, efforts were concen- Responsibility for the project is divided between the two trated on achieving continuity of production. In partners, with Westinghouse providing all aspects of pro- October 1980, ethylene production was begun, thus ject management, design, procurement, and construction marking the first time South Africa had a coal-based of the gasification plant within a designated battery source of this important petrochemical feedstock. limits boundary. Sasol is responsible for integrating the unit into the Sasol Two complex. Both partners will Sasol Three Status supply personnel to conduct the tests during the demonstration and optimization phases of the program. Sasol The plant was completed in 1982 after reaching a peak will supply coal, oxygen, and utilities and will receive the construction workforce of 25,000. Gas was first pro- product gases from the unit. After the demonstra-

4-4 SYNTHETIC FUELS REPORT, DECEMBER 1982 ..inr0' s.øco. 1 h -: L.r"Ij,J :T.0T :1M

Gs.tcaton ... . ; :

Air 2 p.r.IIon O 9 ii t••I•dsfl On Sulphur (I lIquor r.cOv*ty PH Awase dq,o. oud I'yO,oq.. .ulo,uo. Du npr.tlqn Volt is Ur.t 0 I 11111 or 0 01 pool to 'pool

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FIGURE 1 THE SASOL SYNTHOL OIL—FROM—COAL PROCESS

SYNTHETIC FUELS REPORT, DECEMBER 1982 PHASE 1fl2 '$13 I$I4 IllS Ill' I'll I'll

Deur Nfli%

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FIGURE 2 ADVANCED COMMERCIAL-SCALE GASIFIER (ACSG) DEMONSTRATION PROJECT SCHEDULE

tion/optimization phases, Sasol will take over the plant. Westinghouse will be allowed to conduct tests for potential clients during this final commercial operations phase. This demonstration project is the last step in commer- cializing the PAFO gasification process. The process has been developed by Westinghouse in the laboratory and at the pilot-scale beginning in 1970. Initially the gasifier was a two-stage, air-blown process. This concept was successfully tested in a pilot plant from FIGURE 3 1974 to 1977. A single-stage concept evolved in late SINGLE-STAGE WESTINGHOUSE 1977 when the capability to feed caking coals directly COAL GASIFIER. into the fluidized bed was demonstrated. In 1978, the air-blown concept was augmented with an oxygen-blown process. The pilot plant has operated for over 8000 making it non-caking. The coal is then combusted with hours at coal feed rates up to 30 metric tons per thy. oxygen to provide process heat and subsequently gasified Nearly every major type of coal in the United States to form synthesis gas (carbon monoxide, hydrogen, and has been tested. impurities). The jet causes a high rate of solids circulation, resulting in a well-mixed, isothermal bed. In addition to the pilot plant tests, Westinghouse has conducted fluidization studies in laboratory and a 3- The ash components in the coal melt causing the char-ash meter diameter cold-flow models. Various bench-scale particles to agglomerate by a sintering action. These tests of the gasification process have been conducted. agglomerated particles become larger than the coal Additionally, cleaning and combustion of hot fuel gases particles and eventually defluidize. The particles are have been studied. Analytical models of the gasifica- removed from the bed in the ash annulus, cooled by tion process have been developed from the test data. recycle product gas, and withdrawn to lock hoppers Additional information concerning Westinghouse's through a rotary valve. development efforts can be found in the December 1980 issue of the Cameron Synthetic Fuels Report beginning The raw product gases are free of tars and oils, but on page 4-38. contain entrained particulates (65-75% carbon and 25-35% ash). The effluent gases are cooled in a radiant steam The process to be tested by Sasol and Westinghouse boiler to 700°C (1290°F) and in a steam superheater to utilizes minus 6 mm (minus 1/4 inch) coal that is first 370°C (700 0 F). A cyclone removes the particles and dried to 5% surface moisture. As depicted in Figure 3, returns them to the gasifier bed. Venturi scrubbers cool the coal is fed by lockhoppers and a rotary valve into the gas to 160°C (320°F) prior to final scrubbing in a the feed system operating at 30 bar (435 psi). Recycled quench tower. A portion of the product gas is used for product gas is used to pneumatically transport the coal reactor fluidization, ash cooling, and solids transport. to the gasifier where the coal, steam, and oxygen are The majority of the gas is used by the Sasol Two complex fed into the vessel through a feed tube assembly. At or is flared. The expected operating conditions of the the end of the feed tube, a jet is formed where the coal Advanced Commercial-Scale Gasifier (ACSG) are sum- is heated to the reaction temperature of 1010°C marized in Table 1. (1850 0 F). In the jet, the coal is devolatilized, thus

4-6 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE I ACSG OPERATING CONDITIONS

Flow Gauge Rate Temperature Pressure Composition Stream tonne/hr Bar

Coal Feed 47.6 27 0 (WT%) —Carbon 50.2 —Ash 18.2 —Volatiles - 22.6 —Moisture 9.0 Oxygen Feed 25.4 150 33 Steam Feed 22.4 390 37 Recycle Gas 17.6 96 30

Fines Recycle 33.0 704 30 Ash Removal 9.2 100 0 (WT%) —Ash 85.0 —Carbon 15.0 Net Dry Product Gas 65.5 171 27 (VOL%) —CO 42.8 _11 2 31.5 —CH4 5.8 —CO2 17.4 —Other 2.5 Net Steam Product 19.6 427 40

The joint Sasol/Westinghouse project is intended to stage of project planning," Seder said. The U.S. Depart- commercially demonstrate a second-generation coal ment of Energy had recently waived restrictions on the gasification process at a minimum of cost and time. Great Plains loan guarantee that prohibited planning for a When completed, the project will make the process second phase. Seder stated, "We have advised the Depart- available for a wide variety of commercial applications. ment that our emphasis will continue to be on the efficient construction of Great Plains. However, because of the long lead times involved, they have agreed that we can begin to focus some attention on a Phase II expan- ANR DISCUSSING A SECOND PHASE OF THE GREAT sion." PLAINS PROJECT A second phase would have much the same configuration On December 17, 1982, American Natural Resources as the first, and would use the same basic processes, but Company (ANR) announced it was engaged in explora- could include modifications allowing it to co-produce tory discussions on the construction of a second phase liquid fuels, such as methanol, along with synthetic of the Great Plains synthetic fuels plant with state and natural gas. The second phase, if built, would be located local officials, and with the chairman of one of the next to the first one, which is now under construction energy companies building the project. Arthur R. eight miles north of Beulah, North Dakota. Seder, Jr., chairman of American Natural Resources Company, stressed that no final decision had been When the Great Plains project was first proposed in the made. "We are having these talks because our company 1970's, two full production "trains" operating to produce policy is to consult with North Dakota leaders at every 250 million cubic feet of gas daily were planned. How-

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-7 ever, in response to financing problems and concerns about the effect of constructing such a large plant at one time, the plan was changed to allow for phased construction. Extensive engineering work applicable to a second phase was completed as part of the original design and would permit commencement of construction if market, economic, and other study results are positive. As described in the article beginning on page 4-1 of the September, 1982 Pace Synthetic Fuels Report, the Great Plains plant now under construction is scheduled to begin operations in late 1984 and will produce 125 million cubic feet of synthetic gas a day. in addition to American Natural, other partners in the plant are subsidiaries of Tenneco, Inc. and Transco Energy Com- pany, both of Houston; MidCon Corp. of Chicago; and Pacific Lighting Corporation of Los Angeles.

4-8 SYNTHETIC FUELS REPORT, DECEMBER 1982 CORPORATIONS

C-E LUMMUS ACTIVE WITH TWO COAL CONVER- SION PROCESSES C-E Lummus, a subsidiary of Combustion Engineering, Inc., recently announced its active involvement with two coal conversion projects. On September 1, 1982, the company announced it had been selected by Rock- well International Corporation to develop a conceptual design and economic evaluation of a commercial-scale SNG plant using peat as the feedstock. The key feature of this process is the Rockwell Flash Hydropyrolysis (FHP) reactor system in which peat and hot hydrogen are reacted in a single-stage, short-residence time, entrained flow reactor to produce substitute natural gas and if desired, by-product chemical-grade benzene. In 1980, Rockwell selected Lummus to do a similar design development study using the Cities Service/Rockwell (CS/R) Hydrogasification Process employing coal as the feedstock, the results of which showed that the Cs/a Process has a good potential for future use. On November 11, 1982, it was announced that Inter- national Coal Refining Company (ICRC) had signed licensing agreements covering the LC_FiningTM unit with C-E Lummus for its delayed coking process. Both processes have been licensed for ICRC's proposed solvent refined coal (SRC-1) synfuels project at Newman, Kentucky, which is funded by the U.S. Department of Energy. ICRC completed the project baseline report in May, and the project is presently undergoing further review by ICRC. The delayed coker and the LC-Fining unit would receive molten liquid solvent refined coal from up-stream process units. Approximately 3,600 tons-per-day of molten solvent refined coal would be produced. One-third would go to the delayed coker to produce coke to be calcined to anode grade coke for the aluminum industry, liquid fractions for further processing, and fuel gas for steam generation. Another third of the molten liquid SRC is earmarked for the LC-Fining unit, a hydrotreating process. The unit would upgrade the SRC into suitable feedstoeks for refining to products such as gasoline, diesel fuels, or petrochemical feedstocks. The remaining one-third would be produced as a solid product for conventional pulverizing into boiler fuel. Lummus' delayed coker technology has been commercially proven in 33 projects over the past 30 years. The LC-Fining unit—a joint development of Lummus and Cities Service—is a proven hydrotreater technology based on commercial application and advanced development at Lummus' New Bunswick research facility.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-9 GOVERNMENT

GAO ANALYZES GOVERNMENT INVOLVEMENT IN • With second generation processes now advanced to HIGH-BTU GASIFICATION the demonstration phase and with environmental research being curtailed, is continued government The U.S. General Accounting Office (GAO) recently support of research and development necessary? issued a report in which it analyzed Federal government and industry efforts to develop and commercialize high- • Will second generation processes for high-BTU BTU coal gasification technologies. The title of the gasification be able to successfully compete with report is "Government Support for Synthetic Pipeline other synthetic fuels processes for SFC assistance? Gas Uncertain and Needs Attention" (GAO/EMD-82-23). Of specific interest to GAO was determining whether • What benefits are there to continued government government research and development efforts were support and if support is needed, how can costs be consistent with current policies and how government minimized? can use its limited funds to the greatest benefit. The report was prepared from published information and • How can a selection be made of the many pro- from discussions with officials at the Department of cesses now available that will give the greatest Energy (DOE), Environmental Protection Agency (EPA), national benefit? Federal Energy Regulatory Commission (FERC), Office of Management and Budget (OMB), Synthetic Fuels Government Support of Research and Development Corporation (SFC), Army Corps of Engineers, American Gas Association (AGA), Gas Research Institute (CR1), GAO concludes that Government support of high-BTU and National Coal Association (NCA). Based on these coal gasification research and development must be more discussions, the following projects were more closely focused. This conclusion is based on the GAO's opinion examined: that certain functions should be performed by industry and not the government, that second generation processes • Demonstration Projects (except HYGAS) are not significantly more attractive than well-established first generation processes, that Slagging Lurgi (Conoco) Federal support of third generation processes is not COGAS Process (Illinois Coal Gasification needed at this time, and that funding of generic research Group) (e.g.: process control, etc.) is contrary to the philosophy Hygas Process (Institute of Gas Technology) of the Reagan administration. On the other hand, the GAO concludes that the Federal government should • Commercial Projects become more actively involved with environmental research. In summary, the report states that dis- - Great Plains crepancies do exist between DOE's activities and the - WyCoalGas Reagan administration's policies. - Tri-State To resolve these discrepancies, the GAO suggests that The GAO then interviewed the project sponsors, state DOE initiate a system of long-range, integrated planning. officials, and process developers involved with the six Additionally, the GAO recommends that DOE define projects. This assessment by the GAO represented a boundaries that determine the distinct role to be left to cross-section of opinion through mid-1981 with minor the government. changes through November 1981. The GAO report contains the following recommendation The GAO report concludes that high-BTU coal gasifica- to the Secretary of Energy: tion is presently at a crossroads. Industry and Federal government efforts have advanced first and second "establish a plan to guide future support of high-BTU generation processes. However, industry capital con- coal gasification energy research and development. straints, new natural gas sources, and the new The plan should be based on clear policy objectives and philosophy of the Reagan administration makes further defined criteria which will set the general limits of advancements of the technologies more difficult. The government support in the context of overall energy GAO, therefore, concludes that no one can predict how research and development. Also, the plan should much high-BTU gas will be needed and when. recognize research that is more appropriately funded by industry, and include essential environmental The GAO report specifies several important issues that research that is beyond the responsibility of industry." must be considered before proceeding with further government support of high-BTU gasification activities. Government Support of Commercial Demonstrations These issues include: The GAO is in favor of the construction of commercial scale demonstration plants because such facilities would

4-10 SYNTHETIC FUELS REPORT, DECEMBER 1982

demonstrate the viability of high-BTU coal gasification, no comments to the report. However, DOE did not agree extend the long-term availability of natural gas, and with the report in general. replace imported oil with synthetic fuels. Additionally, the GAO concludes that the SFC is a unique method of ## ## advancing both first- and second-generation technologies. High-BTU coal gasification is believed to THE NEW FEDERAL COAL LEASING REGULATIONS be one of only three technologies now ready for large- scale plants. The Reagan Administration's new Federal Coal Leasing regulations became effective on August 30, 1982. While The GAO believes that government support is these regulations do not completely revise the coal warranted because commercial demonstration plants leasing program initiated by the Carter Administration, will benefit the nation. Also, private funds to build the they do promise to significantly increase the availability plants is not readily available, the ratepayers will not of Federal Coal reserves and should decrease some of the fully support synthetic pipeline gas because of its burdensome requirements inherent in the previous Federal higher cost, and the individual states can only provide Coal Leasing Program. Some of the more significant limited support. Hence, the SFC should support demon- changes in Federal coal leasing are discussed in the stration plants and also insure that project sponsors and following paragraphs. lenders bear an appropriate risk. The new leasing regulations differ significantly from the Because two of the three commercial projects that the previous ones in that coal will be leased to satisfy GAO studied planned to use first generation processes industry's demand for reserves and not to satisfy pro- and western coals, the report suggests that the govern- jected coal demand or achieve set production goals by ment should encourage second generation processes region. The previous regulations required coal to be capable of using eastern coals. leased only when demand for coal threatened to outstrip production. As a concept, leasing to satisfy industry's Rather than building demonstration-scale plants of demand for coal reserves will allow industry to decide second generation processes, the GAO recommends when and where to develop new coal production. In building commercial-scale modules to accelerate addition, it will provide more competition in the develop- development of the technologies. The report recog- ment of new reserves as those reserves which are more nizes that these larger scale projects entail larger competitive than others will be developed first. investments of greater economic risks than demonstration projects. The GAO concludes that DOE should Recommendations for coal leasing levels will be help resolve unanswered questions concerning second developed by the Regional Coal Teams (RCT) and sub- generation technologies and also educate the SFC permitted to the Secretary of Interior through the Director sonnel. To limit the expense to the government, GAO (BLM State Director) who may provide additional data and recommends choosing a diversity of technologies and recommendation only as separate documentation. In supporting projects with capacities less than a full- addition, all of the Governors' recommendations will be sized commercial plant (250 million cubic feet per day). transmitted unchanged to the Secretary as part of the RCT transmittals. Upon receipt of the recommendations, Two recommendations concerning commercial demon- the Secretary will consult, in writing, with the Secretary stration projects to the Secretary of Energy are of Energy, Attorney General and affected Indian tribes. included in the GAO report: Prior to establishing the final leasing level for a proposed lease sale, the Secretary will consult with the Governors • "Evaluate the importance of the high-BTU of affected states to obtain final comments and recom- second-generation process as a method of using mendations. In summary, the leasing levels will be based eastern coal, and the prospects for accelerating on the following factors: the processes as commercial scale modules. As part of this evaluation, DOE also needs to con- • Advice from Governors of affected states through sider other coal gasification and indirect lique- the RCT. faction options. • Potential social, economic, and environmental • "Report, within 90 days of the date of this impact. report, to the Synthetic Fuels Corporation's Board of Directors on the potential role of • Expressed industry interest in coal leasing and second-generation processes in the synthetic fuel indication of demand for coal reserves. program, the availability of information needed for commercialization, product costs and • Expressed interest for special opportunity sales. markets, and technical and environmental risks." • Expected production from existing Federal leases Agencies Responses to the Report and non-federal coal holdings. Draft copies of the report were supplied to DOE, SFC, • The level of competition within a region and re- OMB, and FERC. The SFC responded that the report commendations from the Department of Justice. provides a useful perspective to many issues, but the GAO analysis was too narrow in scope because it • U.S. coal production goals and projections of future focused only on high-BTU coal gasification. FERC had demand for Federal coal.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-11 • Consideration of national energy needs and other such exchanges can be shown to serve the "public pertinent factors. interest." Only those leases affected by Alluvial Valley Floor designations which have made significant financial Following publication of the final leasing regulations, commitments will be allowed to exchange leases. DO] came under attack by accusations that state government input had been eliminated by the new The new regulations also change the way in which unsuit- regulations. Late in November, Interior Secretary ability criteria will be applied. Interior has recognized James Watt met with western Governors and assured that unsuitability should only be applied to specific mine them that their input would be considered in setting the plans and not to coal mining in general. Further, with leasing levels. It appears that the Secretary's assurance appropriate planning and mitigation procedures mining came in a personal commitment to consider the Gover- can exist and still preserve other resource values. This nors' input as is spelled out in the new regulations. concept has the potential of changing areas designated for Additionally, Watt reportedly will accept the Gover- limited use to areas of multiple use. nor's recommended stipulations when a state's interest in leasing is significantly balanced with the Federal The Reagan Administration has revised the responsibi- interest in leasing. Actually, input from state govern- lities of the Office of Surface Mining (OSM) and the ments is already highly weighted due to the high level Minerals Management Service (MMS) to separate the of state participation in the leasing program. The reclamation and environmental duties from the adminis- Secretary of Interior will, however, make the final tration of mining and production. New regulations decisions as to the leasing levels. governing the MMS became effective on August 30, 1982, the same day as the new leasing regulations and were Industry will provide input primarily through their implemented to eliminate duplication of responsibilities response to "calls for coal resource information." Such of OSM, MMS, and the states. Several regulations per- information would include a description of the land that taining to the MMS provide more viable operating options should be leased and an explanation as to why the land for coal companies. MMS regulations now permit the should be leased. Obviously, responses to "calls for submittal of a Resource Recovery Plan within 3 years of resource information" will be weighted in proportion to the effective date of a lease (leases issued after 8/4/76) the level of detail included within the response. or readjustment date (leases issued before 8/4/76). This Confidential data will be excepted through the Minerals plan does not have to be submitted with a comprehensive Management Service, (and kept confidential) as all mine and reclamation plan but can be conceptual in submittals to RCTs will be open to the public. The nature. The result is that lease holders will not be public or special interest groups may also describe pressed into preparation of a comprehensive plan of areas and the reasons why certain coal land should not operation and this will provide relief if the market be leased during the "call for coal resource infor- conditions do not favor development at that time. The mation." Both industry and the public will have ample Resource Recovery Plan requirement has provisions to opportunity to comment on leasing levels through the include nonfederal coal in a logical mining unit. This public Region Coal Team meetings and also the public abolishes the treatment of each lease as a logical mining Federal-State Coal Advisory Board meetings. unit and should have the result of allowing a more Responses for the "call for coal resource information" efficient and orderly development of mineable reserves. will be the initial step in the land use planning process. The MMS regulations also rely on standard industry prac- Previously, the land use plans were prepared without tice in determining if maximum economic recovery of significant input from industry. Federal coal will be achieved. The new MMS regulations also ease due diligence requirements as only 1% of the The new leasing regulations also change the procedure reserves will have to be produced within 10 years of the for setting minimum acceptable bids. Interior will now effective lease date (or ten years after the first readjust- set a minimum bid of $100/acre and let competitive ment that occurs after 8/4/76 of leases issued prior to bidding raise the bid to as high as it will go. Then that date). Interior will make a determination as to whether the requirement of fair market value has been met. In non- The new leasing and MMS regulations are tailored to more competitive lease situations (maintenance or bypass closely conform with the needs and practices of industry. leasing) Interior will set a minimum bid to assure that Interior is hopeful that the new regulations will encourage fair market value is established prior to the lease sale. federal coal acquisition. However, on September 28, The lease sales under the new regulations will in fact 1982, the Natural Resources Defense council in concert indicate to Interior the need for new leasing. High bids with other environmental groups filed suit against and more participation will indicate a demand by Secretary of Interior James Watt and BLM Director industry for more reserves. Low bids and little interest Robert Burford. The suit seeks to stop all coal leasing wiU indicate a relatively low demand for new reserves. until the coal leasing program is returned in a manner similar to the previous leasing program. Complaints The new leasing regulations also permit Interior to include: that the new regulations will encourage un- waiver, suspend, or reduce annual rentals and royalties needed development of large blocks of Federal coal; (with exception of advance royalties). This provision speculators will lease Federal coal at the public's expense; will assist individual coal mines in continuing operations leases will be issued without effective land use planning; when problems could cause a mine to operate at a loss. and that the new rules violate Federal law. Under the new regs, holders of leases restricted by Representatives of industry (National Coal Association, Alluvial Valley Floor designations will be allowed to American Mining Congress, and individual companies) exchange those leases for other open Federal coal if

4-12 SYNTHETIC FUELS REPORT, DECEMBER 1982 were preparing to intervene in the suit at the time of this writing.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-13 ENERGY POLICIES

SECOND CONGRESSIONAL HEARING ON THE USE producers are able to independently establish a methanol OF METHANOL AS AN ALTERNATIVE TO GASOLINE fuel industry. Therefore, at this second hearing the Subcommittee attempted to receive testimony from both As summarized on pages 4-40 to 4-44 of the September industries. 1982 issue of the Pace Synthetic Fuels Report, the U.S. House of Representatives Subcommittee on Fossil and Each witness presented formal testimony and also parti- Synthetic Fuels has been studying the use of methanol cipated in question and answer periods. The give and take as a fuel. The Subcommittee conducted a second public discussions were extensive, with most of the action hearing on September 24, 1982, to receive testimony coming here, rather than through the formal testimony. from various industry and governmental experts. Other At the end of the hearing, Representative Sharp advised Congressional hearings have also been conducted to that he will submit a list of written questions to each evaluate nontraditional fuels. The content of one such witness, and include their responses in the report that his hearing by the Energy and Power Subcommittee of the subcommittee will be putting together on the subject. House Interstate and Foreign Commerce Committee was summarized in the March 1981 issue of the The witnesses all agreed, to one extent or another, that Cameron Synthetic Fuels Report beginning on page 4-8. methanol is an acceptable automotive fuel. Additionally, all the witnesses agreed that the Federal government Two panels, listed below, presented testimony at the must play a key role in establishing the industry. How- hearing on September 24, 1982. ever, a divergence of opinion existed among the witnesses as to the best method of using methanol as a fuel. The Panel 1 automobile manufacturers were in favor of using neat methanol in specially designed engines whereas the Mr. Edward G. Guetens, Jr. methanol producer was in favor of using methanol- Business Manager, Oxygenated Fuels gasoline blends. A third option was presented by a ARCO Chemical Company consultant, Peter Hunt, who proposed using methanol to 1333 New Hampshire Avenue, NW replace middle distillates. Suite 1000 Washington, D.C. 20036 Testimony by Edward Guetens Jr. of ARCO Mr. Jaques R. Maroni Mr. Cuetens stated that ARCO believes blending 5% Director, Environmental Research & Energy Planning methanol in gasoline could significantly reduce crude oil Ford Motor Company imports. Additionally, methanol blends could reduce 815 Connecticut Avenue, NW exhaust emissions of hydrocarbons by 20% and carbon Washington, D.C. 20006 monoxide by 40%. ARCO has assumed a major role in methanol fuels by receiving three waivers from the Mr. Joseph Colucci Environmental Protection Agency (EPA) for oxygenated Head, Fuels & Lubricants Department fuels. In 1981, ARCO sold or used 12,000 BPD of alcohol General Motors in gasoline and will increase its production capability in 1660 L Street, NW December 1982 by bringing a 13,000 BPD methanol plant Suite 800 on stream. Although there are three options available to Washington, D.C. 20036 the country, the first two (waiting for the methanol economies to become favorable, and allowing the govern- Panel 2 ment to force the economics by subsidies) are discarded by ARCO in favor of development of markets for blends. Mr. F. Kevin Roland Acting Deputy Director ARCO believes methanol fuel blends are economic today General Accounting Office even without government subsidies and that the market 441 C Street, NW for blends is large enough to require several coal-based Washington, D.C. 20548 methanol plants. With these plants in place, the existence of a secure supply will facilitate the design for neat Mr. Peter S. Hunt methanol vehicles. Peter Hunt Associates 7501 Elba Road Guetens stated that problems in developing methanol Alexandria, Virginia 22306 blends are infrastructural and regulatory and developing infrastructure depends upon increasing demand. Congress At the first hearing Representative Sharp, the Chair- can help overcome the regulatory problems by mandating man of the Subcommittee, referred to the "chicken and that the EPA allow methanol the same waivers for vapor egg" problem plaguing the methanol fuel industry. pressure restrictions as are currently allowed for ethanol Neither the automobile manufacturers nor the methanol blends. Section 211 of the Clean Air Act should be

4-14 SYNTHEIC FUELS REPORT, DECEMBER 1982 amended to expand the "substantially similar" concept 3. Limiting the concentration of methanol in such to encompass a wider range of gasoline components, blends to 5% until there is clear and convincing thus eliminating the need for waivers for every new evidence that technical advances in co-solvents blend. Fuel additive regulations also should be and corrosion inhibitors have progressed to the expanded on a generic basis. Limited layering of fuel point that higher levels would be suitable. blends also should be allowed. 4. If favorable economics of neat methanol develop, In summary, ARCO's approach is to use methanol blends direct the then-existing production base (presum- to stimulate methanol production and distribution ably developed with blends) to the supply of neat systems. With the infrastructure in place, ARCO methanol fuels. believes the transition to neat methanol fuels will have begun. Testimony by Jacques Maroni of Ford Testimony by Joseph Colucci of General Motors In his formal testimony, Maroni stated that Ford believes near-neat methanol fuels (methanol with additives) has Colucci's testimony began with a summary of the the best potential for use as a transportation fuel. For a advantages and disadvantages of neat methanol fuels as substantial methanol fuel industry to develop, the fuel perceived by General Motors. producers require the following: The advantages include: • Long-term contracts assuring full capacity utilization of methanol projects. • ability to be produced from a wide range of domestic feed sources • Some means to guarantee that any methanol pro-- duced would be sold at a profit to ensure a revenue • potential to produce methanol in the future at stream that would make projects "bankable." costs competitive with gasoline • Protection against the possibility that a drastic • improved thermodynamic efficiency over today's decline in the price of gasoline would cause con- gasoline engines sumers to shift away from methanol use. • no apparent problems of achieving emission Additionally, the vehicle manufacturers require: levels required by the Clean Air Act • Resolution of any remaining technical issues, in- • available technology to design and build neat cluding systems compatibility, emissions and safety methanol-fueled vehicles with no expected major consideration, and performance specifications. differences in cost. • Reasonable expectation of conditions favorable to The current disadvantages include: full use of vehicle production capacity put in place. These include adequate fuel distribution to insure • need for appropriate safeguards in distribution that the fuel is conveniently available to con- and handling systems and vehicle fuel systems to sumers, favorable retail pricing at launch, and accomodate for the physical and chemical pro- protection against a decline in gasoline price rela- perties that are different than gasoline tive to methanol. • need for more cold starting aids To accomplish the above objectives, Ford believes that Congress should broaden the charter of the U.S. Synthetic • regulatory questions. Fuels Corporation (SFC). The SFC could provide funding to launch the conversion plants; coordinate the necessary On the other hand, General Motors position concerning inter-industry exchanges to assure that vehicle and fuel methanol blends is that "GM cannot unequivocally supply and distribution are in step; explore ways to give endorse the use of methanol-gasoline blends in existing methanol producers, on a short-term basis, the prices and vehicles at this time" because of volatility and cor- market assurances they need to get under way; and pursue rosion. GM plans to continue to evaluate methanol- the most attractive methanol feedstock. gasoline blends both in the laboratory and vehicle tests. Presently, GM's Opel Division is selling vehicles in In his verbal testimony, Maroni emphasized the following Germany with methanol-compatible materials, but the points: air-fuel ratios of the vehicles must be adjusted to operate on gasoline with 15% methanol. 1. Methanol blends have been in use in Europe for years, but they have not led to neat methanol GM recommends: engines. 1. The use of neat methanol in engines designed 2. Methanol is the most cost-effective manner in specifically for the fuel. which coal may be used in automotive engines. 2. If blends are pursued, they should be permitted 3. Rising oil prices will not encourage switching to only with adequate consumer labeling and with- neat methanol fuel. For example, propane has out subsidies or other economic incentives. been on the market for 40 years; it is clean burning

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-15 and high octane; its distribution systems are in Thus, it is in the public interest to get the market place; but still it is not a significant motor fuel. started soon, because such fuels will provide lower cost energy for the public. 4. Current incentives will not suffice to stimulate methanol fuels because methanol has its highest t Colueci: - If the policy is to convert coal to value as a chemical feedstock, not as a automotive fuels, the choice now is methanol. (All transportation fuel. The United States has a panel members agreed). temporary oversupply of methanol only because the housing market is depressed. Question by Representative Sharp: - Up to now, our national energy policies have been based on the assump- 5. A neat methanol fuel market cannot be launched tion that we should reduce oil im ports. But this assump- under current market conditions. Therefore, tion now is fading. If we eliminate the assumption that Congress now must decide whether it is in the we must reduce oil imports, is it still in the public public, interest to set a national policy to intro- interest to shift to coal? duce methanol as an alternate fuel. If so, then it must also address all of the subsidizing means The panel members responded as follows: for so doing, including modifying the SFC authorities to allow stimulation of the market- • Colucci: - Yes. There is much more coal in the place. ground than there is petroleum. Question and Answer Period for Panel 1 • Maroni: - There is also a lot of low value natural gas throughout the world, although not much is in Following their formal testimony the Panel 1 witnesses the USA. Methanol from low value natural gas can were allowed to discuss their differing viewpoints. be available at an almost com petitive price. Each witnesses' statements are summarized in the Therefore, the US should make an international following information. tender offer to buy all the methanol that can be made from this low value natural gas. Guetens (ARCO): The arguments that the public will not buy vehicles capable of using methanol fuelsis • Guetens: - If the marketplace is left to its own invalid because the same arguments could have been devices, developing coal-based fuels will take a made against the introduction of diesel fuels and diesel long time. engines, but people bought them, even with the uncertainties of new fuels and new engines. The arguments Concerning the low value natural gas concept, it is against blends on the basis of current economics are naive to assume that if a methanol use is developed equally invalid because it is naive to assume that for the low value gas, its value will remain low economies ever stay the same for long periods of time. afterwards. Developing countries will not sell The key is creating methanol supply. Once the capital their gas at a low value, at the same time trying to investments are made in production plants, industry will get $35/Bbl for their low value crude. run them because it is in their best interest. Coal then becomes the cheapest part of the process. Blends are Question by Representative Sharp: - What are the retro- the best way to create consumption. Once the public fitting problems and how does blends versus neat starts using methanol, consumption will increase, and methanol affect them? the pathway to neat methanol engines will be paved. The panel members responded as follows: Colucci (General Motors): Current vapor pressure regulations protect the consumer, particularly against • Colueci: - There is a need to retrofit each auto vapor lock. If this regulation is removed, vapor lock model. New parts must be manufactured and problems may occur again. Thus, Congress should not distributed, but for only a percentage (how much is wipe out all federal regulations - some of them are the question) of the existing models. In retrofit- very worthwhile. ting for neat methanol, existing vehicles must accept different compression ratios, different Maroni (Ford): Agrees that once methanol plants are up emissions, and corrosion.. All these retrofitting and operating people will run them. But, the product problems disappear if the country simply plans to will find its way into the chemical feedstock market, start with new engines designed for neat methanol, rather than transportation, because that is where its and that is GM's position. higher value lies. • Maroni: - Ford has the same kind of concerns. In Questions by Representative Sharp: Is it in the public addition, Ford is concerned with what refiners interest to shift to neat methanol? Is it a national might do with blends. There is the danger that security question? smaller refineries can overblend because methanol is cheaper than gasoline. Even retailers can dilute The panel members responded as follows: with methanol and extend their gasoline supplies. • Maroni - The question of national security is an • Colucei: - This problem of methanol blending could issue for Congress. However, from a fuel effi- lead to different percentages of methanol in the ciency point of view, it is more efficient to burn gasoline, with its subsecjuent corrosion and volati- neat methanol from coal than to burn blends. lity problems. Even now, many consumers don't

4-16 SYNTHETIC FUELS REPORT, DECEMBER 1982 know that they are purchasing blends. Perfor- Question by Representative Sharp: - What are your mance problems with methanol develop so slowly (eelings on the neat methanol versus blend question? that if the consumer is not aware that he is burning methanol, he is apt to blame the auto The witnesses responded as follows: manufacturer for poor performances. Therefore, rigid labeling is mandatory to GM. • Roland: - It all depends on the timing. Do we want to run or crawl? The U.S. needs to get the • Guetens: - Labeling is a tough proposition under consumer to understand methanol fuels. Blends are today's regulations. Ethanol labeling is accept- a fine way to do that, but neat fuels will take able because it is blended at the terminal; but longer. methanol is blended at the refinery. • Hunt: - We must go after neat fuel directly, There are always risks associated with intro- without going through blends. Buses, taxis and ducing new products to the market, but ARCO fleets should be running on neat methanol now. thinks the risks from methanol are minimal. This will allow advantage to be taken of lower emissions in the cities right now. Also, establish- Testimony by Kevin Roland of the GAO ing groups of vehicles is much simpler than setting up to serve the total consumer marketplace. F. Kevin Roland presented the views of the U.S. General Accounting Office (GAO) concerning the use of Question by Representative Sharp: - What actions should methanol fuels. Based on three years of study, the the federal government take? GAO is highly optimistic about methanol's potential as an automotive fuel." However, the major obstacle Responses by Panel 2 impeding methanol is simultaneously developing production, a distribution network, and suitable vehicles. • Hunt: - Congress should get into the standards issue. EPA has been evaluating methanol for 4 to S Boland stated that the time has come to develop fuel years now, without much happening. efficiency standards that will put methanol on a par with gasoline. Encouraging methanol fleets will be • Roland: - Careful pump labeling is needed, other- limited by the limited range of the vehicles and by their wise methanol will show up as an inferior fuel. reduced resale value, as long as the fuel is not widely EPA's waiver program seems to be working well at available to the public. Also, without commensurate present, but timing is the key. If we want faster development of a domestic methanol fuel market, the progress, the Federal government must take quick developing fuel use in the US could result in further action. If a public policy is set to move methanol dependence upon foreign methanol. development faster, then standard setting is the most fruitful area for the Federal government. Testimony by Peter Hunt, Consultant: • Hunt: - Once standards are set, automotive manu- Peter Hunt, an energy consultant, presented a slightly facturers will soon exceed them. Leaded gasoline different view of the potential use of methanol as a probably will phase out within ten years. This fuel. Hunt agrees that methanol is a superior motor means that the leaded gasoline pumps at service fuel to gasoline. However, he believes methanol should stations can be converted over to methanol fuel be used as a replacement for middle distillates because pumps. the annual growth for distillates is increasing at 3-4% whereas the demand for gasoline and resid is declining Question by Representative Sharp: - What is the role of at 4-6%. This inbalance will continue as diesel auto- methanol versus other alternative fuels? What should the mobiles become more popular and as crude oil becomes subcommittee focus on? heavier. Responses by the witnesses: Hunt predicts that the cost of distillate fuels will rise well above $2.00 per gallon. On the other hand, • Hunt: - LNG and compressed natural gas are diffi- methanol produced from coal was predicted in the cult to handle, from the safety point of view. Our Badger Report to be $0.30 per gallon and was predicted infrastructure is set up for liquid fuels. Methanol by EPRI to be $0.30-$0.35 per gallon. Hence, Hunt is quite safe to handle and in not outside the believes that the economics and technology of substitu- existing infrastructure. ting methanol for petroleum now exist. Additionally, Hunt pointed to methanol production and/or engine • Roland: - Methanol is preferable to ethanol and development being agressively pursued in Germany, liquid fuels are preferable to other options, includ- Sweden, Australia, South Africa, Canada, Japan, India, ing the electric ear. Argentina, and New Zealand. Questions by Representative Sharp: - Where are foreign Question and Answer Period for Panel 2 imports of methanol coming from now? What is the future foreign import potential? Should we fear foreign As with the first panel, the second panel discussed their imports? Is this a national defense issue? viewpoints and responded to questions from the Chair- man of the House Subcommittee. This discussion is summarized in the following information.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-17 Witnesses responses:

• Boland: - Imports currently are coining mostly from Canada. • Hunt: - This is not an OPEC type of problem. Methanol can be produced from a whole host of feedstocks. Even the poorest nations can produce it from biomass. There is little likelihood of a methanol cartel being formed to hold the US at bay. Future Plans by the Subcommittee

The Subcommittee on Fossil and Synthetic Fuels plans to submit a list of written questions to each witness. The responses will be incorporated into the report the Subcommittee will prepare. Expected issue date of the report is early 1983.

4-18 SYNTHETIC FUELS REPORT, DECEMBER 1982 ECONOMICS

COSTS OF PRODUCING METHANOL AND MEDIUM- of 5,000 short tons per stream day of fuel grade BTU GAS BY UCG methanol. Identical field gasification facilities were studied for the production of medium heating The Jacobs Engineering Group (parent company for The value gas. In both cases, provision was made for Pace Company Consultants and Engineers, Inc.) has the generation of sufficient additional Mliv for the developed capital and operating costs for the produc- steam and electric power requirements of each tion of methanol and medium-BTU gas via underground complex. The gas produced by the underground coal gasification. The studies were funded by Gulf gasification of coal (in situ) is summarized in Table Research and Development Company. Results of the 2. studies indicate that UCG operations can produce methanol and gaseous fuels at very competitive prices Well drilling was calculated for a horizontal coal compared to surface gasification-processes. seam, 30 feet thick, whose bottom is 600 feet below the surface. Vertical injection/production Design Basis wells were assumed to be drilled to the bottom of the coal seam at intervals throughout the length of The study was intended to develop preliminary (25%) the field and joined at their bottoms by horizon- capital and annual operating costs for an UCG opera- tally drilled linking wells. The field was divided tion capable of producing either: into two sections, each of 10 year life. Table 3 summarizes the well drilling required for one 10- 1. 5000 short tons per day of fuel grade methanol year section. (the FGM case) 2. Gas Gathering and Transport or 2. as much medium heating value gas (the MHV case) as possible from the same amount of coal The field was divided into two parallel ten-year as required for Case 1 sections laid out side-by-side with the process plant at one end. Burning was assumed to com- An extensive list of design criteria, as described in mence at the process plant end of one section and Table 1, were established jointly by Jacobs and Gulf. progress away from the process plant for 10 years Three cases representing different amounts of oxygen and then progress back toward the process plant and steam injection were evaluated and Case Ill for 10 years in the second section. Including a 200- (defined in Table 1) was selected as being most repre- feet wide pipeway and road between the two sentative of a large in situ gasification field. There- sections and sweep extension on the flanks of the fore, the composition and material balances of Case Ill field, all the combustion for twenty years should were used for this design study. occur within an area 9,600 feet by 12,200 feet (4.20 sq. mi.) using this layout. Process Description Each module requires two wells for operation: an Both the FGM and the MHV processes were divided in injection well through which oxygen and steam are five elements as follows: introduced into the coal seam and a production well through which the products of the underground 1. Field gasification facilities combustion are delivered to the surface. Combus- tion is guided by the linking well drilled horizon- 2. Gas gathering and transport system tally at the bottom of the coal seam. When combustion reaches the production well, it is 3. Feed gas/solids separation system necessary to take the module out of service and shift the surface piping so that the production well 4. Gas clean-up system changes to injection service and a new production well is connected. This sequence repeats itself 5A. Methanol complex constantly. It is necessary that the surface piping accomodate the frequent changes required as the 58.MHV complex field operation moves forward. Elements one through four are identical for both the The costs used in this study assume that when the FGM and MHV cases. process units are shut-down for service (they have a 90% on-stream factor), the field headers will be 1. Field Gasification Facilities moved closer to the current combustion activity in preparation for another year. The costs used in Field gasification facilities were designed to this study also assume the use of a single 30" O.D. generate sufficient feed gas for the manufacture insulated, stainless steel line for the transport of

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-19 TABLE 1

DESIGN BASIS FOR THE PRODUCTION OF METHANOL OR MEDIUM HEATING VALUE GAS BY UCG

a) Coal Analysis: Weight Percent, MAF (Moisture and Ash Free Basis)

Carbon 74.42

Hydrogen 5.15

Oxygen 19.33

Nitrogen 0.87

Sulfur 0.23

TOTAL 100.00

Water content on MAF basis = 18.26 percent Ash content on wet basis = 5.07 percent

b) Raw gas production/ton of coal 60,000 SCF (dry basis)

e) Sulfur converted to sulfur compounds in gas = 50 wt%. d) Coal bed is 30 ft. thick, bottom of bed is 600 ft. below grade. Sweep width is 100 feet and pillars are to be equal to sweep width.

e) Mole weight of tar in gas = 250 Carbon to hydrogen ratio for tar = 1.4

f) All steam and electric power will be generated at the site by using a portion of the medium heating value fuel gas produced.

g) Actual steam injection rate will be one mole per mole of oxygen injected. This amounts to about 3 to 4 times the chemical steam requirement.

h) Temperature of raw gas at well head = 650°F i) Pressure of raw gas at well head = 250 psig. Steam and oxygen will be injected to the the wells at 300 psig. j) Raw gas composition:

Three observed potential UCG compositions represent varying levels of oxygen and steam injection: Dry Raw Gas Composition - Mole % Case I Case II Case III

H 2 40 30 25 CO 40 50 55 CO 12 12 12 CH 7 7 7 C2H 5 0.8 0.8 0.8 Tar 0.2 0.2 0.2 Total 100.0 100.0 100.0

4-20 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 (Continued)

Material balance calculations: Dry Raw Gas Compition - Mole % Case I Case ft Case II!

Dry raw gas SCE/ton MAP coal 74,680 64,456 60,350 Coal, pounds (MAE) per 100 mols gas. 1015 1176 1256 Oxygen Injection, SCF per ton coal (MAE) 4180 10,756 13,409 Steam injection, mob per mole of oxygen 5.4 0.87 0.30 k) Water content of raw gs was calculated to be 13.5 mole percent at the well head conditions. 1) Utilities are based on the following data: Atmospheric Pressure at the site = 12.0 PSIA Dry bulb temperature - summer = 85°F Wet bulb temperature - summer = 65°F Cooling water supply temperature = 75°F High pressure steam conditions = 900 psig, 850° F Condensing pressure for turbine exhaust steam = 3.5 inches of Hg Condensing temperature for turbine exhaust steam at 3.5 inches of Hg = 122°F

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-21 TABLE 2 RAW GAS PRODUCTION

FGM Case MLIV Case Total raw gas flow, • 10 6 SCED 597.3 597.3 Product gas temperature, OF 650 650 Product gas wellhead pressure, psig 250 250 Number of modules on stream 23 23 Gas flow per module, 106SCF0 26.0 26.0 Coal gasified, TPD 12,450 12,450 Exportable product 5,000 TPD 437.8 MMSCFO Unit Heating value, LHV 54,223 BTU/gal 323 BTU/SCF Exportable heating value, LHV, 80.93 141.2 lO BTU/day

*Dry basis. Gas, as produced, contains 13.5 mole % water Maximum wet gas per module = 30 x 106 SCFD.

TABLE 3

WELL DRILLING REQUIREMENTS FOR ONE TEN-YEAR SECTION

Number of parallel sweeps required* 24 Width of field, feet 4,600 Vertical well spacing, feet* 100 Length of field, feet 12,200 Number of vertical wells/sweep 123 Total vertical wells required 2,952 Total vertical well drilling, feet 1,771,200 Number of horizontal links/sweep 24 Total linking wells required 576 Total linking well drilling, feet 1,260,000

* One sweep shut-down for repiping of wells has been allowed. Number of parallel sweeps relates to the width of the field; vertical well spacing relates to the length of the field. * * The length of each linking well has been taken as the requisite horizontal portion (500 feet) plus 1612 feet of drilling along a circular arc.

4-22 SYNTHETIC FUELS REPORT, DECEMBER 1982 mixed steam and oxygen to the injection wells. The shaft horsepower is estimated to be about Gas production lines were assumed to be carbon 41,000. steel, insulated for heat conservation and personnel protection. Shift Conversion System

3. Feed Gas/Solids Separation The feed gas was assumed to contain 25 mole percent hydrogen and 55 mole percent carbon Raw gas was assumed to be directed through monoxide. For the synthesis of methanol a multiple parallel trains of dry cyclones located ratio of H 2 :CO of 2.17:1 is required. There- in the field convenient to the production wells to fore, it is necessary to adjust the H, to CO remove some of the entrained fines and solid ratio in the gas by reacting the CO with steam particles. From the cyclones the gases flow to in the shift conversion unit by using sulfided the knockout drums to further separate addi- cobalt-molybdenum catalyst. tional solids and heavy oil condensate. The oily sludge is sent to the oil treating plant for Two parallel trains are required to process all recovery of oil and tar for fuel use. The gases the gas. Approximately 54 percent of the CO then flow to the gas cleanup system. in the feed gas to the shift unit is converted to H to achieve the desired H :CO ratio of 2.17 4. Gas Clean-up System fo methanol synthesis. 2 Raw feed gas from the feed gas/solids separation Acid Gas Removal System area was assumed to be transferred through two 36 inch diameter gas lines to the gas clean-up Raw well head gas contains a large amount of system. The gas contains residual fines and dust carbon dioxide and is contaminated with other as well as oil and tar. Initial cooling consists of impurities such as H,S, COS, CS,, etc. A recovering heat from the 650°F gas by heat variety of acid gas renfoval processe arc avail- exchange with the feed gas to the CO - shift able, but Allied Chemical's "Selexol" process unit. Standby exchangers were provided to appears to he most suitable purification tech- facilitate frequent cleaning of these heat ex- nology. The Selexol unit consists of three changers. Direct water scrubbing cools the gas absorbers: one to sweeten the MHV required and removes the water, oils and heavy tar, and for fuel gas purposes at 237 psia and the other particulate matter. The oily sludge is separated two to selectively remove the sulfur bearing and sent to the oil treating plant where the oils compounds followed by the bulk removal of and tars are recovered and used for fuel in the CO2 from the main feed gas stream flowing to steam boilers. The oily waste water is sent to the methanol synthesis unit. A Claus unit was the water treatment unit. The scrubbed gas assumed to be used to convert the sulfur com- leaves the clean-up system at approximately pounds into elemental sulfur. 145°F. It was assumed that several parallel trains of raw gas cleanup units are required to Synthesis Gas Compression keep the scrubber size and cost reasonable. After the removal of acid gases, the synthesis In the FGM case about 98 MMSCFD (dry basis) of gas is compressed to 1,500 psig for methanol clean gas is diverted to the fuel gas purification synthesis in a single stage centrifugal com- unit for removal of sulfur bearing impurities pressor driven by a condensing type steam tur- prior to its use as the plant fuel gas. The bine. Prior to compression the gas is desul- remaining gas flows to the gas compression furized in four parallel zinc oxide beds. The system for subsequent methanol synthesis. compression horsepower is estimated to be about 28,500. 5A. Methanol Complex Methanol Plant The methanol processing complex includes all the process units required to convert the clean This plant was assumed to be based on ICI gas into the final fuel grade methanol product. technology which uses a copper catalyst whose All utilities and offsites are also located in this activity allows the synthesis reaction to pro- area so that it can be compared to the MHV ceed at relatively low pressures (down to 735 case. Field injection requirements of steam, psig) and low temperatures (about 460 0 F). The oxygen, etc., are supplied from this area. plant was assumed to consist of two parallel trains, each with two converters, using a com- Gas Compression System mon gas circulation compressor. Gas compression prior to the shift unit is Crude 96 wt % product methanol from the required for process reasons and for synthesis section is fed to two cone roof achieving economic sizes for downstream storage tanks which are sized to hold up to 7 equipment. The scrubbed gas from the clean- days of production. up system is compressed from 237 psia to 655 psia in a single stage centrifugal compressor A methanol distillation unit for further purifi- driven by a condensing type steam turbine. cation of the methanol product was not in-

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-23 eluded. Product pumping units were included Air Separation System to feed methanol into a pipeline at a pressure of 500 psig. The air separation system was assumed to consist of two trains of packaged air distillation Fuel Gas Purification System units to supply 5603 short tons of oxygen per stream day. The separated nitrogen will be The methanol manufacturing complex was vented directly to atmosphere or used, in the designed to completely provide for its own FGM ease, for stripping CO 2 from the Selexol requirement of fuel gas for steam and power solvent and for providing an inert gas blanket generation. Calculations of energy balances on the product methanol storage tanks. indicate a net requirement of about 98 MMSCFD of medium heating value gas (in Capital Cost Estimates addition to 92 MMSCFD purge gas from the methanol plant). However, before the gas The capital estimates for the FGM and MHV cases are can be used it must be treated to remove summarized in Table 4. The costs of the following items sulfur bearing impurities. are included:

The "Selexol" process was selected for this Process, utilities, and offsites complex duty because of its ability to selectively remove H 5, COS, CS , etc., without simul- Engineering taneously emoving bSlk quantities of CO This purification unit was completely intä- Construction overhead including the plant startup grated with the main "Selexol" acid gas removal unit included in the Methanol complex. Contractor's fees The integration of these two systems achieves a highly efficient and cost effective Site development design. The treated fuel gas has a heating value of 323 BTIJ/SCF LHV and is available Gas gathering at a pressure of 230 psia for use in the steam boilers. Special charges including royalties and taxes SB. Medium Heating Value Gas Complex Contingencies

The plant facilities are designed to produce for The costs of the following items are not included: export 438 MMSCFD of MEW with a lower heating value of 323 BTU/SCF and are based on an Land and coal field identical coal field gasification arrangement to the one utilized in the FGM Case. The field Coal gasified in situ gasification facilities, therefore, generate exactly the same quality and quantity of gas per Working capital day in an identical mode of operation. As in the FGM Case the MHV complex is also designed to All costs are expressed in early 1981 dollars and no generate all of its own operating utilities. escalation is included beyond this time period. These cost Approximately 157.2 MMSCFD of treated MHV estimates have an accuracy of -- 25 percent. gas is used to provide the steam and the electrical power requirements of the MHV complex. Operating Cost Estimates The feed gas/solids separation system, the gas clean-up system, and some of the offsite systems Table 5 summarizes the approximate annual operating for the MHV Case are the same as for the FGM costs for the two eases. The costs of the following items Case. However, the acid gas removal system is are included: less complex and the utilities requirements are substantially lower. Compression of MEW pro- Drilling costs based on averaging the entire cost of duct is not included so the MHV product gas is drilling wells for 20 years exported from this complex at 210 psig and at 80°F. Field moves MHV Gas Purification System Make-up water at $1.10 per 1000 gallons

The feed gas to this Selexol-based unit is Catalysts and chemicals contaminated with H 2 S 1 COS and CS,, etc., which must be removed prior to export or its Other operating materials and supplies use for plant fuel gas. Bulk CO removal is not needed because the export pr%duct gas is Plant maintenance materials and labor not required to have a high heating value. Multiple trains of equipment are required to Operating labor and supervision process the large volume of sour gas. General and administrative overhead

Miscellaneous items

4-24 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 4 CAPITAL COSTS FGM MLIV Case Case Million $ Million $ Process Site Development 7.1 7.1 Gas Gathering & Pipelines 3.7 3.7 Gas/Solids Separation System 23.0 23.0 Gas Cleanup System 18.9 18.9 Gas Compression System 24.0 Not Required Shift Conversion System 19.2 Not Required Acid Gas Removal System 52.4 27.6 Synthesis Gas Compression and 57.6 Not Required Methanol Plant & Product Storage Sulfur Recovery System 2.8 2.8 Air Separation Unit . 98.3 98.3 Steam Generation and 56.0 39.5 Power Generation System Water Treating Plant 5.5 3.4 Oil Treating Plant 0.1 0.1 Offsites 90.0 55.0 Engineering 46.0 28.0 Construction Overhead & Plant Start-up 34.4 21.0 TOTAL BARE PLANT COST 539.0 328.4 Contingencies at 15% of Bare Plant Cost 80.8 49.3 Contractors' Fee at 3% of Bare Plant Cost 16.2 9.8 Special Charges 33.0 19.7 TOTAL 669.0 407.2

TABLES OPERATING COSTS FGM Case MHV Case Million $/Yr Million $/Yr Raw Water Make-up 1.0 0.4 Catalysts and Chemicals 6.0 0.2 Drilling of Wells 22.0 22.0 Field Moves 2.0 2.0 Miscellaneous 11.0 6.7 Operating Labor 5.9 3.6 Labor Burden 2.1 1.3 Supervision 1.2 0.7 Operating Supplies i.s 1.1 General Administration Overhead 9.6 5.9 Mainenanee Materials and Labor 26.8 16.3 TOTAL 89.4 60.2 Maintenance costs are estimated at 4 percent per year of depreciable capital. Labor cost is estimated at an average of $12.75 per hour. Labor burden is 35% of direct labor. Supervision cost is 15% of labor plus labor burden. Operating supplies are 30% of direct operating labor. Overhead is 135% of direct labor plus supervision.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-25

The costs of the the following items are not included: TABLE I Plant depreciation DESIGN COAL ANALYSIS (Illinois #6) Interest on debt Taxes of any kind PROXIMATE ANALYSIS, Wt% Product sales costs Moisture 4.2 Cost of coal gasified in situ Ash 9.6 Fixed Carbon 52.0 Credit for sulfur product Volatile Matter 34.2 100.00 Economic Analysis ULTIMATE ANALYSIS - MAP COAL Wt% Using the data and methods established by Gulf, it was determined that the following product prices will yield Carbon 7.26 a 12% discounted cash flow rate of return: Hydrogen 75.92 Oxygen 1.14 FMG Case MHV Case Nitrogen 11.39 Sulfur 4.29 $/ton, Methanol 158.47 100.00 $11000 SCF, MHV Gas --- 1.142 Cents/gallon, methanol 53.1 HEATING VALUE - AS RECEIVED $/la BTU, LHV 9.79 3.535 Higher Heating Value, HHV, BTU/lb 12,235 (KJoules/Xg) (28,426) For comparison purposes, the estimated costs proposed aboveground projects to produce substitute natural gas Net Heating Value, LHV, BTU/lb 11,709 (5MG) are as follows: (KJoulcs/Kg) (27,204) Great Plains WyCoalGas Project Project necessary to devolatilize the remainder of the incoming coal to form a char and to react the char with steam to $1106 BTU 5.50 14.65 form the product gas. This raw gas is then cooled, quenched with water, and treated with the proprietary SELEXOL acid gas removal, Claus sulfur recovery, and Beavon-Stretford tail gas treatment processes. COMBINED CYCLE PLANT ECONOMICS USING AIR The Westinghouse coal gasification technology has been AND OXYGEN BLOWN GASIFIERS developed by Westinghouse with support from the U.S. Department of Energy and the Gas Research Institute. Westinghouse Electric Corporation has evaluated the Westinghouse has demonstrated the process in a 24 TPD economics of air and oxygen blown coal gasifiers for pilot plant at the Westinghouse Waltz Mill site in Madison, combined cycle plants. The results of the study were Pennsylvania, since 1975. The plant has accumulated recently summarized by Carl W. Schwartz at the more than 7,000 hours of hot operation on a variety of A.I.Ch.E. conference in Anaheim, California. The title carbonaceous feedstocks. Operating experience in the of his paper was "A Comparison of Air and Oxygen pilot plant has proven the use of a wide variety of coal Blown Coal Gasification for Combined Cycle Plants." feedstocks and petroleum coke in an air or oxygen-blown The study compared a 650 MW, base load, combined configuration. The process produces virtually no tars in cycle power plant. Two types of Westinghouse the product gas and is efficient because high carbon gasifiers, air blown and oxygen blown, were evaluated conversion is achieved with low use of oxidant and steam. in the study. Differences in performance, cost, and Normal pilot unit operation is at 1687 kPa (230 PSIG). A configuration were presented. schematic representation of the Westinghouse pilot unit is presented in Figure 1. Westinghouse plans to demonstrate Process Description the technology at a commercial scale at Sasol Two in South Africa. (Refer to the article entitled "Activities at Both plant designs were based on using approximately Sasol One, Two, and Three" in this issue of the Pace 240 TPH of Illinois No. 6 coal with a higher heating Synthetic Fuels Report for a description of the demon- value of 12,235 BTU per pound. The characteristics of stration pro)ect.) this design coal are summarized in Table 1. In the Westinghouse gasifier, coal is pneumatically Westinghouse lists the following advantages of their coal transported from lockhoppers into the gasifier through gasification technology: a central feed tube, where it combusts and reacts with an oxidant (oxygen or air) and steam. The combustion • The moderate temperatures employed minimize of a portion of the incoming coal provides the heat materials selection problems and extend refractory life.

4-26 SYNTHETIC FUELS REPORT, DECEMBER 1982 Coal Fine Ash Lock Lock Agglomerating Fines Quench Hoppers Hoppers Gasifier Cyclones Scrubber Ash Lock Hoppers o-- r—, Coal 300° 1850oF I CO, Recycled / Quench Fines WaterI COz 4oO°F Raw Gas to Cooling Tower Quench Scrubber

Steam— 41900°F

Recycled A Char/Waler Slurry T to Waste Processing Gas _ Transport Transport 500° F Gas Gas Steam/Oxygen

Ash to Disposal FIGURE 1 PROCESS FLOW SCHEMATIC

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-27 3 These moderate temperatures are high enough to the air blown case is larger because of the increased avoid tar and oil production, thereby avoiding volume of gas processed. potential inplant toxicity hazards as well as the high capital and operating costs of the required The most significant differences between the two con- tar-oil cleanup systems. ceptual plants is that the oxygen blown system has an air separation plant. For the study Westinghouse assumed • Many coals can be processed in the Westinghouse that two air separation plants, each with a capacity of fluidized bed. 1750 tons/day would be used. A liquid oxygen storage facility capable of providing one day's oxygen supply was S The fluidized bed rejects ash as a dry, granular, also included. and environmentally benign material. No slag handling systems are necessary. A booster compressor was assumed to supply the air for the air blown system. This booster compressor uses • Ground run-of-mine coal can be utilized in the approximately 12% of the main compressor air flow from fluidized bed with no fines rejection because of the combustion turbine system and increases the pressure size. from 210 psig to 380 psig to supply the gasifier. The air flow from the booster compressor is split into two • The large inventory of carbon in the bed provides streams: one stream at 230°F is used to pneumatically operational stability and ease of control, yet convey the coal feed into the gasifier and the other responds to process load demand changes. stream is heated to 650°F and used as the oxidant for the gasifier. This configuration requires a startup air Com- • The moderate operating temperature of the pressor with an electric motor drive and a larger gas Westinghouse gasifier offers the advantage of turbine air compressor than is needed for a conventional lower oxygen requirements per unit weight of turbine. Eight Westinghouse gasification trains are coal feedstock. required for the air blown system, compared to five trains required for the oxygen blown system. Each gasification • The Westinghouse gasifier has the flexibility of train consists of a coal feed, gasifier, particulate using air or oxygen for producing low- or recovery, heat recovery, and gas quench system. The medium-BTU gas, respectively. difference between the two gasifers is that air is used to transport the coal to the reactor in an air blown system, The conceptual plants were designed to use a coal and recycle gas is used to transport coal in the oxygen gasification combined cycle (CGCC) system which com- blown case. bines the technologies of producing a fuel by Sal gasification with a combustion turbine/steam turbine In the Westinghouse gasifiers, the coal, char fines, steam, power plant. The hot exhaust gases from the combus- and oxidant enter through a feed system located in the tion turbine are used to generate steam for use in a ash annulus and form a jet where the coal and oxidant (air steam turbine. Both turbines are coupled to generators or oxygen) react. The coal is quickly devolatilized and to produce electricity. To produce 650 megawatts of partially combusted forming char, the gasifier bed power, four combustion turbines and one steam turbine material. As the carbon is removed from the char, a high are required. Combustion turbines with rotor inlet ash material is formed which softens at high tempera- temperatures of 2065°F were used for both designs. tures. The softened ash causes the ash particles to The steam cycle is a 2400 psig, 950°F system with agglomerate into large, dense particles that sink into the 950°F reheat. char ash separator region of the gasifier. The agglo- merates are cooled by the incoming fluidizing gas and The plants were designed to meet environmental continuously removed via a rotary pocket feeder and regulations for power plants as specified in the Environ- delivered to the ash handling system. mental Protection Agency's "Standards of Performance for New Stationary Sources: Gas Turbines." This rule The product gas, containing virtually no tars or oils, exits establishes sulfur dioxide and nitrogen oxide emissions the reactor at approximately 1800°F. Entrained solids in limits of 0.4 lb SO per million BTU (HEW) of coal the hot gas are collected by primary and secondary input, and 0.08 lb RO per million BTU (UHV) which cyclones. The fines enter an exchanger where the solids corresponds to a NOx c6ncentration of 38 ppmw. are cooled to 1200°F by a recirculating heat transfer medium and are then pneumatically returned to the The overall block flow diagrams for the air and oxygen gasifier by recycled product gas. The fines coolers heat blown CGCC plants are shown in Figures 2 and 3 exchange media is used for generation of 600 psia respectively. Additionally, Table 2 compares the saturated steam. number of processing trains and the operating conditions for both the air and oxygen blown configurations. The raw gas heat recovery system is designed to cool the The basic differences between the air and oxygen blown gasifier product gas and recovery sensible heat from the configurations are primarily in the gasification and gas raw gas to improve the overall thermal efficiency of the processing areas. Both designs incorporate identical plant. - The system, consisting of a raw gas heat exchanger size modules of gasifiers, cyclones and heat recovery (aCHE) evaporator and a steam superheater, cools the gas systems. Coal and recycle fines feed systems are sized to approximately 450°F prior to the gas quench system. to reflect the differences in capacities. Tail gas The steam from the fines coolers is combined in a steam treating, sulfur recovery, and water handling systems drum with the saturated steam from the RGHE. The are very similar, but the acid gas handling system for saturated steam at 600 psig will be superheated to 750°F before use in the steam turbine. A portion of this product

4-28 SYNTHETIC FUELS REPORT, DECEMBER 1982 Flue Gas to Atmosoh.re

eon psiaF Heat i_I Steen H R8 F W7 I Recovery I Turbine I Steam I I ____ 1-ri ®Generetor I-I ® I Transport Apr I I Cit Booster I I Combustton compressor I .s4 Turbine —4 420 2m 24OTons/Hr I I Hester I from Coal ______..j I Preparetton I i______IAll Or Gasification BFW LAIr ___r II Steam___ I ___ t Coal Coal IParliculatel I e.t Gas I 'Acidees II Beavon I II II Cleus I Stratford I I Pressuriretion 1.1 Oesifal.on .1 Recoirery I I Recovery 'tel Quench 1I Removal I-al Sultur 11 Tail 0., I I II I II II ® II155*OLhlIt0nIITeeltnentI $ RecycleGa j I I Sultur Treated Tail lsSTons/Day euro IAsh I I Process I Abno,phere Mending Condensate I Ammonia I I Treatment TonsiDay I Net Power Output Sludge 656 MW Aunts to Disposal Disposal 539 Tons/Day Heat Rate 8946 BTU/KW-HR

FIGURE 2 AIR BLOWN COAL GASIFICATION COMBINED CYCLE

Flue Gas to Atmos$phere

eon pve. 900 F Heat I I Steam I H P FW. I Aecovary 11 Turbine I ® Steam Genraetor I I I Cit I t2045MW I _ Air I Combustion I I eGasue as. Turbine MW 240 Tone/Hr I separation I I Heater I Preparation I_I I Steam or Gasification OFW It ____ Coal Coal Ijpertscuiete II Heat Gas I 'AcldGas' I oaua II Baron I I Prasaurlzatlon Gasification Recovery Recovery Stratford I of l.l a Quench I...l Removal I _..I Sulfur I—I Tail Ga I II_ ®II_@11 I®Ill______XOLlIIReconrYIITmeter4,,5I I f RecycleGas Suitur Treated Tad Tons/Day Garth, A 0 process I Atmosphere Handl,ng I Condensate I Ammonia I Treatmant 83 Tons/Day

Net Power Output Sludge 624 MW Ash to to 015005.1 OiWoaal S39Tona/Day Heat Rate 9411 BTU/KW-HR

FIGURE 3 OXYGEN BLOWN COAL GASIFICATION COMBINED CYCLE

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-29 TABLE 2 COMPARISON OF AIR AND OXYGEN BLOWN CGCC FACILITIES

Case A Case B Air Blown Oxygen Blown NUMBER OF TRAINS: Coal Receiving and Conveying 1 1 Coal Preparation 2 2 Coal Pressurization 8 5 Gasification 8 5 Ash Handling 8 Particulate Recovery 8 S Raw Gas Heat Recovery 8 5 Gas Quench/Ammonia Removal 4 3 Acid Gas Removal 4 3 Recycle Gas Compression 4 3 Combustion Turbine Generator Sets 4 4 Combustion Turbine Exhaust Heat Recovery Steam Generators 4 4 Reheat Steam Turbine Generator Set 1 1 Sulfur Recovery 1 1 Sulfur Recovery Tail Gas Treating 1 1 Tail Gas Compression 1 1 Process Condensate Treating (Ammonia Recovery) 1 1 Primary Water Treating 1 1 Demineralization and Deaeration 1 1 Cooling Water 1 1 Effluent Water Treating 1 1 Air Separation None 2 OPERATING CONDITIONS: Gasifier Capacity, TPH 30 48 Gasifier Outlet Pressure, psig 340 340 Gasifier Outlet Temperature, OF 1800 1800 Product Gas Flow to RGHE lb/hr 1,978,032 1,195,717 Raw Gas Heat Exchanger Inlet Temp, O F 1800 1800 Superheat in RGHE, OF 750 750 Steam Production Rate in RGHE, lb/hr 918,223 555,064 Mole % 0 in Gasifier Oxidant 21 95 Fuel Gas 8leanup Temp., °F 100 100 Product Fuel Gas to Turbine lb/hr 1,751,628 719,726 Fuel Temp. Turbine, O F 600 600 Gas Turbine Firing Temp., °F 2065 2065 Gas Turbine Exhaust Temp., O F 996 997 Ambient Conditions (59°F) ISO ISO Gasification Plant Steam Conditions psi/°F 600/750 600/750 Power Plant Steam, psi/°F/°F 2400/950/950 2400/950/950 Stack Temp., OF 280 280 Condenser Pressure, inches 9H 2.5 2.5 Net Efficiency % 38.7 36.8 Heat Rate, BTU/KW-hr 8946 9411

At Rotor Inlet

4-30 SYNTHETIC FUELS REPORT, DECEMBER 1982 steam is used to supply the gasifier process steam electric costs at the busbar because operating costs were requirements. The air blown gasifier requires approxi- not generated, and because coal costs, water, sludge mately 12% more steam than the oxygen blown system, disposal, and ash disposal costs are too site specific. per unit coal feed. Several factors that affect the economic analysis of a The gas quench system cools the product gas exiting the CGCC plant were addressed by Westinghouse. One factor heat recovery system and removes the remaining parti- that is extremely important is the plant capacity factor culate matter. A venturi scrubber cleans the gas prior because many of the project costs are essentially fixed. to the particulate scrubbing quench tower in which the An enhanced plant capacity factor will result in reduced product gas is cooled by direct countercurrent water unit product costs. Financing arrangements will also have contact in the packed bed. The scrubber bottoms slurry a major impact on project viability. A key consideration is processed in a pressure filtration system. is the amount of leverage a project can obtain through debt financing. Other considerations include the return The cleaned product gas is reheated to 600°F and is on equity required by the project sponsors, interest rate piped to four combustion turbines. Each combustion on debt and, loan repayment period. Another major turbine generator set produces electricity and provides consideration in the economic analysis is taxes, parti- exhaust gas at approximately 1000°F for use in its cularly investment and energy tax credits. associated heat recovery steam generator, which produces steam for the main reheat steam turbine. A comparison of the capital costs of the two conceptual CGCC plants is presented in Table 3. One major cost The heat recovery steam generator receives the difference is the air compression costs for the air blown exhaust gas from the combustion turbine. The gas is CASE A, and the cost of an air separation plant for CASE into two parallel flowpaths. In the first module, the gas B. For CASE I, the $8.8 million represents the cost of flows over the superheater tubes and the intermediate- four booster compressors, whereas for CASE B, the $80 pressure reheat tube bank. The gas then flows across million represent the cost of two 1750 ton/day air separa- the tubes in the evaporators, economizers, and the low- tion plants and liquid storage capacity of 3500 tons of pressure evaporator before being exhausted to the oxygen. atmosphere. The costs of the coal gasifiers are also substantially The steam turbine generator used in the study is a different due to the number of gasifiers that are needed state-of-the-art machine, operating at 3600 rpm. The (8 versus 5) for the two cases. Sulfur recovery, acid gas steam turbine consists of a common high-pressure, removal, tail gas treating, process condensate treatment intermediate-pressure cylinder and a low-pressure, and waste water treatment all have slightly higher capital double-flow cylinder exhausting to a condensor at 2.5 costs for the air blown system because the units handle inches mercury absolute. 60% more gaseous flow. The cooling water system costs for the oxygen blown system is higher because of the air tal Cost Estimates separation plant. Effluent water and wastewater treatment costs are about the same in both eases. Budgetary capital cost estimates for both conceptual plants were prepared by Westinghouse from data con- The combined cycle power generation system for the cerning similar installations or from equipment cost oxygen blown system has a 10% higher capital cost than estimates. The capital costs include all material and the air blown case due to the added complexity of the labor necessary to install a module that is connected to steam injection for NO control. The air blown system the adjacent areas with process lines and utility CASE A requires no steam injection for NO control. supplies. Specific items in the basis for the capital Steam is injected into the medium BTU gas to 'lower the costs of the plants include: combustion flame temperature and, hence, the low BTU gas acts as a diluent and prevents the combustion tem- • Purchased equipment and freight for all process perature from reaching NO formation level. equipment The overall performance of the two conceptual plants are • Direct construction labor summarized in Table 4. The air blown system produces less power in the combustion turbine, more power in the • Intra-area piping and electrical equipment steam turbine, and slightly less power overall (1% less). However, the air blown system produces 5% more net O Instrumentation power because the lower gross power output is more than offset by the higher auxiliary power consumption of the • Foundations, piling, excavation oxygen blown system. • Structural steel, erected The air blown gasification system has higher electrical requirements for the gasification area, acid gas removal, • Control room sulfur recovery and tail gas treating, process condensate treating, utility subsystems, and off-site facilities. These However, the estimates have no land or site develop- higher requirements, are due to the larger volume of ment costs, preproduction, inventory, initial catalysts product gas flow. However, the large power requirement and chemicals, royalties 0: taxes included in the total for the air separation plant more than offsets the cost. Also, Westinghouse made no attempt to estimate increased power requirement of three more gasifiers and handling a larger flow in the gas cleanup systems.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-31 TABLE 3 COMPARISON OF SYSTEM CAPITAL COST ESTIMATES

Case Case Air Blown Oxygen Blown Plant Area 1981 Installed Cost ($ M, Coal Receiving and Conveying 9.0 9.0 Coal Preparation 14.0 14.0 Oxidant Compression, and Air Separation Plant for Case B 8.8 80.0 Coal Pressurization, Gasification, Particulate Recovery, 136.0 90.0 Ash Handling, Raw Gas Heat Recovery, Gas Quench, and Recycle Gas Compression Sulfur Recovery and Tail Gas Treating 21.2 18.2 Acid Gas Removal 19.9 16.5 Process Condensate Treating and Ammonia Recovery 26.1 23.4 Primary Water Treatment 8.7 6.6 Waste Water Treatment 4.4 4.0 Cooling Water System 14.4 17.2 Effluent Water Treatment 2.5 2.2 Combined Cycle Power Generation 130.0 143.0 Flare, Instrument Air, Fire Protection, etc. 4.6 4.6 PROCESS PLANT SUBTOTAL 399.6 428.7 Of fsitcs: Office bldg., maintenance shop, lab, warehouse, 40.4 43.6 reagent and byproduct storage, personnel facilities. Engineering, home office costs, fee, and project management 44.1 47.5 Contingencies (25% of Process Plant Cost) 99.9 107.2 TOTAL PLANT INVESTMENT $ 584.0 $ 627.0

TABLE 4 PLANT PERFORMANCE SUMMARY CaseA Case Parameter Air Blown Oxygen Blown Coal Feed Rate, tons/hr 240 240 Coal Energy In (HHV) x 10 BTU/hr 5,873 5,873 Combustion Turbine Output, kw 420,199 444,373 Reheat Steam Turbine Output, kw 280,540 264,453 Total Gross Power Output, kw 700,739 708,826 Auxiliary Power Consumption, kw Coal Handling and Preparation 4,020 4,020 Oxidant Compression and Air Separation for Case B 12,000 56,000 Coal Pressurization, Gasification, Particulate Recovery, 12,000 7,500 Ash Handling, Raw Gas Heat Recovery, Gas Quench, and Recycle Gas Compression Acid Gas Removal 2,500 2,000 Sulfur Recovery and Tail Gas Treating 1,230 950 Process Condensate Treating and Ammonia Recovery 150 125 Utility Subsystems 4,400 4,000 Off-Site Facilities 980 800 Combined Cycle Power Generation 6,400 8,860 Miscellaneous 660 550 Net Power, kw 656,399 624,021 Heat Rate, BTU/kw-hr 8,946 9,411 Overall Thermal Efficiency, % 38.1 36.3 Heat Rate, BTU/kw-hr 8,946 9,411 Installed Cost $/kw-hr 890 1,005

4-32 SYNTHETIC FUELS REPORT, DECEMBER 1982 The analysis also found that for NOx control in the combustion turbines has little effect on plant efficiency. Although this steam would have produced power in the steam turbine, it increases the mass now to the combustion turbine which in turn produces more power. Hence, it appears to be a tradeoff of producing power in the topping cycle or the bottoming cycle. Conclusions The Westinghouse study concluded the following: • The air blown coal gasification combined cycle system (CCCC) is more efficient, less expensive, and involves less design complexity than a similarly designed oxygen blow system. • The lower plant thermal efficiency and higher capital cost for the oxygen blown system is due to the air separation plant. • The preliminary form of the estimate warrants a more thorough investigation and site specific conditions may shift the economic comparison toward the oxygen blown case in certain circumstances. • The Westinghouse coal gasification process can use air or oxygen to produce fuel gas. • Five coal gasification systems are required for the oxygen blown plant compared to eight gasification systems for the air blown plant. • Environmentally, sulfur and ammonia removal will be similar in the oxygen blown plant and the air-blown plant; however, NOx formation is higher for an 0 2-blown plant. Excess NO formation can be controlled by steam injectioA into the combustion turbine but the complexity of the plant design will be slightly increased.

• Steam injection for NO control does not deter from overall plant thern?l efficiency. • The exclusion of air separation plants for energy tax credits eligibility is a severe investment penalty.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-33 TECHNOLOGY

USE OF BATFELLE TREATED COAL TO PRODUCE ing, and desulfurization steps would save money, reduce LOW-SULFUR FUEL GAS complexity, increase thermal efficiency, and improve the load following characteristics of the gasification system. At the National Meeting of AIChE in Anaheim, Califor- nia, a paper was presented entitled "Preparation of Test Results Low-Sulfur Fuel Gas by Gasification of Battelle Treated Coal." The paper included a description of the Initial tests using ETC were conducted in a small 1.5-inch process, a discussion of recent test results, and an diameter reactor that was operated to simulate a fixed analysis of a conceptual commercial scale facility. bed gasifier. These tests demonstrated the following: Process Description 1. Sulfur retention by the ash was sufficient to eliminate the need for gas cleaning. The Battelle Treated Coal (BTC) process involves the aqueous processing of ground coal and calcium-com- 2. The gasification reactivity of the BTC was sub- pound catalysts at elevated temperatures and pressures. stantially higher than that of the raw coal. For a high sulfur Illinois No. 6 coal, the researchers have found that relatively mild treatment conditions 3. The sulfur retained by the ash (as calcium sulfate) rendered the coal non-agglomerating, highly reactive, was stable and would not be leached out. resistant to slagging, and conditioned for sulfur capture. The chemical and physical properties of the raw 4. Because the gas can be used hot, environmental and treated coals are compared in Table 1. problems associated with water contamination would be reduced (or eliminated) compared to The data in Table 1 indicate that the volatile fraction conventional gasification systems. in the coal is increased by the addition of the calcium. The researchers theorize that the calcium poisons the 5. Agglomeration of the ETC was not a problem. coal polymerization reactions, thus reducing the amount of residual carbon that is formed during gasifi- 6. The economics of using ETC for industrial steam cation. Additionally, the amount of calcium added to generation in a commercially available fixed-bed the coal is sufficient to capture over 90% of the sulfur gasifier was estimated to be more attractive that in the raw coal. the following options. Although ETC is suited for use in many types of • Direct coal combustion and flue gas desulfuri- gasifiers, BTC is believed to be particularly well-suited zation (FGD) by fixed bed processes. Use of these fixed bed units is often constrained by the high cost of environmental • Gasification followed by combustion of the gas control equipment and by limitations of coal reactivity, and FGD agglomerating tendency, slagging characteristics, tar production, and feed coal particle size. The ETC • Gasification followed by H removal. process produces highly reactive, non-agglomerating, 2 non-slagging briquettes that can be gasified to produce Based on the batch tests, larger scale continuous tests low-sulfur, tar-free fuel gas. were conducted at the University of Kentucky's 8-inch diameter fixed-bed gasification facility. BTC pellets The researchers believe fuel gas produced from BTC is were fed continuously via a screw feeder and fell into the suitable for direct use in tunnel kilns, basic refractory 8-inch I.D. by 12 feet deep, refractory lined, cyclindcrical kilns, steel-making furnaces, glass-making furnaces, shell gasifier. The pellets were allowed to pass through rotary zinc kilns, antimony concentrators, rotary lime drying, pyrolysis, gasification and combustion zones until kilns, aluminum melting, foundary rolling mills, forging a bed depth of approximately 5-feet was obtained. Ash applications, reheat and annealing furnaces, anode was removed via a drain pipe and valve located below the baking, holding furnaces, steam production, etc. The grate to maintain a constant bed height. Steam and air ash removed in either a dry or wet state contains the flow rates were measured, the gases preheated and then sulfur in the stable calcium sulfate form. Leaching passed through the rotatable grate. Temperatures in the tests using the standard Toxicant Extraction Process gasifier were monitored by thermocouples. have indicated the ash is non-toxic and non-hazardous. The hot gases exiting the top of the gasifier first passed Processing the BTC in a pressurized, oxygen-blown through a six-foot long disengagement chamber where gasifier could have many advantages for the production most of the entrained char and ash were deposited. The of a hot, low sulfur, pressurized medium-BTU gas for dedusted gas then passed to either a 2 x 2 x 6 feet baffled combined cycle-cogeneration operations. The incinerator, or a two stage wet scrubbing system followed researchers believe elimination of the costly gas cool- by the incinerator.

4-34 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE I COMPARISON OF RAW AND BA'VFELLE TREATED COAL CHEMICAL AND PHYSICAL ANALYSES (DRY BASIS) Raw Coal(a) Battelle Treated Coal Ultimate Analysis, Wt. % Carbon 69.74 50.81 Hydrogen 4.81 4.15 Nitrogen 1.23 0.94 Chlorine 0.28 0.19 Sulfur 5.00 2.91 Ash 11.24 34.97 Oxygen 7.70 6.03 Calcium Content, Wt. % 0.40 14.31 Calcium/Sulfur, Mole Rates 0.06 3.93 Proximate Analysis, Wt. %

Fixed Carbon 49.07 27.88 Volatile Matter 39.69 37.19 Ash 11.24 34.93 - Volatile Matter/Fixed Carbon 0.81 1.33 Higher Heating Value, BTU/lb 12,530 8,732 Initial Ash Softening Temperature, °C 1100 1500

Free Swelling Index 2.5 Non-Agglomerating

Illinois No. 6 coal, Christian County, Illinois, Peabody No. 10 mine.

A small slip stream was taken from the disengagement that as the run proceeded the release of sulfur generally chamber for gas analyses. The gases were cleaned in a decreased until a level of approximately 500 ppm was small glass cyclone and a glass wool filter, passed achieved. The majority of the data was obtained by wet through two impingers placed in an ice bath to remove chemical analysis of the fuel gas by the potassium water, and then analyzed for sulfur content. Individual iodide/iodate method. gas samples were also taken periodically for analysis by gas chromatograph and infrared analyzers. A summary of the test run conditions, gas analysis and calculated sulfur release at the end of this fourth run is Four continuous runs were conducted over 40 hours of presented in Table 2. Gas heating values ranged from operating time. The first three runs established the 156-173 BTU/SCF. Because of the small size of the unit ease of operation, elimination of oil and tar production, heat losses were substantial resulting in lower gas heating and low sulfur emissions. The BTC feedstock was also values, but the researchers believe that commercial shown to be non-agglomerating and have a very high ash operation in a more adiabatic mode should result in a gas fusion temperature thus permitting higher than normal heating value of 185 - 200 BTU/SCF. Carbon conversion bed temperatures and, hence, greater carbon conver- was high at over 90 percent. sion, faster reaction rates, and greater carbon-carbon dioxide conversion without encountering slagging The sulfur release data indicate that only 17 percent of problems. The ash particles retained much of their the sulfur fed with the BTC was emitted with the fuel gas original pellet shape indicating that these particles even at relatively low bed depths. As the run continued, maintained their integrity under gasification conditions. the sulfur release fell to values less than 10 percent which Char and ash particles entrained with the fuel gas were is significant because it meets the revised New Source approximately the size of the raw feed coal used in the Performance Standards (NSPS) issued by the U.S. BTC treatment. These char loadings were significantly Environmental Protection Agency in 1978. The NSPS for higher than those experienced with raw coal indicating el%ctrie utility boilers with capacities greater than 250 x that some particle disintegration oceured either during 10 BTU/hr heat input requires a 90 percent reduction. gasification or in the screw feed auger. This sulfur reduction can be achieved by all types of SO2 and sulfur removal technology including flue gas desul- The final run was more heavily instrumented to deter- furization systems and fuel pretreatment systems (such as mine the release of sulfur with the fuel gas. This test coal cleaning, coal gasification, and coal liquefaction). indicated that the fuel gas initially contained between Therefore, the researchers conclude that the data mdi- 1000 and 2000 ppm sulfurous gases (H 2S, COS, CS2) and

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-35 TABLE 2 foot diameter fixed-bed gasifiers) was utilized in the analysis. SUMMARY OF FINAL RUN CONDITIONS AND SULFUR RELEASE IN Capital and operating cost estimates were based on design FIXED-BED GASIFICATION OF data established through the batch and continuous BTC BA'rFELLE TREATED COAL treatment studies. Total capital investment for briquetted-BTC (including captial costs, startup costs and working capital) were BTC Rate, lb/hr 66 estimated to be $24.3 and $25.8 million, for Ca/S ratios of 1.5 and 3.0 respectively. Operating costs were based on BTC Composition, wt. % high sulfur (.r 5 percent) coal delivered for $20/ton, treatment chemicals at $45/ton, briquette binder at Moisture 9.0 $100/ton, and electric power costs at $0.04/kWh. Annual Carbon 46.23 operating costs were estimated to be $34.5 and $39.8 Hydrogen 3.78 million per year based on Ca/S ratios of 1.5 to 3.0, Nitrogen 0.86 respectively. Chlorine 0.17 Sulfur 2.65 A discounted cash flow analysis using a 15 percent dis- Ash 31.82 count factor, 20 year life, and 100 percent equity finan- (Calcium) (13.03) cing was performed. The analysis indica4ed that the cost Oxygen 5.48 of treated coal was $42.4/ton ($1.80/10 BTU) including Calcium/Sulfur, Mole/Mole 3.93 operating costs, costs of capital, startup costs and working capital. This analysis assumed briquettes with Pressure, psig Atmospheric heating values of 11,700 BTU/lb would be produced using Steam Rate, lb/hr 8.5 a Ca/S treatment of 1.5. At a Ca/S ratio of 3.0, the BTU Air Rate, lb/hr 111.8 content was assumed to drop to 10,700 BTU/lb and Product Gas Rate (Dry), treated goal costs were calculated to be $44.2/ton moles/lir(SCFH) 6.2 (2,357) ($2.10/b BTU). These treated coal costs are competitive with low sulfur coals and the researchers conclude that Gas Composition, Vol. % (dry) low sulfur fuel gas can be produced at an attractive price. CO 36.3 Gasification Facilities H2 10.0 CH4 1.7 The industrial gasification facilities were designed to take H25 0.05 advantage of the unique BTC properties and the needs of CO2 1.3 smaller industrial facilities using the hot, low sulfur, low N2 49.3 tar, 175-190 BTU/SCF gas directly. Each facility was 02 1.3 designed to produce enough gas for the generation of approximately 250,000 lb/hr of 250 psi steam in existing H.H.V. of Gas, BTU/SCF 167 oil or natural gas fired boilers. Sulfur Release, wt. % 5.7 Carbon Conversion, wt. % 96.2 To design the appropriate size and number of fixed-bed Avg. Bed Temperature, °C 781 gasifiers, the experimental data on gas composition and Max. Bed Temperature, °C 1010 tar production, were combined with conventional fixed- bed gasifier design data. The gasifier facilities envisioned by the researchers would consist of a seven-day BTC receiving storage yard with automatic reclaim system, gasifier building with foundations, two 12-foot single- cate that BTC is a viable method to reduce sulfur stage gasifiers, with hot gas cyclones, coal bunkers which emissions within established NSPS standards. would hold 50-100 tons of coal, coal feeders, ash removal equipment and all instrumentation and controls. Esti- Commercial Scale Facility Analyses mated capital cost of each 488 TPO briquetted-BTC gasification facilities was $4.9 million. The annualized BTC Production Facility gas costs (including operating costs plus capital charges for caital startup and working capital) were To assess the cost of treatment, a preliminary design of $2.80/1 BTU for 1.5 Ca/S briquetted-BTC At a ETC an integrated treatment plant was prepared. The Ca/S ratio of 3.0, the costs rose to $3.10/I0 BTU. Both facility was considered to be a grass-root installation costs were based on a discounted cash flow analysis using located within truck transport distance of the coal a 15 percent discount factor, 100 percent equity finan- mines. Provisions were made in the design for coal cing, and 350 operating days/year. delivery, storage, crushing, treatment chemicals storage and preparation, reaction, solid-liquid separa- The relationship between gas cost and throughput (with tion, drying, briquette preparation and storage. A Ca/S ratio as a separate parameter) is shown graphically central treament plant with a 100 ton per hour coal on Figure 1. The curves show that gas costs are very (dry) capacity supplying BTC for approximately 7 indus- sensitive to both throughput rate and Ca/S ratio. There- trial gasification facilities (each equipped with two 12- fore, in future experimental programs, the researchers

4-36 SYNTHETIC FUELS REPORT, DECEMBER 1982

UJ C ic

0 EACH SYSTEM INCLUDES TWO 12-FOOT GASIFIERS

. 30 50 10 90 110 130 150 170 190 GASIFIER THROUGHPUT, LB/HR-FT2

FIGURE 1 EFFECT OF GASIFIER THROUGHPUT ON GAS COST PRODUCED FROM BTC

plan to evaluate the effectiveness of lower Ca/S treat- Conclusions ment ratios and their effect on gasifier throughput.. Based on the test data from the batch and continuous Cost Comparison to Natural Gas, Fuel Oil, and Coal fixed-bed gasifiers, the Battelle researchers conclude the following: The cost evaluations conducted by Battelle indicate that the cost of low-BTU gas produced from ETC • 80-95 percent of the sufur in the feed coal can be appears economically competitive today and, due to the captured in the coal ash, eliminating the need for stability of high sulfur coal prices, unlikely to inflate as gas desulfurization. rapidly as competing fuels. The cost gf industrial natural gas ranged from $4.00 to $4.50/1 B'EU at the S Tar-free, very low oil fuel gas can be produced, beginning of 1982, compared to $2.80-3.10/10 BTU for greatly simplifying down-stream processing. hot, low sulfur, low BTU fuel gas from ETC gasification. Projections of natural gas costs show upward • Non-leachable sulfur-containing ash can be pro- trends in gas costs. Typical industrial fuel ices for duced minimizing disposal problems. residual fuel oil range from $5.00 to $7.25/11 BTU in 1981 and are projected to increase at 4-8 percent • A 185-200 BTU/SCF gas can be produced, mini- annually. mizing boiler derating and retrofitting problems. Low sulfur coal is estimated to cost $45-55/ton at • Mildly caking eastern coals can be rendered non 12,500 BTU/lb. Based on a discounted cash flow swelling and non agglomerating, extending the analyses, the price for hot deterred fuel gas prruced range of coals acceptable for fixed-bed gasifica- from these coals range from $3.90 to $4.10/b BTU. tion. Gas from low sulfur coal is more expensive because of the higher cost of the coal, lower gasifier throughput • The steam reactivity of ETC is greatly increased (approximately 80 lb/hr-ft ), and cost of gas cleanup to over the parent coal, thus increasing gasifier remove oils and tars. throughput.

SYNTHETIC FUELS REPORT, DECEMBER 1982 • The ash fusion temperatures are significantly in- catalyst. Additionally, nickel catalysts can be deacti- creased compared to the raw coal allowing vated by high temperatures (above 950°F) and by carbon higher temperature operation which produces fouling if the H 2/CO ratio in the synthesis gas is not less carbon dioxide, requires less steam, and maintained above 2.85. Lastly, the nickel catalysts minimizes potential clinkering and slagging require special procedures to maintain activity and can problems. not be exposed to oxygen after activation. • The hot fuel gas can be used directly, elimina- The conventional methanation process can be improved by ting the need for cooling operations, increasing employing combined shift-methanation in which Equations overall thermal efficiency, and eliminating the 1 and 2 occur simultaneously. Hence, the water formed in waste water problem associated with treatment the methanation reaction is used for the water-shift of the condensate collected from unreacted reaction. These processes also use nickel-based catalysts, steam. thus necessitating sulfur removal prior to combined shift methanation. Also, the processes require steam addition and secondary acid gas removal after shift-methanation to remove the CO9 formed by the reaction. A typical STATUS OF DIRECT METUANATION RESEARCH AT combined shift-methanation process is depicted in Figure Gm 2. The Gas Research Institute (CR1) is developing a pro- Direct Methanation cess for converting synthesis gas from coal gasifiers into substitute natural gas (SNG). Howard S. Meyer The direct methanation process being developed by CR1 recently reported on the status of GRFs research in a methanates the raw synthesis gas from the gasifier to paper entitled "Direct Methanation - A New Method of form methane and carbon dioxide from equal molar con- converting Synthesis Gas to Substitute Natural Gas" centrations of carbon monoxide and hydrogen. The presented at a meeting of the American Chemical chemistry of the process is as follows: Society in Las Vegas, Nevada. The process promises to reduce SNG costs by eliminating much of the synthesis 2C0+ 2H 2 --CH4 CO2 gas purification and upgrading that are required for existing coal-to-SNG processes. Although the overall reaction is the same as for combined shift-methanation, the researchers state that the direct Conventional Methanation methanation mechanism appears to be different in that the carbon dioxide is formed directly rather than by the As shown in Figure 1, conventional SNG processes water-gas shift reaction. Therefore, steam is not consist of several steps including coal gasification, required to suppress carbon formation or to drive the synthesis gas quench, gas shift, gas cooling, acid gas water-gas shift reaction. removal, methanation, and dehydration and compression. In the coal gasification step, coal is reacted with The key to the direct methanation process is the develop- a limited amount of oxygen to form synthesis gas ment of new catalysts. Catalysis Research Corporation (hydrogen, carbon monoxide, and impurities). The gas (CRC) is responsible for developing new catalysts for CR1. quench step utilizes water or oils to cool the raw From 1974 to 1978 CRC developed two patented catalysts synthesis gas and to remove particulates, tars, and oils. (CR1 Series 200 and 300) which are sulfur-resistant The gas shift reaction is needed to adjust the composi- methanation catalysts. The program to develop these tion of the synthesis gas to achieve the proper 3:1 ratio catalysts led to a new area of study and eventually to a of hydrogen (H 2) to carbon monoxide (CO) required for new family of catalysts, GRI Series 400 and 500. With methanation. This water-gas shift reaction is as these catalysts, CR1 began its development of the direct follows: methanation process. CO + H 2O - H 2 + CO 2 (Equation 1) Tests to date by researchers at the Institute of Gas Technology (IGT) have shown that the new GRI Series 500 In this reaction, water (steam) is added to the synthesis catalysts can operate with feed gases containing up to 3 gas in the presence of a catalyst to produce additional mole percent sulfur. Carbon dioxide in the feed gases has hydrogen. The acid gas removal step removes water, been shown to retard the total CO conversion, but not carbon dioxide (C0 0), and sulfur-containing compounds. promote any other reactions. No carbon formation was In the methanation tep, nickel-based catalysts are used detected at H /CO ratios from 3.0 to 0.5. The tests have to convert the cleaned, cooled synthesis gas (now demonstrated hat the new series of catalysts promote essentially a mixture containing only CO and H 2) into the methanation reaction at temperatures from 600 0 to methane as follows: 1200°F and pressures from 200 to 1000 psig. Addition of hydrocarbons and ammonia to the feed gases did not 3H2 + CO — CU4 + H (Equation 2) poison or foul the catalyst. Lastly, the researchers state 2 that the catalysts are easy to handle and can be exposed The nickel-based catalysts impose costly process to air with no loss of activity. restrictions to prevent catalyst deactivation. A major restriction is caused by the extreme sensitivity of SRI International has conducted tests to define the bulk nickel catalyst to poisoning by sulfur compounds. The and surface properties of the promising catalysts gas must be purified to concentrations of 0.1 ppm sulfur developed by CRC. The studies at SRI are intended to or below to prevent irreversible poisoning of the relate catalyst microcompositional and morphological

4-38 SYNTHETIC FUELS REPORT, DECEMBER 1982

YORATION PIPELINE COAL — GASIFIER QUENCH SHIFT GAS ACID GAS QUALITY REMOVAL jCOMPRESSI SIC

FIGURE I CONVENTIONAL METHANATION PROCESSING SYSTEM

1 COMBINED 1 FINAL1 jDEHYDRATION PIPELINE COAL -4 GASIFIER OUENCHJ_..._Tb0 GAS SHIFT! QUALITY / L REMOVAL HMNATI REMOVAL H METNANATIO COMPRESSION SNS

FIGURE 2 COMBINED SHIFT/METHANATION PROCESSING SYSTEM

properties to selectivity and activity. SRI has tioning step rather than 3.0 to 3.2 needed foiconventional developed and improved new experimental techniques methanation. Acid gas removal prior to methanation is utilizing (1) x-ray photoelectron spectroscopy (XPS or not needed. The methanation system consists of a series ESCA), (2) scanning electron microscopy (SEM), (3) BET of adiabatic reactors. Next, the CO, and sulfur com- surface area measurements, and (4) x-ray diffraction pounds are removed in any of several cmmercially avail- (XRD). Solid state properties of the catalysts have able acid gas removal systems. A polishing methanation been determined by a Variety of surface science tech- step using a nickel catalyst is used to convert any niques. remaining carbon monoxide. Lastly, the SNG must be dehydrated and compressed as with other methanation Much of the SRI work is classified as proprietary, but processes. Capital cost and operating cost estimates the researchers have discovered a "critical formulation from these conceptual designs were used to develop variable" that controls the specific methanation economic evaluations. Based on a CR1 Series 300 activity. Additionally, the researchers have discovered catalyst, the process was determined to be economically a correlation between methanation activity and quanti- unattractive due to the need for CO., removal prior to tative absorption of ammonia. methanation. However, with GRI Series 400 and 500 catalysts, CO removal is not necessary because of the Process Evaluation of Direct Methanation good activity f the catalysts in streams with high CO concentrations. The goals of the bench-scale tests at IGT are to simulate gasifier effluent gases and to develop process A plant producing 250 billion BTU per day using the direct design data. The effects of space velocity, tempera- methanation process has been compared to a combined ture, pressure, and feed composition have been tested. shift-conversion process. The design of the slagging Lurgi Quench gases simulating the dry-bottom Lurgi, slagging gasifier was the same for both plants, but the downstream Lurgi, Westinghouse, and HYGAS gasifiers have been processing was redesigned to exploit the advantages of evaluated. Typical data for the direct methanation of direct methanation. The advantages include: slagging Lurgi gasifier raw synthesis gases are shown in Figure 3. Synthesis gases containing H /CO ratios less • Reduced plant investment, operating costs, and gas than 1.0 (as with the slagging Lurgi jasifier effluent costs with H /CO = 0.4) were found to require a "precondi- tioning2thift" to increase the ratio to 1.1 - 1.3. • Effective hydrogen utilization

A processing sequence for direct methanation of • One acid gas removal step slagging Lurgi synthesis gases is shown in Figure 4. The process consists of a slagging Lurgi gasifier and quench • Smaller acid gas removal feed stream as with conventional processes. However, the H /CO ratio is adjusted to only 1.1 to 1.3 in the precndi- • Higher energy efficiency

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-39

100

80 075 850 o 950

AD- ou

I I 0 2000 4000 6000 8000 10,000 12,000 14POO 161)00 SPACE VELOCITY, 5Cr/hr-ft3 FEED COMPOSITION, mol % CO 342? CO2 14.43 H 2 37.02 CH, 10.60 C2H 6 0.34 C 3 H 0 0.11 0.05 H 2S 0.98 COS 0.02 N 2 0.33 H20 1.85 TOTAL $00.00

FIGURE 3 CO CONVERSION IN THE FIRST DIRECT METHANATION STAGE FOR SLAGGING LURGI RAW GASES (450 PSIG, GRI-C-525 CATALYST)

FIHA'®IDEHYORATION PIPELINE 'A5ING I r ACID GAS QUALITY -'--p3R LURGI r::' ® UI - QUENCHiOHDITICHING, METHANATIDN' REMOVAL METHANATI0N RgSIQj GAS GASIFIEJ L___J L.. I Stream ® ® © © ® Component Co 50.9 37.8 1.7 4.1 0.1 CO2 6.5 19.1 50.1 0.7 0,0 H2 25.9 35,0 0.7 16.1 4.7 CMI 0.1 5,3 32.3 77.6 02.7 C24 0.5 0.4 0.6 1.5 1.7 H2S 2.1 i.e 2,6 0.0 0.0

I-Iuunt q CONCEPTUAL FLOWSHEET FOR DIRECT METHANATION OF SLAGGING LURGI RAW GASES

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-40

3 Sulfur tolerance goals for the direct methanation projects. These goals include: S Carbon fouling tolerance • Complete optimization, characterization, and Lower process steam requirements laboratory testing of new sulfur-tolerant direct methanation catalysts, to determine their activity * Decreased heat exchange area and selectivity in direct methanation of coal gasifier product gases with 11 2/CO ratios from 0.5 The preliminary results of this process comparison to 2.5. indicate that the direct methanation process could reduce capital costs by 20%, operating costs by 10%, • Develop fabrication techniques for commercial- and SNO cost by 15%. Further savings are expected by size quantities of direct methanation catalysts. the researchers with the development of new subsystems that are designed specifically for the direct • Develop direct methanation processes to use the methanation process. CR1 considers the project to newly developed catalysts, which will contribute to develop direct methanation to be making excellent reducing gas costs by 5 to 10 percent. progress and, if the development continues to be successful, CR1 plans to pursue the process through the The project schedule proposed by CR1 for pilot plant scale. commercialization of the direct methanation process is depicted in Figure 5. In their 1983-1987 Five Year Research and Develop- ment Plan issued in August 1982, CR1 specified their I,

Will 1981 1982 1983 19S4 1985 1988 1987 1988 1989 1990 (f I (11 2 -

7 9 to 4 14 I It S t It It I ii p 4 II 12 13 Ifr EXPLANATORY NOTES 1 Develop 500 Series catalyst. 2 Develop 600 Series catalyst. 3 Develop 700 Series catalyst. 4 Fabricate 500 and 600 Series catalysts. 5 Fabricate 500. 600. and 700 Series catalysts. 6 Develop conceptual process. 7 Develop bench-scale lest. B Design and construct PDU. 9 Operate and test catalysts in PDU. 10 Perform detailed process engineering design. it Perform preliminary cost studies. 12 Perform support cost studies, 13 Perform detailed cost stuoles. 14 Transfer technology.

FIGURE 5 DIRECT METHANATION PROCESS DEVELOPMENT SCHEDULE

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-41 COAL LIQUEFACTION USING BASIC NITROGEN The study of basic nitrogen compounds and their HETEROCYCLIC SOLVENTS interactions with coal will give insight into the structure and nature of coal and the chemistry of Recent laboratory research sponsored by the Electric coal liquefaction. Power Research Institute (EPRI) has demonstrated that, in the presence of basic nitrogen heterocyclic com- Coal Structure pounds, coal can be almost totally converted to liquid products at relatively mild conditions. The results of Based on the results of research conducted by Kay R. this research were recently summarized at the Brower and G. Kolling, the EPRI researchers postulate A.I.Ch.E. meeting in Los Angeles on November 15-19, that the bulk of coal liquefaction reactions do not proceed 1982, in a paper entitled "Advanced Coal Liquefaction" via homolysis (the decomposition of a chemical compound by Linda F. Atherton and Conrad J. Kulik. The into two uncharged atoms or radicals). Because the research may not only lead to improved coal liquefac- reactions in basic nitrogen solvents occur at low tempera- tion processes, but also to improved understanding of tures (550 0 to 700 0 F), the researchers believe the coal coal structure. forms radicals which react with the solvents to form the coal-derived products. Additionally, the research indi- Recent research has indicated that coal may not be as cates that the reduction of carbonyl groups (aldehydes, refractory and polymeric as was originally thought. ketones, carboxylic acids, esters, etc.) may play a critical Rather, the EPRI researchers now speculate that coal role in coal liquefaction. Carbonyl reduction has only a may be comprised of relatively low molecular weight slight effect on molecular weight, but a significant effect units that are held together by hydrogen bonding and on solubilities and chemical and physical properties. weak thermal bonds. Therefore, in the presence of certain solvents such as basic nitrogen heterocyclic Recent EPRI-sponsored research at Virginia Polytechnic compounds at the proper liquefaction conditions, coal Institute, the University of Wyoming, and Kerr-McGee can be converted into liquid products. The term indicate that coal may be a very reactive substance. In "liquids" is defined by EPRI as compounds that are fact, it may be so reactive it can be irreversibly damaged soluble in terahydrofuran (and/or toluene and cyclo- even at very mild conditions such as those encountered hexane). during preparation and drying. The researchers speculate that, based on recent test results, coal may not be Beginning in late 1980, EPRI's research began focusing composed of polyaromatic, heterocyclic, and alicyclic on basic nitrogen solvents,sueh as tetrahydroquinoline structures that are linked by aliphatic and ether bridges. Q1 ) and piperdine ( Q ). With these solvents, coal Rather, coal may be composed of relatively low molecular has been repeatedly converted to compounds that are weight units held together by hydrogen bonding and weak 100% soluble in tetrahydrofuran (THF) and 90% + thermal bonds. However, if the coal is subjected to some soluble in toluene and cyelohexane. The various type of handling in which energy is exerted on it, the coal research programs sponsored by EPRI that have been may become a retrogressive product that is much more conducted by several organizations are summarized in difficult to liquefy. The reseachers also conclude that the following information. coal is a "very unusual substance" and that its chemistry is still open to debate. Initial Tests The following four types of hydrogen bonding may occur The results of early mircroautoclave experiments con- in coal: N-HO, 0-HO, N-HN, and O-HN. The EPRI ducted by Mobil, as summarized in Tables 1 and 2, researchers have theorized that because asphaltenes are demonstrated nearly complete conversions to THF- composed of both acidic and basic compounds, coal may soluble compounds and high conversions to heptane- also have an acid-base structure. If these acid and base soluble compounds. However, when large autoclase units are hydrogen bonded, coal may be liquefied at lower experiments were conducted by Kerr-McGee and the than typical temperatures. University of Wyoming, the researchers discovered the following: Basic Nitrogen Solvents • Conversion to cyclohexane- and/or toluene-solu- Three or four years ago, the potential importance of basic ble compounds has no relationship to distillable nitrogen solvents to coal liquefaction was first evidenced (400-800°F) product. in EPRI-sponsored studies at Pennsylvania State Univer- sity under a subcontract to Mobil Research and Develop- • Basic nitrogen solvent apparently can be irrever- ment Corporation. In the studies, gold-tube experiments sibly lost to the 800 +°F material. showed that the basic nitrogen fraction from solvent refined coal (SRC) did not coke whereas all other frac- • Coal chemistry is very complex. tions coked profusely. This coking reaction is an indication of retrogressive reactions. Mobil later took a 6000 Despite these disappointing results, EPRI decided to to 800°F fraction of hydrogenated solvent from the SRC continue further research because: pilot plant at Wilsonville. This fraction was chemically separated into generic classes and subjected to coal • Basic nitrogen heterocycles will always be pre- conversion experiments. As shown in Table 3, the coal sent in any liquefaction process. conversion of the basic nitrogen fraction was higher than any other fraction or the parent solvent. Additionally, • Basic nitrogen heterocycles have a dispropor- the contribution of the basic nitrogen fraction was tionate, sometimes controlling, influence on coal demonstrated when the actual conversion of the whole liquefaction.

4-42 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1

MICROAUTOCLAVE CONVERSION OF BELLE AYR COAL IN A BASIC NITROGEN SOLVENT AT VARIOUS CONDITIONS (1 Hr, 3:1 S/C, THQ/Pyrene, H2 Gas)

Initial Pressure T Time % THF (PSIG) (°F) (Mm) Conversion

1,000 750 10 96.85 2,000 750 10 98.95 1,000 750 60 100.00 2,000 750 60 100.00 1,000 840 10 100.00 2,000 840 10 100.00 1,000 840 60 96.85 2,000 840 60 96.85

TABLE 2

MICROAUTOCLAVE CONVERSION OF BELLE AYR COAL IN DIFFERENT BASIC NITROGEN SOLVENTS AT VARIOUS CONDITIONS (1 Hr, 3:1 S/C, 1000 Psig H2 Cold)

% THF % Heptane % Gas Solvent Gas T, O F Conversion Conversion Made

30% THQ Pyrene H2 740 90.1 - - THQ H2 730 95.1 12.6 .4 Pyrene H2 800 59.2 35.4 21.9 Tetralin H2 800 85.0 (avg) 50.0 (avg) 8.0 (avg) THQ H2 800 100.0 55.2 0 30% Tetralin/Pyrene H2 800 81.7 55.5 6.6 30%THQ/Pyrene H2 800 95.4 56.4 1.8 THQ He 800 84.9 44.7 6.8 30% Solvent M/Pyrene H2 840 83.6 50.4 8.5 TUQ H2 840 89.5 61.2 5.9

TABLE 3

CONVERSION OF ILLINOIS #6 (MONTEREY) COAL IN CHEMICALLY SEPARATED FRACTIONS OF 600-800°F SRC-I PRODUCT (800°F, 1 Br, 1000 Psig H2, 3/1 S/C)

% Sensitivity to Percent of Heptane Solubles Fraction Whole % Conversion and Gases

Neutral 82.2 53.7 5.3 Phenolic 10.8 37.6 -32.8 Basic N 4.4 76.5 0.7 Acidic 1.0 ND NO Amphoteric 0.4 ND ND Whole 100.0 72.7 (52.0) 4.4 (-7.8)

*Mathematically calculated value.

SYNTHETIC FUELS REPORT, DECEMBER 1982 solvent was 72.7% versus the calculated value of only 52%. Mobil also found that nitrogen-rich compounds are concentrated in the dissolving coal during the early stages of dissolution. SRI International is attempting to determine the chemical reactions that occur at liquefaction conditions between coal and various basic nitrogen solvents. The researchers theorize that the solvents may function in a number of ways to liquefy coal: (I) acid/base com- plexing agents, (2) basic tautomerization catalysts, (3) internal base catalysts for electrophillic addition, (4) hydride donors, (5) electron donors, or (6) hydrogen atom donors. The results to date indicate that two of these possible properties of basic nitrogen solvents may account for their effectiveness as coal solvents: (I) catalysis of tautomerization processes, and (2) carbonyl reduction. The base-catalyzed taumerization reaction and subsequent cleavage of ether linkages in coal could be very beneficial in liquefaction reactions. In the carbonyl reduction reactions, the researchers theorize that basic nitrogen heterocycle solvents cross-link with carbonyls, particularly amides, in the coal to form species that are relatively poor in hydrogen and rich in nitrogen. Conclusions The EPRI researchers conclude that basic nitrogen compounds are very good solvents for converting coal into liquids, but that the liquids are non-distillable (i.e.: boil above 800°F) because the solvents are incorporated into the coal. Two methods may be available to liquefy the coal without incorporating the solvents into the coal structure. First, the heavy cross-linked products may themselves be good solvents, but will probably not cross-link further. Second, it may be possible to prevent the cross-linking from even occurring. Other major conclusions from the EPRI-sponsored studies to date include: • In its natural state coal is a very reactive material, but drying or other energy-intensive treatments converts natural coal to a retrogressive material that is much more difficult to liquefy than natural coal. • Coal is likely composed of substances of relatively low molecular weight loosely held together by extensive hydrogen bonding and weak thermal bonds. • Heterolysis (decomposition into two opposite charged species) may be the primary process operating to disrupt coal structure; homolysis (decomposition into uncharged species) may be the secondary process. • Solvent chemical properties are crucial in dissolving coal and basic nitrogen heterocycles have a disproportionate, sometimes controlling, influence on coal liquefaction. • The reduction of carbonyl groups play an important role in coal liquefaction.

4_44 SYNTHETIC FUELS REPORT, DECEMBER 1982 INTERNATIONAL

COAL CONVERSION ACTIVITIES IN WEST GERMANY • Reduce the amount of condensible hydrocarbons and shift the composition toward lighter products West Germany has large coal reserves that have been due to the increase in hydrogen partial pressure. estimated to be sufficient for several hundred years at projected rates of consumption. Additionally, there is a • Lower the gas velocity in the upper section of the large amount of experience with coal conversion pro- gasifier by withdrawing a portion of the gas from cesses dating back to the 1930's in Germany. A the central section of the gasifier. Hence, the national program is well under way to improve older, amount of dust in the gas is reduced and/or finer established processes and to develop new processes. feed coal can be used. Five large scale units have been constructed in Germany to demonstrate coal gasification technologies. • Reduce the amount of carbonization products (tars, German industry is also involved in five liquefaction oil, and phenols) and the amount of water in the projects, two in Germany and three in the United products. States. • Facilitate adapting the quality of the gas to its Recent experiences with three of these coal conversion intended use with the aid of a raw gas reforming projects were described at the Ninth Annual Inter- unit. At low reformer temperatures, the gases can national Conference on Coal Gasification, Liquefaction, be used to produce SNG. At higher temperatures, and Conversion to Electricity (COGLAC). Dr. W. the hydrocarbons are cracked to produce synthesis Schafer summarized the results of testing of the pres- gas (CO, H 2, and CO2). surized Lurgi gasification process in a paper entitled "Ruhr 100-New Results on the Advanced Development Three years after plant start-up, the unit has operated for of the Pressurized Lurgi-Gasification." A second paper over 4000 hours. Total testing is planned to last four entitled "First Experience and Results Gained During years. Operation of the 200 t/d COAL OIL Plant in Bottrop" by Karl F. Schlupp described recent tests of the The Lurgi gasifier is a fixed bed unit in which coal is fed Bergius-Fier direct liquefaction process. Tests using a into the top of the vessel from double lock hoppers. Texaco gasifier were described by R. Durrfeld in a third Steam and oxygen enters at the bottom of the gasifier and paper entitled "Results of 4 Years Operation of the passes through slots in a rotary grate. Ash is withdrawn Texaco-Coal-Gasification-Plant at Oberhausen-Holten from the bottom of the unit through a lock hopper. The as Developed by Ruhrkohle AG and Ruhrchemie AG." pilot plant was designed for gasification with oxygen, but air gasification is also possible. Pressurized Lurgi Gasification Pilot Plant at Dorsten The gasifier has two gas withdrawal outlets. "Clear gas" In the mid-1970's, a pressurized Lurgi pilot project was that is free of carbonization products is withdrawn from initiated by a group consisting of Ruhrgas AG, the central part of the gasifier and carbonization gas is Ruhrkohle AG, and STEAG AG. The project was withdrawn from the top of the gasifier. Both gas streams subsequently sponsored by the West German Ministry of are cooled and pre-cleaned in separate quench scrubbers. Research and Technology as part of the national energy research program. Waste heat boilers are used to cool the gases to below 200°C (390°F) and to generate low pressure steam. In The pilot plant, referred to as RUHR 100, is to demon- the pilot plant, the two gas streams are combined and strate an advanced Lurgi gasifier that operates at 100 treated to remove dust and tars. A two-stage shift bar (1450 psi). Design of the major portions of the conversion unit is used to reduce the CO content of the plant began in 1977 by Lurgi Kohie und Mineralol- majority of the product gas to below statutory units for technik GMBH. The utilities facilities were designed by heating gases. Additionally, a portion of the gas can be STEAG. The plant went on stream in September 1979 reformed to produce SNG or synthesis gas. Finally, the at the Ruhrgas facility in Dorsten. H0S in the gas is removed and the gas is fed into Ruhrgas' n4tural gas network. The goals of the project were as follows: The first six runs with the RUHR 100 gasifier were • Increase the operating pressure to 100 bar to conducted at conventional pressures of 25 bar. During the raise the methane content in the raw product gas remaining tests, the pressure was increased and a pressure to more than 17% (versus less than 10% at 25 of 70 bar was achieved in the tenth run. In the combined bar). Concurrently, at least double the gasifier eleventh/twelfth run, the feed coal was switched and the throughput on a ton-per-square-foot of gasifier feed rate was increased to 100% of design. Testing was cross-sectional area basis. then interrupted for five months due to a misoperation of the unit.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-45 Testing to acquire basic design data was started during • the formation of tar and oil declines with increa- tests fourteen and fifteen. The steam-oxygen ratio was sing pressure reduced to improve thermal efficiency and the pressure was increased to over 90 bar. A gas production rate of • at higher pressures the degree of efficiency in 9,200 m /h per square meter of gasifier area (30,185 terms of the energy fixed chemically in the raw ft3/hr per sq. ft.) was achieved. Large fluctuations in gas increases, while the overall gasification pro- coal quality during some tests caused difficulties in the cess becomes more favorable in terms of energy gasifier operation due to the formation of caking crusts. Some tests also used coal briquettes for short • it is more energy efficient to operate at low periods of time. steam-oxygen ratios; moreover, the degree of steam decomposition increases. Test 22 lasted for 522 hours and demonstrated that the gasifier can be operated with varying coal qualities Future tests with the pilot plant gasifier will be directed (coal with a maximum ash content of 52% was success- toward: fully gasified). High load tests demonstrated that the gasifier can be operated at rates far above the design • widening the coal spectrum in the direction of values. During the last few runs, the coal variability using stronger higher-caking coal problems caused the gasifier to be operated at less than optimum conditions. • determination of the upper load limit From the test data, the theoretical effects of gasifier • processing of coal fines in a compacted form. pressure on gas composition were calculated. These theoretical curves, as shown in Figure 1, indicate that Direct Coal Liquefaction Pilot Plant at Bottrop higher pressures increase the methane content of the gas and decrease the CO and H 2 content. The curves in The decision to construct the COAL OIL plant at Bottrop Figure 1 also indicate that the steam-oxygen ratio has was made in 1977. Project sponsors include Ruhrkohle Oil only a minor effect on gas composition. and Gas GmbH and VERA OEL Entwicklungsgesellschaft mbH with financing provided by the West German state of Figures 2, 3, and 4 depict the effects of gasifier North-Rhine Westfalia. Basic engineering was performed pressure on saturated hydrocarbons, unsaturated by Ruhrkohle and VERA OEL during 1978-1979 and hydrocarbons, and condensible tar.and oil components in detailed engineering was completed in 1980. Construction the raw gas. From the pilot plant data, the researchers of the pilot plant began on May 21, 1979, with physical conclude that the unsaturated hydrocarbons, tar, and oil completion in 1981. On November 25, 1981, the first coal components are apparently hydrogenated at higher was liquefied. pressures, thus increasing the yields of methane and saturated hydrocarbons. The Bottrop site was selected because of its proximity to Ruhrkohle's cokery which provides a means of disposing of The theoretical effects of temperature on gas composi- flash gas, waste water, and hydrogenation residues. tion are depicted in Figure 5. These curves indicate Hydrogen for the pilot plant is provided by a hydrogen that the equilibrium concentrations of CO and H2 pipeline near the plant. increase sharply with temperature and the concentrations of methane and CO are reduced. A simplified diagram of the process is presented in Figure 6. The feed coal is first milled to 1 mm and dried to 1% The higher yields of saturated hydrocarbons at higher moisture. The coal is next slurried in recycle oil, mixed pressures increase the heating value of the raw gas, with the iron catalyst, and wet milled to 0.2 mm. This hence improving the thermal efficiency of the gasifier. slurry containing 40% coal is then mixed with recycle gas At 25 bar, approximately 39.5% of the total input and makeup hydrogen before being heated to 425°C energy to the gasifier is converted into synthesis gas. (8000F). However, at 90 bar this value increases to 59.4% of the total input energy. The mixture of coal, oil, catalyst, and hydrogen passes through three reactors operating in series at 300 bar (4350 In the tests, the steam-oxygen ratio was slowly rduced psi). Temperature in the reactors is controlled to 475°C at vyious pressures to a minimum of 5.5 kg/m (0.34 (890°F) by the addition of quench hydrogen. lb/ft ). The heating value of the gas increased at lower steam-oxygen ratios. Hence, the researchers conclude Products from the reactors are separated in the hot that gasifier operation at low steam-oxygen ratios and separator flash drum. The gases from the top of the hot high pressures leads to a better utilization of the input separator are cooled and separated further into a conden- energy. However, the ash fusion behavior of the coal sate stream and a C 1 to Cc stream. A portion of this C1 must be taken into account in that coal with high ash to Cc fraction is recycred to the reactors and the contents or unfavorable mineral assemblages require remarnder is exported as SNG to the cokery. The higher steam-oxygen ratios. condensate is distilled into light, medium, and heavy oil fractions in an atmospheric column. In summary, the tests to date in the RUHR 100 gasifier have demonstrated the following: The bottoms from the hot separator are distilled in a vacuum column into distillate oil and residue. This • the CH content in the raw gas rises from 10% residue which contains ash, unconverted coal, and catalyst at 25 btr to over 17% at 90 bar; accordingly is granulated and sent to the cokery. In an industrial there is also a rise in the heating value

4-46 - SYNTHETIC FUELS REPORT, DECEMBER 1982 — K IG UM TEMPERATURE: 740 C 100 STEAM/OXYGEN RATIO 7.0 KG.'N3 o o ---STEAM/OXYGEN RATIO 4.0 KG/N3 0 t ETH ANE S- 600 ...... S 0 0 30 U 500

400, PROPANE

10 CH4 100 BUTANE 0. I 4 PRESSURE (BAR) Olt 25 50 75 100 (CALCULATED FOR HOMOGENEOUS PRESSURE (BAR) SIMULTANEOUS EGUILISRIUM REACTIONS) FIGURE 2 EFFECTS OF PRESSURE ON SATURATED FIGURE I HYDROCARBONS IN THE RUHR 100 GASIFIER THEORETICAL EFFECTS OF PRESSURE ON GAS COMPOSITION IN THE RIJHR 100 GASIFIER

X I03 SO. O.....O OIL ^^THEME s—.TAR 0 (FREE OF DUST) So. - 60 0 S 4 4 S- PROPENE 40 40. t PUTEN 2 - S ^' F,\\%\N ^'\ 20 40 20 0 DIENE $7UTA •• 25 50 15 100 0. I PRESSURE (BAR) 20 40 SO 00 lOG PRESSURE (BAR)

EFFECTS OF PRESSURE ON UNSATURATED FIGURE 4 HYDROCARBONS IN THE RUHR 100 GASIFIER EFFECTSOF PRESSURE ON OIL AND TAR IN THE RUHR 100 GASIFIER

PRESSURE 00 OAR M4E.-ijo • STEAM/OXYGEN: 7.0 KG/Ma Hydzoçen Recycle Gas a 050 Calast SepaFalor HO LiqWd coal S (STEAM) SI€)e 5MG 2 4° I- MIS 'I It 0 30 a DO S^IUCIAII 0 U LPG 20 4 Gasoline 0 S" DO CH Middle ID Vacuum AI5pfler C Distillation Distillation D)aiiUaie a Granulation 0 00 700 BOO 900 1000 EQUILIBRIUM TEMPERATURE (C) FIGURE 5 FIGURE S THEORETICAL EFFECTS OF TEMPERATURE SIMPLIFIED DIAGRAM OF THE DIRECT LIQUEFACTION ON GAS COMPOSITION IN THE RUHR 100 GASIFIER COAL OIL PILOT PLANT AT BOTTROP

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-47 facility, the residue would be gasified for hydrogen pro- this internal insulation is protected against abrasion by a duction. The oil from the vacuum column is mixed with thin metal liner. the bottoms from the atmospheric column for use as the coal slurry oil. During operation, gas (particularly hydrogen) penetrates from the reactor into the insulating layer, filling the During startup of the pilot plant, problems arose with existing pores with gas. To ensure that the gas returns conventional components such as mills, furnaces, H into the reactor during a pressure release, the metal liner compressors, high-pressure valves, etc. Most of the was provided with pressure equalization outlets. When initial problems have been solved. The first test run rapid pressure release occurs, however, an overpressure with coal was started at a feed rate of 759 kg/h (1650 develops in the insulating layer and may cause damages to lb/h) which is only 8.5% of the design throughput. the refractory bricks. The internal insulation can loosen Proposed design and startup conditions for the COAL and the pressure-bearing reactor wall is no longer com- OIL plant are presented in Table I. The coal through- pletely heat insulated. It is then necessary to take the put during this first test was increased to 2.5 TPH until reactor out of operation and to replace the internal heat the plant was shut down due to failure of both hydrogen insulation and the metal liner. A new reactor design is ccmpressors after seven days of operation. Products being developed that does not have these technical dis- were produced during this test. advantages and ensures a maximum availability and service life. The basic element of this development is a After the compressors were repaired, several tests pressure bearing metal liner between the internal insula- were conducted which achieved design conditions. The tion and the reactor inside. Testing of this reactor type longest test lasted 25 days. During the sixth test, hard, in the Bottrop plant is planned in 1983. Fabrication of granulated vacuum residue was produced for testing in this new reactor is almost completed. Ruhrkohle/Ruhrehemie's pilot plant using the Texaco gasification process. (This pilot plant is described later In addition to process testing and equipment development, in this article.) the project at Bottrop involves an analytical testing program. Due to the difference between coal-derived oils By June 6, 1982, the COAL OIL pilot plant had operated and conventional oils, new methods must be developed and with coal for 2009 hours (4200 total hours of operation). proven methods must be adapted. For this development Total coal throughput was 9000 tons. work, a laboratory was installed at the VEBA DEL AG facility in Gelsenkirchen-Scholven, where the suitability During the operation of the pilot plant, various of COAL OIL for fuel and heating oil production as well different equipment components have been tested. One as for chemical feedstock is investigated. The COAL OIL such component, the high pressure slurry pumps, must is first distilled into low and medium boiling fractions and be extremely resistant to wear due to the high com- the individual fractions are separately processed. Light pression and temperature stresses as well as to the and medium oils are subjected to a refining process. solids contained in the coal-oil-suspension. Three high After the two-stage refining process, the light coal oil is pressure plunger pumps, two of which are of different then converted in a reforming process into gasoline. The design, have been tested at Bottrop. refined medium oil can be used as No. 2 fuel oil. There are other options such as high-pressure hydrogenation of Another component for the COAL OIL process that has medium oil to diesel fuel and the hydrocracking of been tested is the coal-oil slurry preheater. This heater medium oil into gasoline. must be designed with care because the coal begins to swell as the slurry is heated. Therefore, the viscosity The total expenditures for this project are approximately of the slurry increases up to a maximum at 300 0 to 420 million DM ($168 million US), of which about 170 350°C (570 0 to 660°F) and the heat transfer million OM are investment, about 220 million DM are deteriorates due to laminar flow. At Bottrop two required for the operation of the plant up to 1983, and different pre-heaters were installed: a convective-type about 30 million DM for the operation of the laboratory. heater and a radiation heater. In the convective-type The project is mainly financed by the Minister of heater, the slurry flows through pipes and the heat is Economic Affairs of the State of North-Rhine Westfalia. transferred by hot flue gases circulating between the surface of hairpin-shaped pipes. The heat transfer rate The researchers conclude that "so far satisfactory results is relatively low, thereby reducing to a minimum the have been obtained." No significant difficulties have been coking tendency of the coal-oil-suspension in the encountered and the equipment problems have been essen- hairpin pipes. The disadvantages of this type of heater tially eliminated. are the large size required and the high costs. When using the radiation heater which is normally employed Texaco Gasifier Pilot Plant at Oberhausen-Holten in refineries, there is an increased danger of coking due to higher temperatures. The purpose of the tests in the In 1975 Ruhrkohle AG and Ruhrchemie AG decided to Bottrop plant is to reduce this risk and at the same jointly build and operate a coal gasification pilot plant time utilize the higher heat transfer value, the smaller and develop a process to commercial readiness, flue to dimensions, and the lower investment cost. the perceived problems of first generation gasification technologies, a second generation process was desired A third component being tested at Bottrop is the vessel that could: containing the three reactors. The reactors are welded multiLayer vessels, with an internal heat insulation • attain gasification pressures of up to 100 bar (1450 consisting of refractory bricks. As shown in Figure 7, psi)

4-48 SYNTHETIC FUELS REPORT. DECEMBER 1982 WELDED MULTI LAYER WALL

HEAT-INSULATION REFRACTORY BRICKS

B.S. ABRASION RESISTANT LINER

REACTOR INSIDE

STEEL-TUBE SUITABLE FOR HIGH-PRESSURE HYDROGENATION

FIGURE 7 CROSS SECTION OF HYDROGENATION REACTOR WALL

SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 DESIGN CONDITIONS, START-UP CONDITIONS AND OPERATING RESULTS OF THE COAL OIL PLANT AT BOYFROP Design Start-Up Max. Operating Conditions Conditions Results to Date Coal Feed Rate t(m.a.f.)/h 8.3 0.75 8.3 Coal/Oil-Ratio in Slurry wt% 40:60 15:85 40:60 Slurry Rate t/h 20.8 5.0 20.8 Temperature °C 415 440 478 Pressure Bar 300 280 280

• utilize all coals as feedstock 800 hours. Twelve different coals were successfully gasified with good yields and no technological problems. • produce no by-products that pollute the environment The results of the tests are summarized in Table 2. These results indicate the high gasification efficiency, low • operate without fluctuations and provide a oxygen consumption, high coal content of the slurry feed, possibility of a high degree of automation and high carbon conversion that were achieved during the tests. At the end of the tests during 1982, the plant was • have a high degree of availability, so it can be converted to a direct-quenching operation to saturate the linked to chemical processes with annual service product gas with steam. periods of 8,000 hours At the start of the tests, the product gas was fired at the • produce residues that contain no organic or other Ruhrchemie power station. Later it was mixed with ecology-polluting components that can be synthesis gas produced from an oil gasification process leached out by water. and fed to the oxo-synthesis plant at Euhrchemie. The researchers found that the coal-based synthesis gas was It was determined that an entrained bed gasifier could well suited for the chemical synthesis. fulfill these objectives. The Texaco process being developed at Montebello, California, was selected The researchers concluded "that the project targets were because of its simple coal feeding technique (pumping a fully achieved, and that the process has reached a stage coal-water slurry into the reactor). The project where it would be possible to plan a commercial plant." sponsors decided an intermediate-scale demonstration plant was required to bring the process to commercial Component testing was also conducted during the four- scale. year test program. One component, slurry preparation, was improved by the use of wet grinding with a tube mill. The demonstration-scale plant was commissioned on The fineness of the grind was improved and the coal April 3, 1978, after two years of engineering effort and concentration in the feed slurry was increased. eight months of construction. Testing lasted four years and was completed on April 30, 1982. Investment in the Several aspects of the gasifier were also improved. The plant was approximately 11 million OM ($4.4 million burner in the Texaco gasifier is important in that it must: US) • introduce the gasification media into the pres- The Texaco process consists of pumping a coal-water surized chamber slurry into the top of the gasifier. This slurry is sprayed together with oxygen through a burner into the • spray the slurry and mix it with oxygen reactor. Raw product gas and slag are removed from the bottom of the gasifier and cooled in a radiation • distribute the reaction mixture by making good use cooler. Approximately 90% of the ash is removed from of the geometry of the reactor. the stream and the gas is cooled further in a convection cooler. The remaining ash is removed in a water Therefore, five different types of burners were tested. scrubber. The most significant improvement was the development of a burner which could be adjusted on line to compensate During the four-year testing period, approximately for different coal feed rates. 60,000 tonnes were gasified. A total of 11,000 hours of operation were achieved with the longest run lasting The refractory lining of the reactor was also tested. This lining must withstand temperatures to 1600°C (2910°F),

4-50 SYNTHETIC FUELS REPORT, DECEMBER 1982

TABLE 2 TEST RESULTS FROM THE TEXACO GASIFIER AT OBERHAUSEN-HOLTEN (optimum results of different test runs)

Reached Design Temperature, °C 1200- 1600 1500 Pressure, bar 40 40 Coal feed rate, tons/hr up to 8.2 6.0 Amount of pure gas (Co + H 2), m3/hr up to 15200 1000 Suspension concentration, % upto7l 55-60 C-conversion at single pass, % upto99 95 Gasification efficiency (Ho), % upto7? 70 spec. 0 2-demand.m 3/1000 m3 (H2 + CO) > 340

Gas composition, Vol. -% CO 55 45-55 H2 33 30-40 CO 11 15-20 CH 0.01 1 H25/COS 0.3 — N2 0.6 —

corrosive attack by the gases and slag, and erosive The quality of the wastewater from the process is sum- attack of solids. Fifty lining materials were pretested marized in Table 3 and the results of the slag leaching and twenty materials were tested in the reactor. The tests are summarized in Table 4. best results were obtained with Pierochromite bricks (made of chrome oxide and highly purified magnesia) The project sponsors plan to continue operating the capable of achieving service life values in excess of Holton plant and to test the application of the gasifica- 8,000 hours. tion process to the utilization of residues from the coal liquefaction process, COAL OIL, as described previously The waste heat system of the reactor was found to in this article. Negotiations are currently being con- operate without any difficulties. If hydrogen is to be ducted on the execution of further tests. This supplemen- produced, the researchers found that the direct-quench tary program will also provide an opportunity for optimi- method of heat recovery is preferred. zing individual process components.

The following environmental advantages of the Texaco The Texaco gasification process can be used to produce process were demonstrated during the tests: hydrocarbons, oxy-alcohols, hydrogen, or heating gas. However, Ruhrkohle and Ruhreheinie have concluded that • the high gasification temperature reduces the only synthesis gas for chemicals production is presently formation of higher hydrocarbons, and due to the economically attractive. Therefore, Ruhrkohle AG and reducing atmosphere the development of NO Ruhrehemie AG are planning the "Synthesegasanlage and SO is suppressed Ruhr" on the premises of Ruhrchernie AG. This plant will have a feed rate of approximately 30 TPH foc3 a synthesis OP the gasification temperature is above the ash gas production (CO * H ) of0,00O mM /hr and a fusion point; hence, the majority of impurities in hydrogen production of 10,60m M /hr. This synthesis gas the coal are smelted in the vitreous residue and is scheduled to supply the oxo-sSmthcsis plants with gas, can not be leached out by water whereas the hydrogen is destined for the production of fertilizers. The commissioning of the "Synthesegasanlage • the solids are fed in and discharged as suspension Ruhr" is scheduled for 1986. which prevents the formation of dust and emissions of lock gas.

SYNTHETIC FUELS REPORT, DECEMBER 1982 • 4-51 TABLE 3 TABLE 4

WATER BLOWDOWN QUALITY (ILLINOIS NO.6 COAL) LEACHING TESTS OF SLAG FROM THE FROM THE TEXACO GASIFIER AT OBERHAUSEN-HOLTEN TEXACO GASIFIER AT OBERHAUSEN-HOLTEN (ILLINOIS NO.6 COAL) pH 8.7 BY THE EPA EXTRACTION PROCEDURE TDS ppm 1460 PH 4.9 COD ppm 600 TOC ppm 250 TOC ppm 375 Ammonia ppm 1.1 Ammonia 1660 Anions - Anions Bromide ppm c 10 Bromide ppm < 0.1 Chloride ppm 680 Chloride ppm 0.30 Fluoride ppm 62 Fluoride ppm 3.3 Cyanide ppm 3.4 Cyanide ppm 0.02 Formate ppm 97 Sulfate ppm 14 Nitrate ppm 59 Sulfite Plum 195 Metals Sulfate ppm 16 Antimony ppm C 0.5 Arsenic ppm C 0.05 Trace Organics Barium ppm C 0.5 Benzene ppb C I Beryllium ppm C 0.02 Toluene ppb < I Cadmium . plum 0.02 Anthracene ppb C 0.05 Chromium ppm C 0.40 Fluoranthene ppb C 0.05 Cobalt ppm C 0.05 Naphthalene ppb 5.0 Copper ppm C 0.5 Pyrene ppb < 0.2 Lead ppm C 0.5 Phenanthrene ppb < 0.6 Manganese ppm 0.72 Phenols ppb 4.5 Mercury ppm C 0.002 Molybdenum ppm C 0.5 Trace Metals Nickel ppm 0.27 Antimony ppm < 0.001 Selenium ppm C 0.001 Arsenic ppm 0.008 Silver ppm < 0.03 Barium ppm 0.16 Thallium ppm < 0.5 Beryllium ppm 0.010 Vanadium ppm C 0.2 Cadmium ppm C 0.010 Zinc ppm 2.1 Chromium ppm 0.07 Cobalt ppm C 0.05 Copper ppm C 0.05 Lead ppm 0.014 Manganese ppm 0.17 Mercury ppm C 0.001 Molybdenum ppm 0.002 Nickel ppm < 0.05 Selenium ppm 0.070 Silver ppm < 0.03 Thallium ppm C 0.002 Vanadium ppm C 0.2 Zinc ppm 0.19

4-52 SYNTHETIC FUELS REPORT, DECEMBER 1982 ENVIRONMENT

WASTEWATER TREATMENT FOR THE GREAT The gas is further, purified by a low temperature methanol PLAINS PROJECT wash in the Rectisol Unit in which all naphtha, essentially all sulfur compounds, and 97% of the CO are removed to As part of a cooperative agreement with the U.S. prepare the gas for methanation. The Rectisol off-gases Department of Energy (DOE), ANG Coal Gasification are scrubbed in a Stretford Unit to produce elemental Company (project manager for the Great Plains project) sulfur for sale. The Stretford off-gases are then agreed to supply DOE with a report on the development incinerated in the boilers to avoid emitting residual of the wastewater treatment system for the project. hydrocarbons and undesirable sulfur compounds. The title of the report is "A Wastewater Treatment System for a Lurgi Coal Gasification Plant" The clean synthesis gas is diluted with recycled (DOE/RA/20225-T3). The treatment system described methanated gas and passed through parallel beds of in the report was developed from test and analytical reactors containing a reduced nickel catalyst. In this studies conducted over a period of six years. Contained methanation process, carbon oxides react with hydrogen in the report is a basic description of the wastewater to form methane (CO + 311 — CH + H 0). A final treatment design. However, some detailed information clean-up reactor is used to ?,move $ema&ing traces of that is proprietary to Sasol or Lurgi is not included in carbon monoxide and to insure a high BTU product gas. the report. The gas is cooled, dried, and compressed to a minimum of 900 psig for transmission to end users in natural gas As described in more detail on page 4-1 of the pipelines. This product gas has a higher heating value of September 1982 Pace Synthetic Fuels Report, the Great 977 BTU per cubic foot. Plains project is presently under construction and is scheduled for startup in late 1984. When completed, Wastewater Sources the project will convert approximately 14,000 TPD of coal into 125 million cubic feet per day of high-BTU The report by ANR describes the various sources of gas. The plant was designed on the basis of zero wastewater at the Great Plains plant and briefly sum- discharge of plant wastewaters. marizes the degree of contamination of each stream. The wastewater resulting from the gasification of the lignite Great Plains Process Description is the largest continuous wastewater stream generated in the plant. The raw gas at the outlet of the gasifier The basic block now diagram of the Great Plains contains 51.5% moisture which must be either shifted or project is presented in Figure 1. Approximately 22,000 condensed in waste heat exchangers and gas coolers in the TPI) of lignite is crushed to 8" in the primary crushers Gasification, Shift, and Gas Cooling Areas. The conden- and then crushed to less than 2" in the secondary sate (gas liquor) is collected and processed to remove tar, crushers. Approximately 14,000 tons per thy of 2" x tar oil, phenols, and ammonia before being used as make- 1/4" coal is fed from a storage pile to the gasifiers and up water to the cooling tower. 8,000 tons per day of -1/4" coal is fed to the Basin Electric generating facility to fuel their boilers. The upstream surface runoff includes all naturally occurring waters that drain from areas adjacent to the The gasifier building contains 14 Lurgi Mark IV gasifiers plant boundaries. These waters contain soil sedimentation with 12 in operation and 2 serving as spares. The coal that is minimized by drainage devices which prevent soil is fed to the top of each gasifier by means of lock erosion. hoppers and the ash is discharged by means of lock hoppers at the bottom. Steam and oxygen are mixed The clean inplant storm drainage is similar to the and distributed through a rotating grate and pass upstream runoff in that it normally includes rainwater and upward through the coal bed. The gasifiers operate at snowmelt containing soil sediments. It includes all storm about 430 psig. drainage within the plant boundaries. Because it is relatively clean water, it is handled separately to avoid The raw gas from the top of the gasifiers is quenched unnecessary treatment. and cooled to condense the tar, oil, phenols, ammonia, and water. These components comprise the gas liquor The plant sanitary wastes consist of drains from plant stream which is treated separately. showers, toilets, sinks, kitchen equipment, and building janitorial equipment. Approximately 30% of the gas stream must be shifted to produce the correct ratio of hydrogen to carbon Inorganic wastewater streams (essentially brine solutions) monoxide for methanation, slightly more than 3-to-1. originate from the Secondary Water Treatment Unit as a In the shift reactors, carbon monoxide reacts with result of filter backwashing and ion exchange resin steam over a cobalt molybdenum catalyst to produce regeneration. These wastewater streams are relatively the additional hydrogen required. pure and are reused as make-up to the Raw Water Storage Pond. The blowdown from the low pressure steam system

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-53

AIR OXVGEN OXYGEN I I COMPRESSION COMPRESSO PROOTION COMPRESSION I — I I PIPELINE El

COAL FRIES TO I I 4i.. U ELECTPEC] I I I STEAM S.j

II, ______

CRUOSOAS I COAL GAS$FICATION PREPARATION .i..i

______ICGIVERSOI __ Ij 7iEc I ____ RUNOFJ 14 4 _jt 4jLNAPNT MINE COAL I

I AMPCNEA P I I AoUEot. :S SUTION — 11I, AkwaIA WATER 104 I 0SEPAPATOIH4$4 RECOVERY COQMG TOWERS -...- [^] L WASTE GAS TO I flTEAAI 0$NERATORSII. SI.-'u I i FUEL GAS TO I.------STEMA GENERATCSUØI - I SLA.FLM I c000E pHENaS P p

FIGURE 1 PROCESS FLOW DIAGRAM OF THE GREAT PLAINS PROJECT

4-54 SYNTHETIC FUELS REPORT, DECEMBER 1982 is another source of inorganic wastewaters. A portion Retention Pond (2.3 acres). This clean stormwater may of the distillate from the Multiple-Effect Evaporators be discharged from the Storm Water Retention Pond into used to concentrate cooling tower blowdown may also the natural drainage system, reused in the plant, or used be treated with the inorganic streams intermittently. for dust control in the coal mine. The Coal Pile Run-off Retention Pond collects all the storm drainage from the The oily water drainage includes all contaminated undeveloped east side of the plantsite, the runoff from wastewater steams within the plant. Paved process temporary coal or ash storage piles, and drainage from areas of the plant drain to the underground sewer sumps in the coal storage buildings. This pond allows coal system that collects rainwater and any process liquid particles, soil sediments, and dust suspended in the storm spills. Low point drains on equipment and pipes water to settle out. The clarified water is then dis- discharge to the same system. Several process units charged to the stormwatcr pond which also collects have individual oily water collection systems to prevent stormwater runoff from the non-process areas of the spills in these units from entering the oily sewer prior facility. The stormwater in this system may be con- to analysis. taminated by items such as oils from plant roads and parking lots. Therefore, the drainage system is designed Wastewater Treatment Processes to allow contaminated water to be treated in the oily water treatment system. This system is designed so that In 1973, the Lummus Company began developing a zero initial stormwater preferentially flows to the Small Storm discharge wastewater treatment system for the Great Water Pond. At a minimum, the stormwater in the small Plains facility. All treatment processes selected were pond is inspected or analyzed before it is discharged to well' proven on conventional wastewaters. The key to the large storm water pond or pumped back to oily water the originally proposed system was biological treatment treatment. The 4.5 acre Storm Water Retention Pond of the stripped gas liquor (compounds condensed from receives flow from the two storm water ponds and the the gasifier raw gas). plant drainage. This water can be reused in the plant or mine or discharged to natural drainage. Approximately one year after this preliminary design was prepared, 12,000 tons of North Dakota lignite was Sanitary Wastewater Treatment gasified at the Sasol I plant in South Africa., The resulting gas and liquid streams were treated as The domestic sewage treatment facility is a standard proposed in the original design and all the processes package unit designed to treat 20,000 gallons per day of performed as expected with the exception of biological domestic sewage. The liquid effluent after secondary treatment of the dephenolized and stripped gas liquor. treatment is discharged to the stormwater pond and the sludge is used as a soil conditioner in the mine reclama- Because of the difficulties encountered in the test, tion program. alternate methods of treating the stripped gas liquor were sought. Direct feed of stripped gas liquor to a Inorganic Wastewater Treatment cooling tower was proposed and successfully tested at Sasol. The key feature of the wastewater treatment The inorganic wastewater treatment system is designed to design, therefore, became the direct use of the cooling pretreat and dispose by deepwell injection the excess tower to provide partial oxidation and concentration of inorganic wastewater that cannot be reused. Water used organics in this stream. Several other design changes for backwashing filters or rinsing of regenerated ion evolved as a result of this major design change. The exchange resins is collected in the backwash pit and revised treatment system to be used at the Great Plains pumped to the raw water storage pond to be reused as plant is depicted in Figure 2 and the flow rates and feed to the water treatment unit. The majority (125 to compositions of the streams are summarized in Table 1. 175 gpm) of the low pressure steam system blowdown is reused as make-up to the incinerator quench system in the Offsite Surface Runoff wastewater treatment process. The excess (100 to 150 gpm) that cannot be reused is disposed of via a deepwell. All rainwater, snowmelt, and other naturally occurring This blowdown contains traces of boiler feedwater treat- waters adjacent to the plantsite contribute stormwater ment chemicals (sodium phosphates, hydrazine, runoff that is diverted around the site (both Great morpholine, sodium sulfite, and tn-sodium phosphate). Plains and Basin Electric Power Cooperative) by a The evaporator distillate from the Multiple Effect peripheral drainage ditch. This drainage ditch Evaporator contains low concentrations of light organic discharges downstream of the plant site into the compounds and is, therefore, used primarily as make-up to naturally occurring drainage pattern. the cooling water system. However, under extremely cold winter conditions when the low cooling tower evaporation Clean Inplant Storm Drainage rates preclude normal make-up, the volume of distillate that cannot be stored in the cooling tower surge pond is The inplant storm drainage system collects all the also disposed of via the dcepwell. The remaining storm water falling on the non-process areas of the inorganic wastewater streams are the brine solutions plantsite. This system retains the stormwater so that resulting from regeneration of the various ion exchange suspended particles can settle and so that any water resins. These brine solutions cannot be reused within the contaminated with oils or organics can be pumped back plant and must, therefore, be disposed of via the deep- to the oily water treatment system. The clean inplant well. drainage system includes three ponds: the Coal Pile Run-Off Retention Pond (2.2 acres), the Storm Water The Deepwell Pretreatment System is designed to Retention Pond (4.5 acres), and the Small Storm Water pretreat the excess inorganic wastewater to prevent the

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-55 WASTEWATER TREATMENT UIAURAM FOR THE 5HEAT PLAINS PROJECT

4-56 SYNTHETIC FUELS REPORT, DECEMBER 1982 TABLE 1 NORMAL WINTER WASTEWATER STREAMS FOR THE GREAT PLAINS PROJECT

Steam Numbers Identified in Figure 2 2.2 2.2 2.3 2.4 2.5 2.6 2.7 2.8 2.9 Normal Average Flow GPM 316 275 28 132 50 ä3 1n 83.3 2,277 Design Flow GPM 511 450 50 500 500 2,642 Ca PPM asCaCO3 500 7 $00 1 8 Mg PPM asCaCo3 200 7 200 I I Natk PPM as CaCO3 2,500 2,250 52,600 301 301 Total Cations 2,264 303 303

HCO3 PPM as CaCO3 150 19 89 CO3 PPM as CaCO3 30 6,800 5 5 OH PPM as CaCO3 1,964 1,800 SO4 PPM aSCaCO3 3,850 800 82,250 262 262 Cl PPM as CaCO3 500 20 1.200 14 14 Misc. PPM as CaCO3 100 2,254 3 3 Total Anions 303 303

Phosphate as PO4 40 200 S102 PPM as 0802 75 10 10 COD PPM 8,200 3,080 TOG PPM 3,800 450 26,950 695 NH3 PPM as Nt!3 2,385 900 15,050 593 Phenols PPM as Phenols 8,230 12,300 848 Fatty Acids PPM as Acetic Acid 5,390 900 45,800 1,520 Free Oils 80-0,000 TSS PPM 8,000 10,000 100 1 II TOO PPM 11,500 0,950 97,700 I 2,340 pit 7.0 9.0 6.0 10.0 82.5 7.9 7.9 8.0

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-57 loss of permeability in the injection zone of the deep, pumped from the API pit into the tar separators well and to comply with EPA regulations for under- for reprocessing. round injection control. The design flowrate is 400 gpm with the normal winter flowrate of 223 gpm and Rectisol - The Rectisol Unit has two sewer systems normal summer flowrate of 199 gpm. The pretreatment to isolate oily water from methanol. All equip- system includes two levels of filtration and pH adjustment containing methanol is hard piped to an ment to between 5.0 and 6.0. The filtration package enclosed methanol sewer system so that any includes three pressure sand filters in parallel followed methanol drained from the equipment flows into an by eight tubular cartridge filters in parallel to remove underground methanol slop tank and is reused particles larger than 10 microns. The deepwell injects within the process unit. All oily water not con- the water into the Minnelusa sandstone formation at a taining methanol flows directly into the plant oily depth of about 6000 feet. Woodward-Clyde Consultants sewer system. If methanol enters the oily water conducted tests during 1975 and 1976 to determine the sewer system, valves can be closed and a portable feasibility of deepwell disposal of aqueous plant wastes. sump pump used to empty the system. Results of these tests indicated that the inorganic wastewater stream could be disposed of in a deepwell. • Sulfur Recovery - The Stretford Unit sulfur However, the cooling tower blowdown that contains recovery unit has a dual sewer system identical to organics should not be included in the deepwell disposal the system in the Rectisol Unit. The enclosed system. chemical sewer recycles the stretford solution to the process and the oily water sewer flows directly Oily Water Treatment to the plant oily sewer system. A battery limit block valve is also provided in this unit to contain The oily water sewer and treatment system processes spills within the process unit boundaries. contaminated water streams from the plant by reducing the oil concentration in the streams from between 10 The total oily water sewer collection system from all and 1000 ppm free oils to less than S ppm free oils. A process units is combined in one large underground pipe separate underground sewer system is provided to that leads to a splitter box. Other wastewater streams collect the oily water from the different process areas. from the stormwater pond, filter backwash, and the The following five process units have been designed cooling tower feed surge pond also flow to this splitter with special oily sewer systems to contain and repro- box. Pumps transfer the incoming flow to two parallel cess potentially dangerous accidental spills: API Separators equipped with flight scrapers, oil skimmers, and sludge pumps that separate the water, oil, • Phenosolvan Unit - Two separate underground and sludge phases. Each of the API Separators has a sewer systems are provided in the Phenosolvan design flowrate of 250 gpm. If the flowrates exceed 500 Unit. All normal oily water, cooling water, gas gpm during a rainstorm, the excess flow is diverted by the liquor, or rain water enter an open sump from splitter box to a pond for later processing. The oil that is which the liquid can be pumped into the plant skimmed off is pumped to the Slop Oil Sump, the Slop Oil oily water sewer system, the Gas Liquor Buffer Decanting Tank, and finally to the Slop Oil Tank in the Tank for reprocessing, or into the enclosed di- tank farm. The API Separator sludge is pumped to the isopropyl ether (IPE)/phenols sewer system tank froth sump and is then dewatered in the Vacuum Pre-coat within the Phenosolvan Unit. The open sump has Drum Filter. an underflow/overflow weir arrangement to separate the WE from the water phase. The The effluent from the API Separators is pumped to a rapid second sewer system is an enclosed system to mix section of the Dissolved Air Flotation (OAF) Floccu- contain and transmit IPE and phenols to an lation Tank where it is mixed with coagulants to break the underground tank for reprocessing in the oil emulsion and to coagulate and flocculate the phenosolvan extractors. suspended solids. The flocculated water is diffused with air to clarify the wastewater by the formation and Ammonia Recovery - Two separate sewer system attachment of fine air bubbles to the suspended matter, are provided in the Ammonia Recovery Unit to causing the material to be lifted to the liquid surface. isolate phosphate solution spills from gas liquor The froth is removed from the surface by means of and oily water. An underground tank collects surface skimming. Particulate matter that settles to the the ammonium phosphate solution and the bottom is collected by a bottom scraper. The froth and solution is then pumped from the tank back into the sludge are combined and fed to the Froth Bump and the process. The oily water sewerall in the combined with sludge from the API separator. The liquid ammonia recovery area transmits wastewater effluent from the DAF Unit is filtered and used as make- to a sump. The oily water can then be pumped up to the cooling tower. to either the plant oily water sewer system, the Gas Liquor Buffer Tank for reprocessing, or to a The API/OAF sludge is stored in the Froth Bump until a tank truck for chemical disposal. sufficient quantity is available to operate the Vacuum Pre-coal Drum Filter that is designed to filter the sludge • Gas Liquor Separation - A separate equipment at a feed rate of 30 gum. The solids from the filter are drainage system is provided in the Gas Liquor such that no free liquid drains from the discharged filter Separation Unit to allow all equipment drains cake while it is stored in bins prior to disposal in the and surface drainage to flow into an API pit. hazardous waste landfill. The liquid filtrate is recycled to Oily water, gas liquor, tar, and tar oil are the inlet of the API Separator.

4-58 SYNTHETIC FUELS REPORT, DECEMBER 1982 Gasification Wastewater Treatment acceptable level by Sasol). The overall cooling system was designed using Sasol's experience in their commer- The largest single stream of wastewater in the facility cial-size SGL cooling tower as well as test runs at Sasol is the gas liquor from the coal gasification process. using simulated Great Plains-type SGL in a small experi- The gas liquor stream consists of approximately 2300 mental cooling tower. gpm of water condensed from the gasifier raw gas and contaminated with tar, tar oil, coal dust, and dissolved The analysis of the gas liquor from the original gasifica- compounds such as phenols, ammonia, carbon dioxide, tion test in 1974 provided the foundation of simulating hydrogen sulfide, fatty acids, and traces of many other Great Plains gas liquor for the cooling tower tests done at compounds. Sasol. Great Plains gas liquor was found to have low concentrations of chlorides, fluorides, and hardness and, The gas liquor is collected in several areas of the plant in comparison to Sasol's gas liquor, was found to contain (Gasification, Gas Cooling and Rectisol) and is cooled higher concentrations of phenolics, fatty acids, and fixed prior to further processing. The Gas Liquor Separation ammonia. Therefore, Great Plains SGL was simulated by Unit is a simple three-stage decantation process. In the adding ammonium acetate (fatty acids) to Sasol SaL. A primary stage, dusty tar and clear tar are drawn off the comparison of the Sasol, Great Plains and simulated Great bottom of the tank while the gas liquor overflows into Plains SGL is presented in Table 2. the second stage. In both the second and third stages of separation, the light tar oil is skimmed from the top of Initial test results showed that the addition of fatty acids the separators. Finally, gravel filters remove residual had no adverse effect on the experimental cooling tower suspended tar and oil from the gas liquor. The Gas at Sasol or the systems associated with it. The corrosion Liquor Separation Unit is designed to remove in excess rates measured on the heat exchanger tubes were low (in of 99% of the residual dust, over 99% of the oils, and the range of 5 to 8 mills/year). Little fouling occurred in essentially all of the tar in the gas liquor. The final gas the system and foaming and sludge formation were also liquor product has approximately 100 ppm oils, 30 ppm very limited. dust, and virtually no tar. In subsequent tests, variables that were evaluated in more The gas liquor from the Gas Liquor Separation Unit still detail were chemical oxygen demand (COD), biochemical contains phenols, ammonia, and acid gases (H 2S and oxygen demand (BOD), and biological counts of both C09) which must be removed before using the water as aerobic and anaerobic bacteria. The purpose of the maRje-up to the cooling tower. The Phenosolvan Unit additional tests was to understand the mechanisms for the removes the phenols from the gas liquor in a series of reduction in total organics and to determine the extent mixer settler type extractors di-isopropyl ether (IPE) that biological activity is beneficial in the cooling tower. extracts the phenols from the gas liquor. The The overall results of the tests indicate that a reduction dephenolized gas liquor is stripped with nitrogen to of approximately 60% of the total organics occurred in remove the residual IPE. The IPE/phenol mixture from the system. the extractors is distilled to yield a crude phenol product and to recover the IPE. The phenosolvan Because the continuous operation of the cooling tower is process using IPE as a solvent has an extraction effi- vital to the overall plant operation, surge capacities both ciency of over 99% for mono-valent phenols and 90% upstream and downstream are provided. The three types for multi-valent phenols. The final gas liquor product of surge in the Great Plains plant design include the (1) contains a maximum of 30 ppm mono-valent phenol and 11.1-acre Cooling Tower Feed Storage Pond, (2) Multiple 135 ppm multi-valent phenol. Effect Evaporator Feed Storage Pond, and (3) Stripped Gas Liquor Surge Tank. An additional surge tank for The gas liquor from Phenosolvan Unit is treated further unstripped gas liquor is also provided upstream of the in the Phosam Unit to remove ammonia and acid gases. Phenosolvan Unit. The entire cooling water system has In the Phosam Unit, the dissolved éeid gases and been designed to mechanically withstand the. physical ammonia are first stripped from the gas liquor in a properties of the gas liquor and the severe North Dakota steam stripping section. In an absorber column, an climate. The tower is also designed to minimize drift ammonium phosphate solution absorbs the ammonia and losses by using adjustable louvers, variable speed fans, and the acid gases proceed overhead to the Sulfur Recovery high efficiency mist eliminators. Unit. The ammonia phosphate solution is stripped of ammonia and water and is recirculated to the absorber. The blowdown from the cooling tower is concentrated in The ammonia and water are distilled to produce the Multiple Effect Evaporator that is designed to con- anhydrous ammonia. The bottoms product of the steam centrate the blowdown by a factor of 10. Because the stripper, the stripped gas liquor (5GW, is used as make- cooling tower operates at 10 cycles of concentration, the up to the cooling tower. The SGL product from the two units together reduce the volume of the gas liquor by Phensom process contains a maximum of 150 PPM free a factor of 100. The evaporator design is similar to that ammonia and 500 PPM fixed ammonia. commonly used for liquid concentration in the pulp and paper industry. The evaporator design flowrate is 500 The heat load in the gasification facility is removed gpm with the normal expected flowrates being 395 gpm in using a cooling water system from a multieell, forced the summer and 375 gpm in the winter. The distillate draft, counter-flow-type cooling tower. The make-up product from the evaporator system is used as cooling to the cooling tower is both stripped gas liquor tower make-up and the evaporator concentrate product is (approximately 2000 gnm) and Zeolite softened water destroyed in the Evaporator Concentrate Incinerator. (100-1200 gpm). The cooling tower is designed to operate at 10 cycles of concentration (found to be an

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-59

TABLE 2 COMPOSITION OF SASOL, GREAT PLAINS, AND SIMULATED GREAT PLAINS STRIPPED GAS LIQUOR (SGL) Compound Concentration (mg/1) Sasol Great Plains Simulated Great Plains F 65 0.5 65 Cl 20 3 20 Ca 18 6 18 Na 55 18 55 Fatty Acid 400 1600 1600 Phenols 80 150 80 NH 175 500 1000 TOC 400 - 680 900 COD 1400-2500 2880 2000-3000

Sasol SGL spiked with ammonium acetate

Tests using Sasol cooling tower blowdown (spiked to The products of combustion at the outlets of the incinera- simulate blowdown from Great Plains) conducted by tor combustion chamber enter the quench system that is Aqua Chem, Inc., demonstrated that evaporator designed to cool the products of combustion to 200°F and distillate contained relatively high concentrations of to allow for efficient vapor/liquid separation. Lower ammonia and organics, thus making it unattractive for pressure boiler blowdown is the make-up water to the use as boiler feedwater. To maintain the overall quench system and blowdown from the quench system is integrity of the wastewater system, surge volumes both used as make-up to the ash disposal system. The upstream and downstream of the Multiple Effect quenched products of combustion proceed to a Venturi Evaporator are provided for shut-downs of either the Scrubber and Drop Separator to remove particulate evaporator or the Evaporator Concentrate Incinerator. matter and SO from the exhaust gas. The 2.4-acre Multiple Effect Evaporator Feed Storage Pond upstream of the evaporator has a design capacity The Gasification, Gas Liquor Separation, and Phenosolvan of nearly 8,000,000 gallons. Downstream of the Units have all been designed by Lurgi based on their evaporator, the Incinerator Feed Surge Pond is a 1.0 experience. The Phosam Unit is based on a process used acre pond with a capacity of over 3,000,000 gallons. by U.S. steelin the steel making industry and designed by Four alternate schemes, each using a multi-effect USS Engineers and Consultants. The Cooling Tower, evaporator to concentrate the gas liquor, were Multiple Effect Evaporator, and Evaporator Concentrate evaluated by Lummus. The four schemes include: (1) Incinerator systems are all package units that Lummus incinerating the concentrated waste in a thermal has specified and procured for Great Plains. The cooling oxidizer, (2) incinerating the concentrated waste in the water system has also been designed by Lummus based on gasification plant's super-heaters, (3) spray-drying the information provided by Sasol from their experience. concentrate and disposing of the dry waste in the mine, and (4) evaporating the waste using solar evaporation. Water Make-Up to Ash Handling The study results showed that the thermal oxidizer was the best solution from an economical as well as tech- The ash handling system is designed to quench, process, nical standpoint. and dispose of the gasifier ash. The hot dry gasifier ash passes from the gasifier to ash lock hoppers and then into The Waste Incinerator System is designed to oxidize the the ash sluiceway where water quenches the ash and organic materials in the aqueous waste feed stream or transports it to the ash sumps. The ash slurry is pumped evaporator concentrate. The incinerator system at to dewatering bins in Which the water overflows to a Great Plains is designed to comply with present EPA settling tank, followed by a surge tank, and finally returns regulations for stack emissions of SO, NO and, parti- to the ash sumps. This water is then returned to the ash culates as well as proposed EPA guid3lines combus- sluiceways as sluicing water. When one dewatering bin is tion temperature and residence time in the combustion full of ash, the slurry is diverted to a second dewatering chamber. Fuel for the incinerator consists of the by- bin, the first bin is dewatered (drained), and the ash is products of the gasification process (95% tar and 5% trucked to an approved solid waste disposal site in the tar oil). The combustion chamber is designed to coal mine. The make-up water to the ash handling system operate at 25% excess air, a temperature of 1800°F, is supplied by blowdown from the low pressure steam and a calculated retention time of 1.8 seconds. system and waste incinerator system. The total water make-up to the ash handling system varies based on the

4-60 SYNTHETIC FUELS REPORT, DECEMBER 1982 ash composition in the coal, but normal make-up rates are designed to be between 30 and 60 gpm. Ash leaching tests were conducted to determine trace element leaching characteristics of ash produced from the gasification of North Dakota lignite in a Lurgi gasifier. Dry ash samples were crushed, analyzed, and then slurried with dc-ionized water at ambient and elevated temperatures (120°F and 180°F) for 24 hours. The slurried ash water was then filtered and the filtrate was analyzed for the trace elements. The final analyses indicated very low concentrations of the twenty-two elements leached from the ash. Only boron (6 ppm), fluorine (2.4 ppm), and lithium (1.6 ppm) were found in concentrations above 1.0 ppm in the filtered water and only barium (0.6 ppm) and lead (0.4 ppm) were found in concentrations above 0.1 ppm. These test results are consistent with leachability tests completed by EPA that indicate no hazardous contaminants are leached from coal-based ash. Disposal of Hazardous Wastes A hazardous waste disposal area at the Great Plains plant has been approved for the disposal of potentially hazardous solid and liquid wastes. These waste products include ion exchange resins, activated carbon, sand and gravel filter media, catalysts, vacuum filter cake, oils and greases, solvents, acids, and caustic. To simplify the problem of waste handling and landfill area, a single hazardous waste landfill has been selected that is approximately 420 feet by 420 feet by 10 feet deep with a capacity of approximately 65,000 cubic yards of waste. The disposal site has been sized to contain the first 5 to 10 years of plant wastes. The waste disposal site is designed to have an impervious liner approximately 5 feet in thickness. Beneath the liner, a leachate collection system consisting of a ravel underdrain with a collection sump will be installed to detect any failure of the liner. Additionally, all liquid wastes will be placed in drums or other containers prior to disposal. These basic design guidelines were based on the criteria for hazardous waste landfills as specified by EPA. Summary The report by ANR is quite lengthy (412 pages) and contains a large amount of information and many detailed P&l diagrams. The wastewater treatment system to be used at Great Plains was developed over many years and at considerable expense. This treatment system may not be universally acceptable for other coal sources, other gasification processes, or other plant sites. However, the information in the report may be helpful in that it describes the methodology used to develop and refine the wastewater system design.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-61 RESOURCES

DOl BANS COAL LEASING TO RAILROAD-AFFILI- 1982, the Bureau of Land Management (BLM) announced ATED ENERGY FIRMS that the bid by Texas Energy Services, Inc. of Gillette, Wyoming along with Northwest Mutual Life Insurance for On December 7, 1982, Secretary of the Interior James the Rocky Butte tract would not be accepted. Texas Watt announced that the U.S. Department of the Energy's bid for the Rocky Butte tract was at the Interior (001) will halt future leasing of Federal coal minimum bid level of $2,300/acre for a total of deposits to energy firms that are corporate affiliates of $11,168,800. Recoverable reserves are reported to be 445 common-carrier railroads. The Secretary's decision not million tons which results in a bonus bid of 2.5 to lease to rail company affiliates reverses a six-year- cents/recoverable ton of coal. Texas Energy immediately old policy and effectively removes inconsistencies in appealed BLM's rejection of the Rocky Butte tract bid the positions taken by the Interior and Justice Depart- calling the decision to reject the bid, "arbitrary, discrimi- ments during the past Administration. The Secretary's nating, capricious, and totally without merit." Later, a decision came after a legal opinion issued by Interior three-judge panel of the Interior Board of Land Appeals Solicitor William H. Coldiron which modifies Interior's agreed to a settlement between the attorneys for the legal interpretation of Section 2(c) of the Mineral Department of the Interior (001) and Texas Energy in Leasing Act of 1920. Coldiron's opinion holds that the which Texas Energy would withdraw the appeal in ambiguous language of Section 2(c) may reasonably be exchange for a government assurance that the Rocky construed in more than one way, and that Interior's Butte tract would be reoffered in a follow-up Powder policy should be changed to conform with that of River basin lease sale to be held in October of 1982. Justice. Existing coal leases held by railroad affiliates are not affected by Watt's new policy, however. At the time BLM announced the rejection of the bid for the Rocky Butte tract, they also withheld acceptance of An earlier Interior Solicitor cited the legislative history the high bid for the Coal Creek tract by Wcsco Resources. of the disputed Section 2(c) as indicating that Congress The Coal Creek tract, containing 60 million tons of intended to allow railroad affiliates to lease coal. The recoverable reserves, was offered as a small business set Justice Department's Antitrust Division in 1980 dis- aside. Coal Creek Coal Mining Company also bid agreed with Interior. Both Departments endorsed the unsuccessfully for the Coal Creek tract, but following the repeal of Section 2(c) by the 97th Congress, but Con- sale, challenged Wesco's right to bid as a small business. gress did not pass legislation on this request. The Small Business Administration in Denver then ruled that Wesco did qualify as the high bidder for the Coal The new Coldiron opinion asserts that close examina- Creek tract. The high bid on the Coal Creek Tract in tion shows the legal issues "have more than one reason- Montana was subsequently accepted by the BLM. able construction." As a consequence, Coldiron recommended that the Secretary adopt the Justice Depart- Justice Department Enters Review ment position for a unified Administration policy. A copy of Coldiron's new opinion is included in the The Justice Department's initial review of the high Appendix in this issue of the Pace Synthetic Fuels bidders qualifications to bid in the lease sale resulted in Report. their withholding approval on Shell Oil Company's and Thermal Energy Company's bid. Shell Oil submitted a bid of $25.9 million for the Spring Draw tract containing 323 million tons of reserves. The Justice Department POWDER RIVER BASIN LEASING ACTIVITIES requested additional information from Shell Oil Company on its ownership and other coal holdings. After Shell A great deal of activity relative to leasing has occurred provided details on Royal Dutch Shell which owns 69% of since the Powder River basin coal lease sale in Shell Oil and coal holdings through their part ownership of Cheyenne, Wyoming, on April 28, 1982, (see the Pace AT Massey Coal, the Justice Department approved Shell Synthetic Fuels Report, June, 1982 page 4-53 Fr -a as a qualified bidder. The Justice Department withheld description of the lease sale). In that sale, thirteen approval on the Thermal Energy Company bid ($4.5 for tracts were offered and eleven of those tracts received the Cook Mountain tract) because of a sister company's bids. A discussion of the activities relative to the minority interest in the proposed Tongue River Railroad. leasing program are presented in the following. The proposed railroad would serve the proposed rail- isolated Montco mine in the Montana portion of Powder Mineral Management Service Review Bids River basin. The Department of Justice was concerned with Thermal Energy as a qualified bidder as they feared The Mineral Management Service (MMS) received each that provision 2C of the Mineral Lands Leasing Act of eleven high bids to determine if they achieved "fair prohibiting common carrier railroads from leasing Federal market value." Criteria used in determining "fair coal would be violated. After more indepth review of market value" includes but is not limited to: bidder information supplied by Thermal Energy, the Department participation; and the amount of the high bid in com- of Justice also approved Thermal Energy as a qualified parison to bids for other tracts in the sale. On June 4,

4-62 SYNTHETIC FUELS REPORT, DECEMBER 1982 bidder. In a related incident, (described in more detail construction of the mine and equipment purchase; pay- elsewhere in this issue), Interior has sided with the ment of annual rentals and production royalties; and Department of Justice in prohibiting railroads from payment of Federal state, and local taxes. As an leasing federal coal. Over the recent past, Interior and example, the federal royalty rate for surface mined coal Justice were split over whether or not railroads were is 12-1/2% of its value. At a selling price of $7.00/ton, qualified to hold Federal coal leases. the potential royalty value of the 1.56 billion tons of Powder River basin coal would be $1.36 billion. From this Follow-Up Leasing example it is apparent that the bonus bids are but a small fraction of potential government revenue from Federal In early September, 1982, the Department of Interior coal. Some of the coal will not be mined for many years, announced a follow-up lease in the Powder River basin but at the same time, the selling price of Powder River consisting of two tracks in Wyoming and three tracts in basin coal should increase significantly which will Montana. The Wyoming tracts were to be offered on increase royalty revenue. October 15, 1982, in Cheyenne and the Montana tracts were to be offered on October 20, 1982, in Billings. Pace believes the critics of Federal coal leasing are short The Wyoming tracts were to consist of the Rocky Butte sighted. A no leasing or minimum amount of leasing and Fortin Draw tracts. Rocky Butte tract was offered policy will insure reduced supplies of coal in the future in the first round, but the high bid from Texas Energy which will drive up the price of coal. High leasing costs was rejected by BLM as the bid did not meet "fair to industry will have the same affect, because much of market value". The Fortin Draw tract was withdrawn the offered coal would go unleased. The ultimate coal from the first round sale because there was some consumers (utility customers) would pay dearly if the question as to the recoverable reserves. The three critics of leasing were to have their way. Ironically, the tracts in Montana consisted of: the Spring Creek tract critics of leasing would have the public believe them to be (280 acres with 20 million tons recoverable); the North consumer advocates. Decker I tract (510 acres with 16.6 million tons); and the North Decker II tract (921 acres with 30 million AMAX Gets Three Leases tons). North Decker I and North Decker II were part of the North Decker tract offered in the first round. AMAX received two leases, Little Rawhide and South Neither the Spring Creek tract or the North Decker Duck Nest Creek, in the April 28 lease sale. The Little tract received bids in the first round lease sale. Rawhide tract will add 90 million tons of coal along the western portion of the AMAX Eagle Butte Mine. The Later in the month of September, Interior withdrew the South Duck Nest Creek lease will add 143 million tons on three tracts in Montana because of the relative lack of the southeast corner of AMAX'S Belle Ayr Mine. In interest in leasing coal in that area at the time. addition to these two leases, AMAX received a lease on the North Duck Nest Creek tract. This tract, consisting The second round lease sale in Cheyenne was conducted of 1,433 acres and containing 180 million tons of recover- on October 15, 1982 and the Fortin Draw tract and the able coal, was not offered for lease in the Powder River Rocky Butte tract both received a single bid. Texas basin lease sale. AMAX earned its right to purchase the Energy Services was the sole bidder ($23,337,600) for lease by relinquishing its prospecting permits on the the Rocky Butte tract and WyoDak Resource Develop- Northern Cheyenne Indian Reservation in Montana. ment Corp. was the sole bidder ($1,352,032) for the AMAX paid $4.4 million for the North Duck Nest Creek Fortin Draw tract. Table I summarizes the details of tract. North Duck Nest Creek will provide an additional the sale of the two tracts. The Fortin Draw tract is a 180 million tons of reserves along the Northwest Corner maintenance tract to provide additional reserves for of the Belle Ayr Mine. AMAX's Belle Ayr Mine holds the the WyoDak mine. Texas Energy's bid for the Rocky annual production record for a single coal mine at 18.1 Butte tract in the second round of leasing was exactly million tons per year in 1978. The South Duck Nest Creek two times greater than their bid for that tract in the and North Duck Nest Creek should extend the life of Belle first round. The Mineral Management Service has Ayr by about 20 years depending on the rate of produc- accepted the bid as meeting fair market value. tion. Controversy Relative to Coal Leasing High Regional Coal Team Preparing For '84 Sale Amidst the activity related to leasing, has been a The Powder River basin Regional Coal Team met in fountain of criticism alleging "give aways" and impro- Casper, Wyoming on October 21, 1982 to initiate planning prieties. The element that is missing in the arguments for the 1984 Powder River basin coal lease sale. At the surrounding the bonus bids for coal leases is a present, ranking and track selection should be complete consideration of the revenues that will enter govern- by May of 1982. The Draft Environmental Impact State- ment coffers through production royalties. The April ment should be complete by October, 1983. The lease 28 and October 15 Powder River basin lease sales sale is scheduled for the summer of 1984 (August 16, resulted in the leasing of over 1.56 billion tons of 1984). Land use planning for the sale is nearing com- Federally administered recoverable coal. The total of pletion. Thirteen expressions of interest had been the high bonus bids (accepted by the BLM) for that coal received for the Wyoming portion of the basin from which is approximately $68.2 million or about 4.4 cents per the RCT expected to delineate 16 to 18 tracts. These recoverable ton. This value is small relative to the tracts will then be ranked and tract selection for leasing selling price of a ton of coal but in no way reduces completed by May 6, 1982. The Montana portion had expenditures for: planning and detailed design required received on the order of 6 expressions from which a for preparation of mining and reclamation plan; actual

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-63 TABLE 1 SUMMARY SECOND HOUND POWDER RIVER BASIN LEASE SALE Recoverable Company Bid Reserves Tract Location (106Tons)_ Total $/aere (0/ton High Bidder Fortin Draw T.SON., R.72W., 27 $1,352,032 $4,225.10 5.0 WyoDak Resources Campbell County, Wyo. Development Co. 320 acres Rocky Butte T.48N., R.71W., 445 23,337,600 4,806.39 5.2 Texas Energy T.49N., R.71W., Services Campbell County, Wyo. 4,855.54 acres

number of tracts (to include recycled tracts not sold GREEN RIVER-HAMS FORK REGION LEASING ACTI- during the previous sale) will be delineated. VITIES In addition to preparing for the 1984 lease sale, the Following the sale of the Danforth Hills No. 2 and RCT is considering six coal ownership exchanges. Danforth Hills No. 3 Federal coal leases on April 6, 1982, These six exchanges are for coal reserves underlying (see Synthetic Fuels Report, June 1982, Page 4-62, for and adjacent to the Interstate 90 right-of-way. The details) activities relating to coal leasing have been lands to be exchanged are presently being evaluated to associated with "housekeeping" chores and the initial determine the resource value. The following six com- preparation for the next lease sale scheduled for March of panies are involved in the exchange procedure: Exxon, 1984. A summary of the more significant actvities WyoDak, Kerr-McGee, Belco, Gulf, and Bid Horn Coal. related to coal leasing in the Green River-Hams Fork Region follows. The next RCT meeting is scheduled for January 18, 1982, at which time all tract delineations should be Possible Coal Lease Tracts Delineated completed. BLM and Minerals Management Service has delineated 25 Pending Lawsuits tracts for possible leasing in the Green River-Hams Fork Coal Region. Twelve of these tracts are located in the The National Wildlife Federal, et.al .'s suit to block Wyoming portion of the region and thirteen are located in awarding of the Powder River Basin continues. At the the Colorado portion of the region. The delineation of time of this writing oral arguments before a Federal possible tracts for leasing follows the submittal of judge in Billings, Montana had ended. The plaintiffs "expressions of interest" and application of the "unsuit- contend that BLM did not receive fair market value for ability criteria". The tracts now delineated will be ranked the coal and further that the land use planning was and depending upon the desired leasing level, a certain inadequate. The plaintiffs complained that the sale was number of these tracts will be offered in the Green River- characterized by little or no competition which was the Hams Fork lease sale in March, 1984. Figure 1 through result of the poor coal market conditions and charge Figure 5 show the locations of the tracts which have been that the sale should have been postponed to a later date delineated in five different coal fields or planning areas. when the coal market was better. Three of the tracts delineated on the figures will not be pursued any further by ELM at this time. These three The plaintiffs have been challenged by Wyoming's tracts include: Cooper Ridge and Big Flat (see Figure 2), Attorney Generals Office to show "standing," as the and Kindt Basin (see Figure 3). plaintiffs did not have anything to lose even if the government did not receive the best price for the coal. The ELM has also released preliminary estimates of Wyoming receives 50% of the bonus bids, rentals and inplace and recoverable tonnages for the tracts. Table 1 royalties and reportedly is completely satisfied by the summarizes the preliminary estimates of the delineated bids accepted by BLM. resource base. More detailed tract profiles will be available from the BLM in the near future. As shown by A lawyer for Shell Oil Company (high bidder on the Table 1, the tracts which have been delineated contain Spring Draw tract) disagrees with the plaintiffs about 760 million tons of recoverable coal. These tracts arguments related to the land use planning and contends have been delineated to include other fee coal within that the plaintiffs could have participated in the their boundaries in order to offer more logical mining planning process prior to the lease sale but waited to units. The total recoverable reserve for both Federal and file a law suit. other fee coal for the delineated tracts is about 1.04 billion tons. Another interesting factor is that Federal coal contributes only about one half of the total recoverable reserves delineated in Wyoming. The large percentage of other fee coal is due to the location of the tracts

4-64 SYNTHETIC FUELS REPORT, DECEMBER 1982 1.ISSdJflpa.ait- riIr ----•--

41 ruearanr • 3 tiiw __ jr .— 7

II I-ti lLtuJj14.

FIGURE 1 TRACTS DELINEATED FOR POTENTIAL LEASING KEMMERER FIELD AREA, WYOMING

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-65 1.1' 1s1. I.E i.} 14 1.1. 'F

-'C

•1' u . I I I -p

-I, 1aCIi1WDLilitl MR • t

•i.

4:4 it ii [tg ILl 4-

FIGURE 2 TRACTS DELINEATED FOR POTENTIAL LEASING, ROCK SPRINGS FIELD AREA

4-66 SYNTHETIC FUELS REPORT, DECEMBER 1982 89 88 ST 88 85 84 83 82 I' Y L "t''rc-001 —I / H Ij J'\ /' —°/ii \ I CO RRAL CREEK - I 2 (24 / IV iji,_—\ 23 r—'c4— \ 4 ) 24 23 WILD HORSE DRAW

M&4 INDIAN SPRINGS ir S tv\4;1: / 21 ______1 92 88 85

q 20

20 1 21q- I__ (/ DttttS22 - N A CS_ ,e%tIlnh/ 19 1/ ..ØISATLANTIC RIM =C' \Th-4---- \^T' T BASIN

/I Ise \6 / L. ¶L-' 'j ; '—'LY -' _A 1)/Lt3- 4 C 717 NORTH EAST COW CREEK.-____ J

)fl \-c/ N 4r!tC-' -71J

10 IS 20npes SCALE

DELINEATED TRACTS

EXISTING LEASES

FIGURE 3 TRACTS DELINEATED FOR POTENTIAL LEASING GREAT DIVIDE BASIN, LITTLE SNAKE RIVER AREA

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-67 94 93 92 Be 87 Be -T Th 20 TJDAROZA4LEI'^IH LAY TRACT 8

7 (2 HORSE GULCH 9 I t4 SIGNAL BUTTE 2maêXic95 jrIAMSFoRKr113 TROUT CREEK 106 112 5 10 i ISLES MOUNTAIN /\ 1 2 4IPao4.' L. ctJ •Vki 1L.. NO,90 NT H, e '' • Moflal,I,L._, L.....wfL_._4JLy 131 - , . —-r'2 102 5WjF ri Z PEI / 1304 / mallull, .rA c li 129 * ',.ctC,tti 6 ., FISH CREEK 1 Ô9 '' - -L

14 s2747577.Ihmnu 3 Ay ,. n bw Q LITTLE MIDDLE CREEK MIDDLE CREEK RATTLESNAKE .2

L0 EST.j,2 \ 4 • 87 tD .

\8182 . I 145 ? . ee^er tq,

11. 94 ^05 BASE 92 LINE 91 a 09 J so ______

0 0 5 20.n'Ies I 5I I SCALE

DELINEATED TRACTS

EXISTING LEASES

FIGURE 4 TRACTS DELINEATED FOR POTENTIAL LEASING, YAMPA COAL FIELD, COLORADO

4-68 SYNTHETIC FUELS REPORT, DECEMBER 1982 lz •1?SIIIIUSWIJI!tiLir±t*1Ifl INNS S as a II!dLa1 —IS

ML -II 1t•-pr, wa• -'w ___ SWLttu1II 15 2DrnpPe, 5 SCALE

DELINEATED TRACTS

EXISTING LEASES

FIGURE 5 TRACTS DELINEATED FOR POTENTIAL LEASING LOWER WHITE RIVER FIELD AREA, COLORADO

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-69 TABLE 1 PRELIMINARY ESTIMATES OF COAL RESOURCES FOR DELINEATED TRACTS (Million Tons)

Federal Coal Federal Plus Others

Area/Tract Inplace Recoverable lnplace Mineable Recoverable WYOMING: Kemmerer Field: Tract 98 3.8 3.4 3.8 3.8 3.4 Byrne Creek 38.1 7.2 80.9 20.0 17.0 Total 41.9 10.6 84.7 23.8 20.4 Rock Springs Field:

Winton 40.4 20.2 145.9 145.0 72.5 Leucite Hills 54.8 6.5 97.1 20.9 17.7 Deadman 3.4 0.3 3.4 0.3 0.3 Point of Rocks 34.0 13.6 66.0 26.6 22.6 Pio 133.4 11.1 133.4 13.0 11.1 Total 266.0 51.7 444.9 205.8 124.2 Great Basin-Overland Field: Indian Springs 44.0 25.0 86.1 70.0 49.0 Atlantic Rim 164.0 79.2 382.2 204.7 178.1 N.E. Cow Creek 192.2 82.8 212.1 183.2 91.6 Corral Canyon 25.6 22.3 83.0 83.0 72.2 Wild Horse Draw 10.3 4.5 1 23.7 13.9 12.1 Total 436.1 213.8 787.1 554.8 403.0 Wyoming Total 744.0 276.1 1,316.7 784.4 547.6

COLORADO: White River Field: Prairie Dog 147.0 44.0 147.0 87.5 44.0

Yampa Field: Rattlesnake 117.7 38.0 117.7 76.0 38.0 Lay 65.5 55.7 72.2 57.7 57.7 Signal Butte 257.8 79.9 257.8 145.5 79.9 Horse Gulch 8.3 7.0 8.3 7.0 7.0 Bell Rock 176.0 39.0 176.0 78.3 39.0 Isle Mountain 38.0 33.5 38.0 33.5 33.5 Williams Fork 45.9 39.9 45.9 39.9 39.9 Peck Gulch 112.8 44.4 112.8 88.7 44.4 Little Middle Creek 53.0 24.8 53.0 24.8 24.8 Fish Creek 130.7 63.2 138.7 68.0 68.0 Middle Creek 26.6 5.5 26.6 11.0 5.5 Trout Creek 21.0 10.0 21.0 10.0 10.0 Colorado Total 1,200.3 484.9 1,215.0 727.9 491.7 GreenRiver - liamsForkTotal 1,944.3 761.0 2,531.1 1512.3 1,039.3

4-70 SYNTHETIC FUELS REPORT, DECEMBER 1982 within the Union Pacific Railroad checkerboard land grant. Red Rim Controversy The controversy over the Red Rim area (south and west of Rawlins, WY) continues. The area was tentatively scheduled for tests of "cooperative leasing" or leasing of Federal coal in cooperation with fee coal holders. In the Red Rim case, Federal coal would be leased in cooperation with coal held by the Union Pacific Corp., (railroad land grant). The National Wildlife Federation with support from the Wyoming Fish and Game Depart- ment contends that the area is critical winter habitat for antelope. The other concern is that any cooperative agreement may violate Section 2e of the Mineral Land Leasing Act which prohibits railroads from leasing Federal coal. Red Rim, Cooper Ridge, and Big Flat will not be considered by BLM at this time for the 1984 Green River-Hams Fork coal lease sale due to controversy over those tracts' possible contribution to wildlife winter range. As described elsewhere in this issue, Department of Interior has changed its position on leasing Federal coal to railroads and now sides with the Justice Department in prohibiting railroads from leasing Federal coal. Gulf's Savery PRLAs Unsuitable The Savery Coal Draft Environmental Impact State- ment issued in September 1982, recommends that a "no development" alternative is preferred over the foreseeable future (15 - 20 years). The primary reason for the "no development" alternative is the socioeconomic impact projected for the area. The Savery Project Area is located adjacent to the Colorado-Wyoming state line, along the Little Snake River, in the vicinities of the towns of Dixon and Savery, Wyoming, and Slater, Colorado. Gulf acquired nine Preference Right Lease Applications (PRLA5) in the Savery area as a result of its acquisition of the Kemmerer Coal Company. These PRLAs are the focus of the EIS and any potential development in the area. fiLM has made its intentions clear in that they do not want any coal development in the Savery area. However, BLM also must consider the PRLAs and Gulf's intention to take them to lease. One possible alternative is for BLM to proceed with the processing of the Preference Right Lease Applications and if leases are in fact due to Gulf, then those leases would be issued. After the PRLAs become leases, then BLM would exchange those leases for other Federal coal. The exchanges would probably be accomplished in a fashion similar to AMAX's exchange of PRLAs in the Montana portion of the Powder River basin for a coal lease adjacent to its Belle Ayr Mine near Gillette, Wyoming. I

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-71 STATUS OF COAL PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name A. C. Valley Corporation A. C. Valley Corporation Project ...... 4-81 AIRCO, Inc. Medium Btu Synthesis Gas Study ...... 4-101 Air Products and Chemicals, Inc. Keystone Project ...... 497 North Alabama Coal Gasification Consortium ...... 4-105 Solvent Refined Coal Demonstration Plant (SRC-l) . . . 4-108 Allis-Chalmers KILnGAS Project ...... 4-98 Amax, Inc. Amax Coal Gasification Plant ...... 4-81 American Natural Resources Great Plains Gasification Project ...... 493 American Natural Service Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Amerigas, Inc. Keystone Project ...... 497 Mining and Industrial Fuel Gas Group Gasifier ...... 4-192 AMTAR, Inc. Alabama Synthetic Fuels Project ...... 4-81 Anderson, Arthur Gulf States Utilities Project ...... 4-95 ANR Gasification Properties Company Great Plains Gasification Project ...... 493 Ansaldo Fiat/Ansaldo Project ...... 4-90 Applied Energetics, Inc. Alabama Synthetic Fuels Project ...... 4-81 ARCO Underground Coal Gasification - Rocky Hill Project .... 4-115 Exxon Donor Solvent Process Development ...... 4-89 Arkansas Power & Light Company Central Arkansas Energy Project ...... 4-83 Ashland Synthetic Fuels, Inc. H-Coal Pilot Plant ...... 4-96 Baltimore Gas and Electric KILnGAS Project ...... 4-98 Basic Resources, Inc. Underground Coal Gasification -University of Texas .... 4-113 Underground Gasification of Texas Lignite- Tennessee Colony Project ...... 4-116 Basin Electric Great Plains Gasification Project ...... 4-93 Baukol-Noonan Coal Co. North Dakota Synthetic Fuels Project ...... 4-106 Bechtel Inc. Breckinridge Project ...... 4-82 Cool Water Coal Gasification Project ...... 4-86 Medium BTU Synthesis Gas Study ...... 4-101 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Bethlehem Steel Corporation Keystone Project ...... 4-97 Low/Medium BTU Gas for Multi-Company Steel Complex. . 4-100 Billings Energy Corporation Forest City Coal Gasification Project ...... 4-91

4-72 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name Page

Black, Sivalls & Bryson, Inc. Lignite Briquette Gasification Plant ...... 4-99 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 British Department of Energy National Coal Board Liquid Solvent Extraction Project . . . 4-104 National Coal Board Low-Btu Coal Gasification Project . . . 4-104 British Gas Corporation Slagging Gasifier Project ...... 4-108 Brookhaven National Laboratory Flash Pyrolysis of Coal With Reactive and Non-Reactive Gases 4-90 Brooklyn Union Gas Company New England Energy Park ...... 4-104 Burlington Northern, Inc. Circle West Project ...... 4-84 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Caterpillar Tractor Company Caterpillar Tractor Low Btu Gas From Coal Project . . . . 4-82 Celanese Corporation Celanese Costal Bend Project ...... 4-83 Celanese East Texas Project ...... 4-83 Central Illinois Light Co., Inc. KILnGAS Project ...... 4-98 Central Maine Power Central Maine Power Co.'s Sears Island Project ..... 4-83 Central Power and Light Chemically Active Fluid Bed Project ...... 4-83 Cities Service Integrated Two Stage Liquefaction ...... 497 LC Fining Processing of SRC Extract ...... 4-99 Clark Oil and Refining Corp. Clark Synthesis Gas Project ...... 4-85 Cleveland-Cliffs Iron Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Coal Fuel Conversion Co. Ott Hydrogenation Process ...... 4-106 COGAS Development Company COGAS Process Development ...... 4-86 Combustion Engineering Two-Stage Entrained Gasification System ...... 4-111 CONOCO Il-Coal Pilot Plant ...... 4-96 Medium BTU Synthesis Gas Study ...... 4-101 Consolidated Gas Supply Corp. COGAS Process Development ...... 4-86 Consolidation Coal Company Underground Coal Gasification, Pricetown Project . . . . . 4-115 Consumer Energy Corporation Combined Cycle Coal Gasification Energy Centers 4-86 Consumers Power Company KILnGAS Project ...... 4-98 Cook Inlet Region, Inc. Beluga Methanol Project ...... 4-81 Cooperative Power Association North Dakota Synthetic Fuels Project ...... 4-106 Crow Indian Tribe Crow Indian Coal Gasification Project ...... 4-87 Curtiss-Wright Corporation Gas Turbine Systems Development ...... 4-79 Davy McKee Corporation Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Department of Energy BI-GAS Project ...... 4-81 Cities Service/Rockwell Process Development ...... 4-81 Crow Indian Coal Gasification Project ...... 4-87

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-73

Company or Organization Project Name Exxon Donor Solvent Process Development ...... 4-89 Fast Fluid Bed Gasification ...... 4-90 Flash Pyrolysis of Coal With Reactive and Non-Reactive Gases 4-91 Flash Pyrolysis Coal Conversion ...... 4-91 Florida Power Combined Cycle Project ...... 4-91 Gas Turbine Systems Development ...... 4-91 Gasification Environmental Studies ...... 4-92 Grace Coal-to-Methanol-to-Gasoline Plant ...... 4-92 GREFCO Low-Btu Project ...... 444 Gulf States Utilities ...... 445 Hampshire Gasoline Project ...... 495 H-Coal Pilot Plant ...... 4-96 Integraged Two-Stage Liquefaction ...... 447 Keystone Project ...... 4-97 LC Fining Processing of SRC Extract ...... 499 Low-Medium BTU Gas For Multi-Client Steel Complex 4-100 Low-Rank coal Liquefaction Research ...... 499 Memphis Industrial Fuel Gas Demonstration Plant ..... 4-101 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Minnegasco High-Btu Gas From Peat Feasibility Study 4-102 Minnegasco Peat Gasification Project ...... 4-102 Molten Salt Process Development ...... 4403 Mountain Fuel Coal Gasification Process ...... 4-103 New England Energy Park ...... 4-104 North Dakota Synthetic Fuels Project ...... 4406 Philadelphia Gas Works Synthesis Gas Plant ...... 4-106 Solvent Refined Coal Demonstration Plant SRC-1 ..... 4-108 Transco Coal Gas Plant ...... 4-110 Two-Stage Entrained Gasification System ...... 4-111 Union Carbide Coal Conversion Project ...... 4-112 University of Minnesota Low-BTU Gasifier for Commercial Use ...... 4-112 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-112 Underground Coal Gasification Hanna Project ...... 4-114 Hoe Creek Project ...... 4-114 Mitchell Energy ...... 4-113 Pricetown Project ...... P4-115 Steeply Dipping Bed Project ...... 4-116 Tono Project ...... 4-116 University of Texas ...... 4-113

Dow Chemical Dow Coal Liquefaction Process ...... 4-87 Dravo Engineers and Constructors Gulf States Utilities Project ...... 4-95 Keystone Project ...... 497 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Eastern Gas and Fuel Associates New England Energy Park ...... 4-104 EG&G New England Energy Park ...... 4-104 Electric Power Research Institute Cool Water Coal Gasification Project ...... 4-86 Exxon Donor Solvent Process Development ...... 4-89 H-Coal Pilot Plant ...... 4-96 KILnGAS Project ...... 4-98 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Two Stage Entrained Gasification System ...... 4-111 Elgin-Butler Brick Co. Lignite Briquette Gasification Plant ...... 499 El Paso Natural Gas Company Burnham Coal Gasification Project ...... 4-82

4_74 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name

Emery Synfuels Associates Emery Coal Conversion Project ...... 4-88 Empire State Electric Energy Research Corporation (ESEERCO) Cool Water Coal Gasification Project ...... 4-86 ENEL (Italian State Utility) Fiat/Ansaldo Project ...... 4-90 Energy Impact Associates Gulf States Utilities Project ...... 495 Keystone Project ...... 497 Energy Transition Corporation Chokecherry Project ...... 4-84 Grants Coal to Methanol Project ...... 4-93 Peat Methanol Associates Project ...... 4-106 Enrecon, Inc. Enrecon Coal Gasifier ...... 4-88 ENI Exxon Donor Solvent Process Development ...... 4-89 Environmental Protection Agency Chemically Active Fluid Bed Project ...... 4-83 Underground Coal Gasification - University of Texas .... 4-113 European Economic Community Fiat/Ansaldo Project ...... 4-90 Extractive Fuels Inc. Underground Coal Gasification ...... 4-113 Exxon, USA Catalytic Gasification Process Development ...... 4-89 Donor Solvent Process Development ...... 4-89 Exxon East Texas Project ...... 4-90 Exxon Wyoming Project - Coal Gasification ...... 4-90 Fiat TTG Fiat/Ansaldo Project ...... 4-90 Florida Power Corporation Florida Power Combined Cycle Project ...... 4-91 FMC Corporation COGAS Process Development ...... 4-86 Ford, Bacon & Davis Mountain Fuel Coal Gasification Project ...... 4-103 Forest City, Iowa Forest City Coal Gasification Project ...... 4-91 Foster Wheeler Energy Corporation Chemically Active Fluid Bed Project ...... 4-83 Memphis Industrial Fuel Gas Demonstration Project 4-101 Froedtert Malt Corp. North Dakota Synthetic Fuels Project ...... 4-106 Gas Research Institute Exxon Catalytic Gasification Process Development 4-89 Minnegasco Peat Gasification Project ...... 4-102 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-112 General Electric Company Central Maine Power Co.'s Sears Island Project ..... 4-83 Cool Water Coal Gasification Project ...... 4-86 Gas Turbine Systems Development ...... 4-91 IGCC Simulation ...... 4-96 General Refractories Company GREFCO Low-Btu Project ...... 4-84 W.R. Grace and Company Grace Coal-to-Methanol-to-Gasoline Plant ...... 4-92 Grand Forks Energy Technology Center Gasification Environmental Studies ...... 4-92 Low-rank Coal Liquefaction Research ...... 4-99 Great Plains Gasification Associates Great Plains Gasification Project ...... 4-93

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-75 Company or Organization Project Name

Gulf Research & Development Corp. Underground Coal Gasification - Steeply Dipping Beds . . . 4-116 Gulf States Utilities Company Gulf States Utilities Project ...... 4-95 Hampshire Energy Group Hampshire Gasoline Project ...... 495 Hanna Mining Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Hoffman, E. J. King-Wilkinson/Hoffman Project ...... 4-98 Houston Natural Gas Corp. Medium BTU Gasification Project ...... 4-101 North Alabama Coal Gasification Consortium Project 4-105 Howmet Aluminum Corporation Howmet Aluminum Project ...... 4-96 Hydrocarbon Research, Inc. Breckinridge Project ...... 4-82 Fast Fluid Bed Gasification Project ...... 4-90 H-Coal Pilot Plant ...... 4-96 Illinois Power Company KILnGAS Project ...... 4-98 Illinois, State of KILnOAS Project ...... 4-98 Inland Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-100 Institute of Gas Technology Memphis Industrial Fuel Gas Demonstration Project 4-101 Integrated Carbons Corporation Purged Carbons Project ...... 4-107 Inter-City Gas Corporation Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 International Coal Refining Co. Solvent Refined Coal Demonstration Plant (SRC-1) 4-108 InterNorth North Dakota Synthetic Fuels Project ...... 4-106 Iowa Power & Light Company KILnGAS Project ...... 498 Iowa, State of Forest City Coal Gasification Project ...... 4-91 Japan Coal Liquefaction Development Co. Exxon Donor Solvent Process Development ...... 4-89 Japan Cool Water Program (JCWP) Partnership Cool Water Gasification Project ...... 4-86 Johnstown Area Regional Industries, Inc. Keystone Project ...... 4-97 Jones and Laughlin Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-100 Kaneb Services Hampshire Gasoline Project ...... 4-95 Kentucky, Commonwealth of H-Coal Pilot Plant ...... 4-96 Solvent Refined Coal Demonstration Plant - SRC-I . . . . 4-108 Tri-State Project ...... 4-110 Kidder, Peabody & Co., Inc. North Alabama Coal Gasification Consortium Project. - 4-105 King-Wilkinson, Inc. King-Wilkinson/Hof I man Project ...... 4-98 Koppers Co. Hampshire Gasoline Project ...... 4-95 Peat Methanol Associates Project ...... 4-106 Tennessee Synfuels Associates Mobil-M Plant ...... 4-109 Laramie Energy Technology Center Underground Coal Gasification - Hanna Project 6.... 4-114 Lawrence Livermore Laboratory Underground Coal Gasification - Hoe Creek Project .... 4-114 Underground Coal Gasification - Tono Project ...... 4-116

4-76 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name Page Lehman Brothers Kuhn Loeb, Inc. Keystone Project 4-97 Lummus Company Integrated Two Stage Liquefaction ..... 4-97 Mansfield Carbon Products Mining and Industrial Fuel Gas Group Gasifier 4-102 Mapco Synfuels Mapco White County Project ...... 4-96 MCN Coal Gasification Company Great Plains Gasification Project 4-93 Memphis Light, Gas and Water Memphis Industrial Fuel Gas Demonstration Project 4-101 Meridian Land and Mineral Company Circle West Project 4-84

Metropolitan Life Insurance Co. Hampshire Gasoline Project ...... 4-95 Michigan Wisconsin Pipe Line Co. Great Plains Gasification Project 4-93 MidCon Corporation Great Plains Gasification Project 4-93

Mid South Synfuels Inc. Memphis Industrial Fuel Gas Demonstration Project 4-102 Minnesota Department of Natural Resources Mining and Industrial Fuel Gas Group Gasifier 4-102 Minnesota Gas Company Minnegasco High-Btu Gas From Peat Feasibility Study 4-102 Minnegasco Peat Gasification Project 4-102 North Dakota Synthetic Fuels Project 4-106 Minnkota Power Cooperative North Dakota Synthetic Fuels Project 4-106

Mitchell Energy Underground Coal Gasification 4-113

Mobil Oil Fl-Coal Pilot Plant ...... 4-96 Mono Power Company Emery Coal Conversion Project ...... 4-88

Monongahela Power Company KILnGAS Project 4-98 Montana Dakota Utilities North Dakota Synthetic Fuels Project 4-106 Morgantown Energy Technology Center Underground Coal Gasification - Pricetown Project 4-115

Mountain Fuel Resources, Inc. Emery Coal Conversion Project ...... 4-88 Mountain Fuel Coal Gasification Process 4-103 NASA Lewis Research Center NASA Lewis Research Center Coal-To-Gas Polygeneration Power Plant 4-103

National Coal Board Liquid Solvent Extraction Project 4-104 Low-BTU Gasification Project 4-104 National Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-100 Natural Gas Pipeline Co. of America Great Plains Gasification Project 4-93 Nokota Company Dunn Nokota Methanol Project 4-87 North Dakota Synthetic Fuels Group North Dakota Synthetic Fuels Project 4-106

Northern Indiana Public Service Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-100

Northern Natural Gas Company Minnegasco Peat Gasification Project 4-102 Northern States Power Co. North Dakota Synthetic Fuels Project 4-106 Northwest Pipeline Corporation Nices Project 4-105

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-77 Company or Organization Project Name Northwestern Mutual Life Insurance Co. Hampshire Gasoline Project ...... 4-95 Northwestern Public Service North Dakota Synthetic Fuels Project ...... 4-106 Northwestern Wisconsin Electric Co. North Dakota Synthetic Fuels Project ...... 4-106 Occidental Research Corporation Flash Pyrolysis Coal Conversion ...... 4-91 Ohio Edison Company KILnGAS Project ...... 4-98 Ottertail Power Company North Dakota Synthetic Fuels Project ...... 4-106 Pacific Gas and Electric Co. San Ardo Cogeneration Project ...... 4-107 Pacific Lighting Corporation Great Plains Gasification Project ...... 4-93 Pacific Power and Light Underground Coal Gasification, Tone Project ...... 4-116 Pacific Synthetic Fuel Company Great Plains Gasification Project ...... 4-93 Panhandle Eastern Pipe Line Co. COGAS Process Development ...... 4-86 Wyoming Coal Conversion Project ...... 4-112 Peabody Coal Company North Alabama Coal Gasification Consortium Project. . . 4-105 Peat Methanol Associates Peat Methanol Associates Project ...... 4-106 Peoples Natural Gas Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Philadelphia Gas Works Philadelphia Gas Works Synthesis Gas Plant ...... 4-106 Phillips Petroleum Corporation Exxon Donor Solvent Process Development ...... 4-89 Phillips Coal Gasification Project ...... 4-106 Pickands Mather & Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Placer Amex Inc. Beluga Methanol Project ...... 4-81 Potomac Edison Company KILnGAS Project ...... 4-98 PPG Industries Medium BTU Synthesis Gas Study ...... 4-101 Public Service of Indiana KILnGAS Project ...... 4-98 Public Service of Oklahoma Chemically Active Fluid Bed Project ...... 4-83 l{ILnGAS Project ...... 4-98 Raymond International North Alabama Coal Gasification Consortium Project. . . 4-105 Republic of Texas Coal Company Underground Coal Gasification - Mitchell Energy ..... 4-113 Reserve Mining Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Riley Stoker Corporation Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Rockwell International Cities Service/Rockwell Process Development ...... 4-85 Molten Salt Process Development ...... 4-103 Rocky Mountain Energy Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Underground Coal Gasification - Hanna Project ..... 4-114 Ruhrkohle AG Exxon Donor Solvent Process Development ...... 4-89 H-Coal Pilot Plant ...... 4-96 Sandia Laboratories Underground Coal Gasification-Washington State ..... 4-117 Santa Fe International North Alabama Coal Gasification Consortium ...... 4-105

4-78 SYNTHETIC FUELS REPORT, DECEMBER 1982 Company or Organization Project Name Sasol Limited Sasol Two and Sasol Three ...... 4-107 Shell Oil Company Shell Coal Gasification Process ...... 4-107

Solid Energy Systems Corporation SESCO Project ...... 4-107 Southern California Edison Cool Water Coal Gasification Process ...... 4-86 Southwestern Electric Power Chemically Active Fluid Bed Project ...... 4-83

Standard Oil of Indiana H-Coal Pilot Plant ...... 4-96 Standard Oil Company of Ohio Beacon Process ...... 4-81 Stearns-Roger Incorporated BI-Gas Project ...... 4-81 Stone & Webster Engineering Group Gulf States Utilities Project ...... 4-95 Central Maine Power Co.'s Sears Island Project ..... 4-83 Mining and Industrial Fuel Gas Group Gasifier ...... 4-102

Sunderland, Jack B. Peat Methanol Associates Project ...... 4-106

Tenneco, Inc. Great Plains Gasification Project ...... 4-93 SNG from Coal ...... 4-108 Tenneco SNG Inc. Great Plains Gasification Project ...... 4-93

Tennessee Eastman Co. Chemicals From Coal ...... 4-84 Tennessee Gas Pipeline Company COGAS Process Development ...... 4-86 Great Plains Coal Gasification Project ...... 4-93 Texaco Inc. Central Maine Power Co.'s Sears Island Project ..... 4-83 Cool Water Coal Gasification Project ...... 4-86 Lake DeSmet SNG From Coal Project ...... 4-98 - Medium BTU Gasification Project ...... 4-101 San Ardo Cogeneration Project ...... 4-107 Texaco Coal Gasification Process Development ..... 4-109

Texas A&M University Underground Coal Gasification of Texas Lignite ..... 4-116 Texas Eastern Corporation New Mexico Lurgi Coal to Gas/Methanol Plant ...... 4-104 Tri-State Project ...... 4-110 Texas Energy and Natural Resources Lignite Briquette Gasification Plant ...... 4-99 Advisory Council Underground Coal Gasification-University of Texas .... 4-113

Texas Gas Transmission Corp. Ken-Tex Project ...... 4-97 Tri-State Project ...... 4-110 Texas Mining and Mineral Resources Research Institute Underground (Coal Gasification - University of Texas ....4-113 Timberline Fuels, Inc. Ott Hydrogenation Process Project ...... 4-106 TOSCO Corporation TOSCOAL Process Development ...... 4-110 Transco Companies, Inc. Great Plains Gasification Project ...... 4-93 Transco Coal Gas Plant ...... 4-110 Transco Coal Gas Company Great Plains Gasification Project ...... 4-93 Transcontinental Pipe Line Corporation Great Plains Coal Gasification Project ...... 4-93

Transwestern Coal Gasification Co. Lake DeSmet SING From Coal Project ...... 4-98

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-79 Company or Organization Project Name TRW, Inc. Beacon Process ...... 4-81 TRW Coal Gasification Process ...... 4-110 TVA North Alabama Coal Gasification Consortium Project. . . 4-105 TVA Ammonia-From-Coal Project ...... 4-111 Union Carbide Corporation Low/Medium BTU Gas For Multi-Company Steel Complex . 4-100 Union Carbide Coal Conversion Project ...... 4-112 Union Electric Company KILnGAS Project ...... 4-98 United Coal Company Whitethorne Coal Gasification Project ...... 4-112 United Energy Resources Inc. Medium BTU Synthesis Gas Study ...... 4-101 United Engineers & Constructors, Inc. Philadelphia Gas Works Synthesis Gas Plant ...... 4-106 University of Minnesota University of Minnesota Low-ETU Gasifier for Commercial Use 4-112 University of North Dakota Gasification Environmental Studies ...... 4-93 Low-Rank Coal Liquefaction Research ...... 4-99

University of Texas Underground Coal Gasification ...... 4-113 USBM - Twin Cities Metallurgical Research Center Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 U.S. Steel Corporation Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Utah International New Mexico Lurgi Coal to Gas/Methanol Plant ...... 4-104 Virginia Fuel Conversion Authority Whitethorne Coal Gasification Project ...... 4-112 Washington Irrigation and Development Co. Underground Coal Gasification, Tono Project ...... 4-116 Washington, State of Underground Coal Gasification, Tono Project ...... 4-116 Western Energy Company Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 West Penn Power Company KILnGAS Project ...... 4-98 West Texas Utilities Company Chemically Active Fluid Bed Project ...... 4-83 Westinghouse Electric Fiat/Ansaldo Project ...... 4-90 Gulf States Utilities Project ...... 495 Keystone Project ...... 4-9? New England Energy Park...... 4-104 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-112 Weyerhaeuser Mining and Industrial Fuel Gas Group Gasifier ...... 4-102 Wheelabrator-Frye Solvent Refined Coal Demonstration Plant - SRC-I .... 4-108 Wold-Jenkins Underground Coal Gasification, Thunderbird II Project 4-117 World Energy, Inc. Underground Coal Gasification ...... 4-113 WyCoal Gas Inc. Wyoming Coal Conversion Project ...... 4-112

4-80 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since June 1982) SYNTHETIC FUELS FROM COAL COAL CONVERSION PROJECTS A.C. VALLEY CORPORATION PROJECT - A.C. Valley Corporation The A.C. Valley Corporation, a privately funded development company, proposes to construct and operate a 10,000 barrel per day coal liquefaction project in the Allegheny-Clarion Valley Region of Pennsylvania. GIlT gasification, ICI methanol synthesis, and Mobil methanol-to-gasoline processes will convert 4,950 tons per day of high sulfur coal to gasoline. A.C. Valley submitted an application for a federal loan guarantee to the SFC, but the project failed to pass the maturity test. The company submitted another loan guarantee application under the SFC's second solicitation ending June 1, 1982. The project again failed to pass the maturity test. Project Cost: $800 million (1981) ALABAMA SYNTHETIC FUELS PROJECT - AMTAR, Inc., and Applied Energetics, Inc. The site of the proposed project is in Greene County, Alabama, on the Tombigbee River near the small town of Boligee. The project proposes the use of indirect liquefaction technology to produce gasoline (GIlT gasification, Id conversion to methanol, and Mobil-M conversion to gasoline). Initial production from one module would be 8,230 barrels per day of lead free gasoline, 1,700 barrels per day of liquefied petroleum gas, and 100 tons per day of sulfur. Pour additional modules are planned for a later date. Plant start-up is scheduled for early 1987, with full production expected in late 1989. A loan guarantee and a price guarantee were requested from the Sit under the second solicitation that ended June 1, 1982. However, the project failed to pass the SFC's maturity tests. Engineering will be performed by Burns and Roe-Humphreys & Glasgow Synthetic Fuels, Inc. AMAX COAL GASIFICATION PLANT - AMAX, Inc. AMAX, Inc. conducted a feasibility study for a plant to be built in Duluth, Minnesota to produce methanol at the former U.S. Steel Corporation Morgan Industrial Park site. Results of the study indicated that, in 1984-5 when the 210 million gallon per year facility would come on stream, the methanol market could not absorb such additional output. Consequently, AMAX announced that it would not renew its option on the U.S. Steel site. AMAX will continue studying application of methanol, for both chemical and fuel uses. In 1975 AMAX, United Aircraft and Florida Power and Light successfully tested methanol as fuel in an industrial gas turbine used for power generation. The test demonstrated marked reduction in nitrogen oxide emissions and in maintenance costs through use of methanol. Currently AMAX is testing a methanol/diesel engine in its own mining operation. Project Cost: Not available BEACON PROCESS - TRW, Inc. and Standard Oil Company of Ohio The Beacon Process, invented by TRW, is a joint development project with Standard Oil Company of Ohio to convert low Btu gas from air blown coal gasifiers or underground coal gasification to SNG and electricity. A modeling study of fixed and fluid-bed reactors for the process has been completed. A cooperative agreement provides for DOE cost sharing during a thirty month development period. Preliminary design and planning for a two-reactor integrated test facility is in progress. Project Cost: Over $10 million to date. BELUGA METHANOL PROJECT - Cook Inlet Region, Inc. and Placer Amex Inc. The above firms have conducted a feasibility study for a 1,500 TPD methanol plant using Alaskan subbituminous coal. Winkler 4 atm. gasifiers will be used for gasification. ICI process will be used for methanol synthesis. The project sponsors applied for a loan guarantee and a price guarantee under the SFC's second solicitation ending June 1, 1982. The project pathed SPC project maturity tests but failed to pass its project strength tests. A state industrial site has been applied for. Plant site is on state land and private land owned by Cook Inlet Region, Inc., approximately 60 miles west of Anchorage. Construction has not been scheduled. Cost of Study: Over $4 million Cost of Project: $2.3 billion (1981) BI-GAS PROJECT - DOE, and Stearns-Roger, Inc. A 120 TPD pilot plant, based on the Bituminous Coal Research, Inc. entrained bed, slagging-ash, coal gasification process is located at Homer City, Pennsylvania. It was designed, built, and has been operated by Stearns-Roger Incorporated. Initially, program management functions were provided by the Phillips Petroleum Company for BCR,.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-81 STATUS OF SYNFUEL.S (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

the prime contractor. Both functions, in addition to operation, were assigned to Stearns-Roger in November of 1979. Char, steam, and oxygen react at high temperature in the first stage of the gasifier. The hot gases devolatilize coal in the second stage to produce the required char and a product gas of high methane content. The pilot plant, which includes shift and methanation units, will produce 3.4 MM SCFD of 514G. Efforts are currently directed toward collection of operating data and the improvement of operability on both subbituminous and bituminous coals. Slag tapping problems have been solved for Rosebud coal. Progress has been made in solving important problems in control and monitoring of coal and char feeds and in measurement of Stage I temperatures. The feeding of supplemental fuel gas into Stage I as a safety precaution has been discontinued. Attainment of this, safely, was a major goal of the FY 1981 program. The plant has had continuous runs of 170, 120 and 100 hours on Rosebud coal with all systems operating satisfactorily and reliably. Major thrust of the remaining FY 1981 program was to achieve further safe operating experience on an Eastern bituminous coal. The Program includes development of a mathematical model of the BI-GAS process, as well as establishing a data base for the process. Funding for the program through March 1982 was received.

Pilot Plant cost: $79 million. Testing Costs: Not Available. BRECKINRIDGE PROJECT - Bechtel Petroleum, Inc. Under the Synthetic Fuels Corporation's first solicitation, the project sponsor (Ashland Synthetic Fuels and Bechtel) requested loan guarantees for a facility to utilize the H-Coal direct liquefaction process. The project met the SFC's project strength criteria and progressed to Phase II evaluation. As originally envisioned, the plant was to convert high sulfur Illinois Basin coal into a slate of products including 46,500 bpd of liquid distillate, propane and butane, and 20 million scfd of synthetic natural gas (total production equivalent to 47,500 bpd). The original estimate for the plant investment was $2.7 billion (1981 dollars). However, when adjusted for inflation and interest during construction, the as-spent cost was projected to be $5.5 billion. Therefore, project sponsors decided to reduce the initial plant throughput by one-half (9000 TPD). One factor in the decision was the limit of $3 billion that the SFC can award to one project. In addition to the original loan guarantee, the sponsors also requested a price guarantee from the SFC. On

On November 22, 1982, Ashland announced they were withdrawing from the project due to many factors including uncertainty about future crude oil prices, the large investment involved, possible cost overruns, and recent tax-law changes that reduced potential tax benefits. Project Cost: $2.7 billion (1981 dollars) for 18,000 tpd facility;

(NOTE: in previous issues of the Synthetic Fuels Report this project has been summarized as part of the H-coal description.) BURNHAM COAL GASIFICATION PROJECT - El Paso Natural Gas Co. Proposed commercial Lurgi plant for pipeline gas in Four Corners area has been placed on indefinite hold. Estimated Cost: Unavailable CATERPILLAR TRACTOR LOW BTU GAS FROM COAL PROJECT - Caterpillar Tractor Co. In April 1977, Caterpillar announced plans to construct two, two-stage coal gasifiers at its York, Pennsylvania plant to fuel heat treating furnaces. Gas with a heating value equivalent to about 2.2 million SCFD of natural gas could be produced. The plant is a two-stage, low-pressure system complete with gas cleanup. Plant construction began in September 1977. Construction of a gasifier for the East Peoria, Illinois, plant has been deferred indefinitely although the York installation is successful. Plant was completed June 1979, with start-up for debugging in September 1979. Due to an eleven-week strike in the last quarter of 1979 and some minor equipment changes that had to be made, debugging was not resumed until May 1980. Tests have been run on existing radiant tubes using producer gas with no adverse effect. The system operated from February 1981, until the July vacation shut-down. After vacation, the system was started up and has been making low Btu fuel gas (producer gas) on a continuous basis and is using it - 24 hours a day, seven days a week - in the heat treating furnaces. Coal gasifier has been shut

4-82 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUEL.S (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

down since September due to reduced production schedules. Plans now are for starting up again sometime mid-year of 1983. Project Cost: *5-10 million. CELANESE COSTAL BEND PROJECT - Celanese Corporation Celanese Corporation contracted with Stearns Roger, Inc., to conduct a feasibility study for a gasification project to provide chemical feedstocks as well as fuel at the Celanese plant in Bishop, Texas. Lignite or subbituminous coal would be shipped to the facility. The engineering feasibility study by Stearns-Roger, Inc. is complete. Celanese has indefinitely postponed further work on the project. Project Cost: Over $10 million for both East Texas and the Costal Bend project studies CELANESE EAST TEXAS PROJECT - Celanese Corporation Celanese contracted with Rust Engineering to prepare a feasibility study for a possible mine mouth coal gasification facility to produce chemical feedstocks from Texas lignite. The engineering feasibility study by Rust Engineering is complete. Celanese has indefinitely postponed further work on the project. Project Cost: Over $10 million for both East Texas and the Costal Bend project studies. CENTRAL ARKANSAS ENERGY PROJECT - Arkansas Power & Light Company Arkansas Power & Light Company is sponsoring a combined cycle cogeneration process using the Texaco coal gasification process. Loan guarantees were requested from the SFC, but the project was not selected by the SFC. The project would be located at the White Bluff steam electric station, five miles from Redfield, Arkansas. The project will be designed to produce 120 billion Btu's per day of medium Btu gas. When pipelined to industrial steam user(s) located remote from the gasifier and burned in one or more combined cycle cogeneration plants, approximately 430 megawatts of electrical energy and 1.8 million pounds of process steam will be produced from the gas. Project sponsors are also considering producing ammonia or methanol from the coal-derived gas. Status:

Project Cost: Undetermined

CENTRAL MAINE POWER CO.'s SEARS ISLAND PROJECT - Central Maine Power Co., Texaco Inc., General Electric Co., and Stone & Webster Engineering Corp. A feasibility study for a commercial-scale coal gasification combined cycle power plant to be located on Sears Island, Maine was initiated in October 1980, with DOE funding. The study's objectives include: (1) develop process design including equipment and process selection; (2) determine capital costs and construction timetable; (3) evaluate operating and maintenance costs, reliability, and operating characteristics; (4) compare the cost of energy from the IGCC plant to a coal-fired plant and identify benefits and risks; and (5) prepare plans for final design and financial arrangements. Texaco provides design of coal grinding and gasification using the Texaco Coal Gasification Process. GE provides the design of the combined cycle part of the plant, including turbines, electrical and steam systems. SWEC provides design of coal receiving, handling and storage, plant layout, oxygen plant and balance of plant. Preliminary engineering and the heat and material balances are virtually complete. The preliminary plant capacity is 520 MW net at 5,120 tons/day coal. The heat rate is currently calculated at approximately 9,500 Btu/ICwh. The equipment includes 4 gasifiers plus 1 spare, 2 sulfur removal trains, 4 gas turbines and heat recovery steam generators, and I steam turbine. The design coal is Kentucky No. 9 (11,800 Btu/lb., 3.9 percent sulfur, 15 percent ash) and performance will also be calculated based on Illinois No. 6 coal.

Project Cost: $3,560,773 (DOE Contract). CHEMICALLY ACTIVE FLUID BED PROJECT - Central and Southwest Corporation (Central Power and Light Co., Public Service Co. of Oklahoma, Southwestern Electric Power Co., and West Texas Utilities Co.), Foster Wheeler Energy Corporation and the Environmental Protection Agency CP&L has constructed a 210 MM Btu/hr coal gasification pilot plant to demonstrate the Chemically Active Fluid Bed (CAFB) gasification process developed by Esso Research Centre Abingdon (ERCA), United Kingdom. The design and engineering, completed by Foster Wheeler Energy Corporation was funded by the EPA. EPA is also providing

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-83 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

fuels, feedstocks and the environmental assessment. The 1600°F circulating limestone in the process removes sulfur (as CaS) from the fuel producing a relatively sulfur-free low Bus gas. This fuel gas is fired directly in an existing 20 MW natural gas-fired boiler which has been retrofitted to accept the low-Btu fuel. The plant is located at CP&L's La Palma Station, San Benito, TX. The three other utilities share construction and operating expenses with CP&L. The plant is designed to use lignite or heavy high sulfur fuel oil as primary fuel. The unit has gasified No. 6 fuel oil for 510 hours in five separate runs. The generator has produced up to 22 MWe power with the boiler firing product gas from the gasifier. No. 6 fuel oil input was approximately 17,000 lbilhr. at the 22 MWe load. During the periods of operation, the product gas from the gasifier has produced 4.4 x 10 Kw hours of electricity. Measured stack emissions have been within NSPS limits. In addition, initial trials with Texas lignite and Eastern bituminous coal have produced 110,000 kW hours of electricity. Additional operation on Eastern bituminous coals was scheduled in 1981. Project Cost: $13.5 million CHEMICALS FROM COAL - Tennessee Eastman Co. In a privately funded project, Tennessee Eastman Company, a manufacturing unit of the Eastman Chemicals Division of Eastman Kodak Company, is constructing a multi-million dollar project to produce industrial chemicals from coal. Texaco's coal gasification process will be used to produce the synthesis gas for manufacture of acetic anhydride. Methyl alcohol and methyl acetate are produced as intermediate chemicals and sulfur will be recovered. Bechtel Petroleum Inc., is in charge of the process design, engineering, procurement, and construction management. Construction began late in 1980 in Kingsport, Tennessee, with start-up planned in mid-1983. Locally mined coal will be used. Status: Daniel International unit of Fluor Corporation is the general construction contractor. The project is over 50% complete. Project Cost: Unavailable CHOKECHERRY PROJECT - Energy Transition Corporation Project sponsors are continuing their study of the feasibility of building a coal gasification plant to produce hydrogen using coal reserves in Moffat County, Colorado. Energy Transition Corporation (ETCO), as the prime contractor to W.R. Grace in 1980 and 1981, prepared an economic feasiblity report on a nominal 5000 ton of methanol per day plant using the KBW Gasification Systems, Inc. (Koppers/Babcock & Wilcox technology for gasifying coal. Included in the ETCO feasibility report is a market study for fuel grade methanol in dedicated fleets in the "local" area (Colorado, Utah and Wyoming). W.R. Grace also conducted an "environmental and regulatory" feasibility study under a DOE grant of $769,714 in 1981. The project was accepted into the Colorado Joint Review Process (JRP) in December 1980 and the JRP team of local, state and federal agency representatives, and the project sponsor, held four public meetings in 1981 to review the project. In March 1981, an application was filed with the U.S. Synthetic Fuels Corporation for a price guarantee of 75 cents/gallon (January 1981 dollars) escalated quarterly at the inflation rate plus 1/2 percent. The project sponsors transferred the Project to the SFC Second Solicitation in December 1981. Project sponsorship was transferred from Grace to ETCO in January 1982 and ETCO reapplied for price and loan guarantees under the SFC's second solicitation ending June 1, 1982. However, on June 18, 1982, the SFC announced that the project had failed to pass their project maturity test and had been dropped from further consideration under the second solicitation. The project feasibility study (Grace funded), and the environmental and regulatory feasibility study (DOE funded), have been completed. Current estimates are that an 18 to 24 month preconstruction (final design, permit applications, etc.) period will be required. ETCO is proposing a scaled-down version of the project which will produce 60 million SCF per day of hydrogen from one KBW gasifier. The hydrogen would be pipelined to oil shale upgrading facilities in either the Piceance Basin or in Eastern Utah. The plan calls for expansion to a 10 gasifier plant capable of producing 600 million SCF per day of hydrogen. (NOTE: this project has appeared in previous issues under the title "Grace Synthetic Fuel Liquefaction Plant").

Project Cost: $400 million (est.) CIRCLE WEST PROJECT - Burlington Northern Inc. Burlington Northern Inc. (BNI) has studied the feasibility of locating a proposed commercial plant for fertilizer and liquid fuels from coal on BN-owned Dreyer Brothers ranch near Circle, MeCone County, Montana. BN filed for 67,000 AFY from Fort Peck Reservoir. Koppers and Kellogg presented preliminary engineering study to the Montana Department of Natural Resources and Conservation in February 1976 for a plant to produce 2,300 TPD fertilizer grade liquid anhydrous ammonia plus 2,174 TPD fuel-grade methanol. Basin Electric Power Cooperative joined BN-Dreyer Bros. in September 1977, to evaluate the feasibility of a power plant having common coal mining facilities with BN plant. Lignite would be used in synthetic fuels or fertilizer plant or for Basin Electric plant.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-84 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

The project is now the responsibility of Meridian Land & Mineral Company, a wholly-owned subsidiary of Burlington Northern Inc. Some environmental work is currently ongoing. Main effort of ML&M is to complete a land exchange with the Department of Interior.

Project Cost: Undetermined

CITIES SERVICE/ROCKWELL PROCESS DEVELOPMENT - DOE and Rockwell International (Energy Systems Group) The CS/R (Cities Service and Rockwell) process is based on flash hydropyrolysis (FHP) of finely pulverized materials (e.g., coal, peat, or oil shale) in single-stage, short-residence-time, entrained-flow reactors. The slate of synthetic fuels produced from coals depends on the severity of the FHP reactor operating conditions and the reactor residence time. Low seventies and very short times favor yielding an essentially liquid syncrude, along with modest yields of gases (e.g., CO, CH4, C2's, C3's, etc.). High seventies and long residence times favor production of all gaseous products, predominantly CH4. At intermediate seventies and times, the heavy syncrude components are hydrocracked to light, predominantly aromatic liquids. Under certain conditions, there is a substantial yield of high- purity benzene as the sole by-product, and it can be upgraded readily to chemical-grade quality. Rockwell has studied coal hydroliquefaction and hydrogasificationin 1/4- and 1-tonTh engineering-scale reactor and process development systems under several DOE contracts. The liquefaction work, performed in four discrete phases beginning in 1975, was brought to a close in 1982 with the publication of two comprehensive final reports. These summary reports include a preliminary design study for a commercial CS/R hydropyrolysis coal liquefaction plant performed by Scientific Design Co., Inc., and significant work by Cities Service in characterizing FHP coal liquids. For high-Btu coal gasification, DOE awarded Rockwell an $18 million contract in 1978 to design, construct, and operate an 18-ton/day integrated hydrogasification PDU at Rockwell's Santa Susana Field Laboratory near Canoga Park, California. Construction of the IPDU w* interrupted in FY 1982 when the facility was about 60 percent completed. Rockwell has restructured the project into a proposed joint DOE/private industry program, with Rockwell heading a consortium of private sector participants. Current discussions among Rockwell, DOE, and the industry participants are directed toward finalizng the work scope and participation agreements. It is anticipated that the project will be resumed in the second quarter of FY 1983 and that long-duration tests (up to 30 days) will be achieved during FY 1985. In May 1981, the C-E Lummus Company, under subcontract to Rockwell, completed the preliminary conceptual design of a 250-billion Btu/day, high-Btu coal gasification plant based upon the CS/R Hydrogasification Process. In addition to synthetic natural gas, the plant was designed to produce 5,310 bbl/day of chemical-grade benzene. Lummus estimated the capital and operating costs for the commercial plant, and the resulting 20-year average cost of gas was $3.68 per million Btu in mid-1979 dollars (C.F. Braun gas cost guidelines, utility financing). Subsequent process modifications have reduced the COG to $3.38 per million Btu. In October 1982, DOE awarded Rockwell a $0.6 million contract for experimental evaluation of hydroretorting of eastern oil shale in a CS/R hydropyrolysis reactor. Reactor tests are scheduled to be made before mid-FY 1983, with variations among reactor temperature, pressure, and residence time. Testing will be followed by a preliminary process study to determine whether this approach to recovery of shale oils may have significant advantages in either liquid yields or processing costs. Project Cost: $3.2 million (PDU Studies) $18 million pilot plant CLARK SYNTHESIS GAS PROJECT - Clark Oil and Refining Corp. Clark requested $4 million from the DOE for a feasibility study for an indirect liquefaction plant. A Koppers- Totzek gasifier and the ICI process to convert the synthesis gas into methanol and the Mobil M process to convert the methanol to gasoline was proposed for the project to be located new New Athens, Ill. The feasibility study was completed the first quarter of 1982. The study concludes: 1) the proposed processes are technically feasible; 2) however, the project cannot be justified financially; 3) loan guarantees from the SFC would not be sufficient to attract the needed equity portion of the financing; and 4) the amount of funds required for price guarantees would exceed the SFC's maximum funding authority. Cost of Study: $4 million Cost of Plant: $1.3 billion (1981)

New or Revised Projects

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-85 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

COGAS PROCESS DEVELOPMENT - COGAS Development Co. (CDC) (Joint venture of Consolidated Gas Supply Corp., a subsidiary of Consolidated Natural Gas Company, FMC Corp., Panhandle Eastern Pipe Line Company, a subsidiary of Panhandle Eastern Corp., and Tennessee Gas Pipeline Company, a division of Tenneco, Inc.) The COGAS Process produces pipeline gas, essentially sulfur - free No. 2 and No. 6 fuel oils and gasoline feedstock grade naphtha from coal. Development of design data from cold models and a pilot plant with a feed capacity equivalent to 100 tons of coal per day is completed. Under the DOE/IGCC Synthetic Pipeline Gas (SPG) from Coal Demonstration Plant Program, process development, process design, and detailed engineering are complete. That program was terminated at the convenience of the Government due to the lack of funding. CDC offers a COCHAR Process and a DCC Process. The COCHAR Process converts coal to liquid fuels and char. The DCG Process converts coal to pipeline gas and/or medium Btu gas. Davy McKee Corporation has the exclusive rights to license the CDC proprietary process technology and related know-how. Project Cost: CDC has spent about $20 million developing process COMBINED CYCLE COAL GASIFLCATION ENERGY CENTERS - Consumer Energy Corporation Consumer Energy Corporation is a non-profit organization headquartered in Cameron, Missouri. Two combined cycle coal gasification facilities each producing electricity, fuel gas, methanol, and sulfur are being considered for rural areas of northern and central Missouri. The proposed sites at Eager, Missouri and Yates, Missouri are under purchase option. Texaco gasification process favored, but final hardware selection will be made in mid-1981. Capacities of each facility are projected to be 42 MMSCFD low-medium Btu industrial gas, 700 ST/fl of methanol, 321 MW power generation and 220 ST/fl elemental sulfur. Feedstock is high sulfur Missouri coal. Status: The Economic and Technical Feasibility Report, including preliminary environmental and socio-economic impact study, has been completed. Preliminary engineering and design phase to start in early 1981. Phase I includes 7 work tasks and will last one year. Construction is scheduled for 1983, and start-up date for both facilities is projected as late 1985. The project team consists of the following: Consumer Energy Corporation; Associated Electric Cooperative Inc.; Lutz, Daily & Brain, Consulting Engineers; Foster Wheeler Energy Corporation; Midwest Research Institute; Arthur Andersen & Co.; Stern Brothers & Co.; Lazard-Freres & Co.; Mudge, Rose, Guthrie & Alexander; and Stockard, Andereck, Hauck, Sharp & Evans. Project Cost: 416.4 million (each plant) CONVENT, LA., PROJECT - (see Medium Btu Gasification Project.) COOL WATER COAL GASIFICATION PROJECT - Participants: Southern California Edison, Texaco Inc., Electric Power Research Institute, Bechtel Corporation, General Electric Company, Japan Cool Water Program (JCWP) Partnership; Contributor: Empire State Electric Energy Research Corporation (ESEERCO) Sponsors are building a 1,000 tons coal per day demonstration plant using oxygen-blown Texaco Coal Gasification Process. The gasification system will be integrated with a new combined cycle unit to produce approximately 100 megawatts of net power. The California Energy Commission approved the state environmental permit in December 1979. Final engineering design began in February 1980, and construction commenced in December 1981. Start-up and operation of the integrated facility is planned for mid-1984. The design coal is to be Western (Utah), but a variety of coals, both Eastern and Western, are to be tested. Texaco and SCE, who are contributing equity capital of $45 million and $25 million respectively to the effort, signed the joint participation agreement on July 31, 1979. The Electric Power Research Institute (EPRI) executed an agreement to participate in the Project in February 1980 and their current committment is $105 million. Bechtel Power Corporation has been selected as the prime engineering and construction contractor and also executed a participation agreement in September 1980. They are contributing $30 million to the project. General Electric signed a participation agreement in September 1980. In addition to contributing $30 million to the Project, GE will be the supplier for the combined cycle equipment. The JCWP Partnership, comprised of the Tokyo Electric Power Company, Central Research Institute of the Electric Power Industry, Toshiba CGP Corporation and IHI Coal Gasification Project Corp. signed a participation agreement on Februrary 24 1982 to commit $30 million to the Project. ESEERCO executed a contributor agreement on January 20, 1982, committing $5 million to the Project. A $24 million Project loan guaranteed by SCE, Texaco and EPRI together with a $6 million in-kind contribution by SCE of facilities at SCE's existing generating station completes the $300 million funding. A supply agreement was executed with Airco, Inc. on February 24, 1982 for Airco to provide "over-the-fence" oxygen and nitrogen from a new on-site facility, thus reducing capital requirements of the Project. The Project applied to the U.S. Synthetic Fuels Corp. for financial assistance in the form of a price guarantee up to a maximum of $63 million. This was designed to reduce the risks of the existing Participants during the seven year operating period. The Project was not accepted by the SFC because it did not pass the "credit elsewhere" test (the SFC believed sufficient private funding was available without government assistance). However, the sponsors reapplied for a price support under the SFC's second solicitation which ended June 1, 1982.

4-86 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNPIJELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

On September 17, 1982, the SFC announced that the project had passed the six-point project strength test and had been advanced into Phase II negotiations for financial assistance. Other organizations are being actively sought to join in the effort to reduce the funding by EPRI and the Project loan. Status: All key permits for the Project have been obtained, final engineering design and construction by Bechtel are approximately 85% and 20% complete, respectively on December 1, 1982. A $15 million contract has been awarded to Combustion Engineering to fabricate the gasificr, radiant cooler, convection cooler, and two steam drums. Project Cost: $300 million CROW INDIAN COAL GASIFICATION PROJECT - Crow Indian Tribe, DOE The Crow Indians were awarded $2.7 million by the DOE to study the feasibility of building a major commercial coal gasification facility on their reservation in Montana. The conceptual plan developed by the Crow Indians would use Lurgi technology to convert reservation coal reserves into synthetic natural gas at the rate of 125 million standard cubic feet per day. Two mining areas on the reservation containing more than a billion tons of surface-mineable coal are potential supply sources for the project. The feasibility study is being conducted by a Crow-assembled team that includes Council of Energy Resource Tribes (CERT), Fluor Engineers and Constructors, Inc. as builder, and Pacific Coal Gasification Company (a subsidiary of Pacific Lighting Corporation) as operator. Westmoreland Resources, Inc., and Shell Mining Ventures, Inc., both of whom hold coal leases on the reservation, are assisting in the evaluation of alternative mine sites. The coal gasification facility may require approximately 100 MW of power for its own internal use. Other factors have led the Tribe to conduct an independent feasibility study to evaluate a coal-fired electric power generating station on the Crow Reservation, consisting of two 500 MW units. The proposed station would utilize coal and water supplies located on the reservation. Cost: $2.7 million (study) $3 to $4 billion Project DOW COAL LIQUEFACTION PROCESS DEVELOPMENT - Dow Chemical Company Dow has developed a coal liquefaction process in a 200 pound-per-day laboratory pilot plant. The process uses an expendable molybdenum based catalyst. A solution of a water soluble molybdenum compound is emulsified in recycle solvent and the resultant emulsion is dispersed in the slurry of pulverized coal and recycle solvent prior to liquefaction. Hydroclones are used to achieve a partial solids removal from the reactor product and to provide a partial recycle of catalyst to the reactor. Hydroclone underfiow is extracted with paraffinic solvent in a countercurrent liquid-liquid extractor to produce solids-free, low sulfur deasphalted oil and a high solids residue which is suitable as a gasifier feedstock. The recycle solvent for the process comprises 3 parts of hydroclone overhead to I part of deasphalted oil. Dow has constructed a 200 pound per day mini-plant. The skid-mounted mini-plant will offer support services for a planned 6 to 10 ton per day pilot plant. Dow is hoping to integrate the pilot plant with an existing hydrocarbon plant in order to use existing support facilities, and has explored this possibility with a number of oil companies. Project Cost: Undetermined DUNN NOKOTA METHANOL PROJECT - The Nokota Company The Dunn-Nokota Methanol Project is a mine-mouth, coal-to-methanol complex that would produce 86,940 barrels per stream day (BPSD) of methanol from 43,150 net short tons per stream day (ST/SD) of run-of-mine (ROM) lignite coal. As an alternative, Nokota is considering co-production of substitute natural gas (SNG) and methanol. The proposed plant and mine site area is located approximately five miles southeast of Dunn Center, North Dakota. Dunn-Nokota is one of several projects to which the Department of Energy made an award in late 1980 under its Alternative Fuels Program. Nokota is conducting a number of technical, environmental, marketing, and financial reviews of the Project with the assistance of this grant. Firms participating in the DOE financed study include Dames & Moore, project manager and environmental consultant; Fluor Engineers and Constructors, Inc., for design engineering; Purvin & Gertz, Inc., for marketing and transportation planning; Williams Brothers Engineering Company, for pipeline transportation design and routing; John T. Boyd Company, for mine planning; Dillon, Read & Co. Inc., financial and economic analyses; and legal counsel in Bismarck, North Dakota, Atkinson & Dwyer, and in Washington, D.C., Hamel, Park, McCabe & Saunders. Nokota is concurrently applying or preparing to apply for the principal construction permits and other permits required for the Project.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-87 STATUS OF SYNPUELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

Nokota's schedule for the Project calls for phased construction and operation, with initial construction beginning in 1985 on a facility producing at one-half the full capacity. Commercial operation of this phase of the Project is scheduled for 1989. Construction of the remainder of the facility is scheduled to begin in 1988 and to be in commercial operation in 1991. The major processes planned for converting coal to methanol are coal gasification using the Lurgi dry bottom gasification process, gas cooling, gas purification using the nonselective Rectisol process, methanol synthesis, methanol purification, CO2 removal, and methane reforming. Methanol synthesis will require four parallel trains, each designed to produce approximately 22,000 BPSD or 3,100 ST/SD of methanol. Nokota has completed essentially all drilling required to define the lignite resource of the mine site and has allocated sufficient reserves to meet the coal requirements of the plant over its expected life. At full capacity, the mining operation will use the coal under approximately 390 acres of land (14.7 million tons) each year. To achieve this delivery schedule, Nokota plans to operate three large walking draglines in separate mine areas. The site of the Dunn-Nokota Methanol Project is the same as that selected by the Natural Gas Pipeline Company of America (NGPL) in the mid-1970's for its proposed 275-MMSCFD coal gasification facility. Numerous studies by state universities, federal and state agencies, and private firms involving resource assessment and environmental evaluation have been conducted on this site. Since mid-1979, Dames & Moore has performed extensive environmental studies, has updated previous baseline data, where appropriate, and is assessing impacts of the Project. Essentially all of the baseline data required to evaluate the environmental effects of construction and operation of the Project has been compiled. Nokota's application for a PSD permit to construct with respect to this Project was deemed complete by the North Dakota State Health Department, effective June 30, 1980, and is currently under review. As required under the North Dakota Energy Conversion and Transmission Facility Siting Act, Nokota filed its letter of intent to construct an energy conversion facility with the North Dakota Public Service Commission on May 1, 1981, and its ten-year plan on July 1, 1981. During July 1981, the Bureau of Reclamation was designated as lead agency within the Department of Interior for the purpose of preparing the Environmental Impact Statement (EIS) on the Dunn-Nokota Methanol Project. In November 1981, Nokota filed a water permit application with the North Dakota State Water Commission for 16,800 acre-feet of water annually for water make-up requirements of the facility.

Project Cost: Estimated at $2.8 billion (in 1981 dollars) for the coal-to-methanol plant ($2.3 billion in the alternative where SNG is co-produced) and $310 million (1981 dollars) for the mine. EMERY COAL CONVERSION PROJECT - Emery Synfuels Associates (Mountain Fuel Resources, Inc. and Mono Power Company) Emery Synfuels Associates proposes to build a gasification plant at a site near the town of Emery, Utah. Preliminary approval of the site has been secured from the Utah Interagency Task Force on Power Plant Siting. Mountain Fuel Resources, Inc., has signed an option agreement to acquire water rights from the Muddy Creek Irrigation Co. Initial plant designs are being prepared based on the Lurgi process. The projected plant would produce commercial quantities of substitute natural gas and methanol. Mountain Fuel Resources, Inc., and Mono Power Company, a subsidiary of Southern California Edison Company, are conducting a feasibility study of the technical, economic, regulatory, and business aspects of the project. A decision to proceed with the project has been postponed until markets for large amounts of methanol become more established. Completion of the study is scheduled during 1982. Project Cost: Undetermined ENRECON COAL GASIFIER - Enrecon, Inc. Enrecon was developing a fluidized bed, medium-Btu coal gasification process in Golden, Colorado. The 60 TPD Phase I pilot plant began operation in December 1979, and was operated up to August, 1980. Kinetic and equilibrium models predict system performance for different feed materials for SNG, hydrogen and synthesis gas production. Enreeon predicts over 75 percent cold gas efficiency at over 400 Btu/SCF using either western sub-bituminous or eastern bituminous coals. C.F. Braun & Co., a subsidiary of Santa Fe International, has completed an evaluation of how the ENRECON process compares technologically and economically with other known processes for SNO production. Costs range from $4.19 per million Btu to $4.50 using a Pittsburgh #8 coal at $27/ton, 1979 dollars, utility financing. Enrecon was seeking investors for the $25 million test program to complete its pilot plant studies of coal gasification. However, the fund raising effort proved unsuccessful and was terminated in August, 1982. Enrecon has

4-8 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUEIJS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

been moved to Pittsburgh, Pa. where the technology will be held pending some future interest. Enrecon holds a minority interest in Encotec. ForEnergy Conversion Technology, Ltd. (Encotec) has been formed to develop an innovative new fluidized bed process the thermal and catalytic production of oil and gas from tar sands, oil shale and coal.

Estimated Cost: $300,000 for P011 EXXON CATALYTIC GASIFICATION PROCESS DEVELOPMENT - Exxon Exxon Research and Engineering Company has completed a $16.8 million contract awarded by DOE in September 1978, for a Catalytic Coal Gasification (CCC) process development program continuing through Much 1981. The Gas Research Institute (CR!) also participated in the project funding. The development program included operation of a one TPD Process Development Unit (PDU) which was constructed with Exxon funding, as well as bench-scale research and engineering support. The gasifier was started up in 1979 on Illinois No. 6 coal. The process uses a potassium catalyst (K2CO3) which promotes both the steam-carbon gasification and methanation reactions when added to the feed coal. The production of methane is thermodynamically favored at low temperatures. Due to the promotion of the K2CO3 catalyst, the temperature is low enough (1300° F) to yield a high CH4 concentration. Since the amount of CO and H2 recycled back to the gasifier balances the amount of CO and H2 leaving the gasifier, the net products of gasification are mainly CI-14 and CO2, with lesser amounts of H2 5 and NH3. Because methane is produced directly in the gasifier, there is no need for water gas shift and methanation reactors. An oxygen plant is not required for carbon combustion since the heat required for gasification is essentially provided by the heat from the exothermic water gas shift and methanation reactions. One of Exxon Corporation's Dutch affiliates, Esso Steenkool Technology, plans to construct and operate a 100 ton-per-day pilot plant at Rotterdam, Europort, Holland. Operation of the unit is expected to begin in 1986. The new plant is part of an 8-year development effort which is expected to cost more than $500 million. Project Cost: $5004- (Exxon Funded)

EXXON DONOR SOLVENT PROCESS DEVELOPMENT - DOE, Exxon Company, USA, Electric Power Research Institute, Japan Coal Liquefaction Development Co., Phillips Coal Company, Arco Coal Co., Ruhrkohle A.G., and ENI Exxon Research and Engineering Company and DOE entered into a Cooperative agreement in July 1977 for an integrated coal liquefaction development program to develop the EDS coal liquefaction process, funded by DOE and seven private sector participants. A central feature of the research and development project is the operation of a 250 ton-per-day coal liquefaction pilot plant which started up in 1980 in Baytown, Texas. First operations were on Illinois No. 6 coal in the once-through mode between June 1980 and June 1981 with a total of 3,903 hours on coal. All subsequent operations were in the bottoms recycle mode, as follows: Wyoming coal July 1981-Oct. 1981 1,842 hrs. on coal Illinois No. 6 coal Nov. 1981-Feb. 1982 2,024 hrs. on coal Wyoming coal Feb. 1982-May 1982 1,080 hrs. on coal Lignite coal May 1982-Ongoing The results of these tests indicate that the liquefaction section of a commercial-size plant operating on Illinois No. 6 could be designed when commercially justified. The final government co-sponsored test was concluded in mid-May 1982. Private sponsors continued testing Texas lignite until late summer 1982. Development of the hybrid boiler which combusts liquefaction bottoms to provide process heat and steam will continue into 1983. A toxicology program will also continue into 1985. Costs for the program are proportioned among the sponsors as follows: DOE - 48%, Exxon Co., USA - 24%, EPRI -12%, JCLD -8%, Phillips -2%, Arco Coal -2%, Ruhrkohle - 2%, and ENI -2%. Project Cost: $340.8 Million

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-89 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

EXXON EAST TEXAS PROJECT - Exxon Coal, USA Exxon was studying the possibility of constructing a 42,000 ton/day coal gasification plant. The project was to be located at a mine to be constructed in the East Texas counties of Cherokee, Rusk and Smith. The plant was to produce 800 MMCFO of 400-Htu/SCF gas and 10,000 bbl/day of liquids. The products could be used for industrial fuel or chemical raw materials. SASOL has tested a 16,000 ton sample of the coal to determine the technical feasibility of the Lurgi process for gasifying this lignite. Exxon signed a licensing agreement with Lurgi Kohle and Mineraloltechnik of West Germany for the preliminary design phase. In early 1982, Exxon decided it will not proceed with the project at this time. The Region VI Environmental Protection Agency held an EIS seeping meeting for the project late in 1980 in Jacksonville, Texas. EPA terminated the EIS after cancellation of the project. Project Cost: $20 million for detailed design $4 billion for commercial plant EXXON WYOMING PROJECT, COAL GASIFICATION - Exxon Coal, USA Exxon is studying the possibility of constructing a coal gasification plant in northern Wyoming. Gas from the plant could be processed to produce SNG, methanol or some other form of liquid product. Exxon has state and federal leases in both Sheridan and Campbell counties; however, the probable location of the plant would be near Gillette, Wyoming, in Campbell County. Exxon has maintained its option with the Powder River Irrigation District, for 25,000 AFY from the proposed Middle Fork of the Powder River reservoir project. Exxon has optioned to ARCO one half of this volume. Status -planning. Project cost: Undetermined

FAST FLUID BED GASIFICATION - DOE and Hydrocarbon Research, Inc. (Subsidiary of Dynalectron Corporation). HRI has designed, constructed and operated a nine TPD Process Development Unit (PDU) to further develop the Fast Fluid Bed (FF8) Gasification process. The FF8 concept was developed at the City University of New York. It operates at high gas velocity with recycle of solid char. The advantages of this mode are high capacity, good turn down and the ability to gasify caking coals at temperatures intermediate between conventional fluid beds and entrained beds. The process can produce a low or medium-Btu gas. The PDU gasifier is located at the HRI R&D Center, Lawrence Township, New Jersey. Construction and initial operations have been completed. Status -Unit has been operated at design throughput using anthracite and bituminous coals. The PDU has been modified for Phase If testing to recycle coal chars.

Project Cost: $4 million (Phase I contract) $1.8 million (Phase II contract) FIAT/ANSALDO PROJECT - Westinghouse Electric Corporation, Fiat 'F'l'G, Ansaldo, European Economic Community, EN EL (Italian State Utility). The Fiat/Ansaldo project, to be located in Sicily, will utilize the Westinghouse pressurized fluidized-bed coal gasification system in a power generation application. Low BTU coal gas will fuel a single gas turbine which will be one of two turbines in a 300 MW combined cycle plant. A 15 month feasibility study, funded by Fiat 'fl'G and Ansaldo in cooperation with the European Economic Community and ENEL is to be completed during the first quarter of 1983. A follow on to the design study could lead to the construction of a coal gas combined cycle plant in Sicily which could be in operation as early as 1986. Project Cost: not available

FIRST COLONY PROJECT - (see Peat Methanol Associates Project.) FLASH PYROLYSIS OF COAL WITH REACTIVE AND NON-REACTIVE GASES - DOE and Brookhaven National Laboratory The purpose of this program is to perform a systematic generic study on the flash pyrolysis of coal with reactive and non-reactive gases. The result of this task is to establish a reliable data base for the rapid pyrolysis of coal over a range of reaction conditions which will be useful for development of processes based on these techniques. The yields and distribution of products is being performed in an entrained tubular reactor. The independent variables to be investigated are type of coal, process gas, pressure, temperature and residence time. Other dependent variables include coal particle size and gas-to-solid feed ratio. The non-reactive gases qtjng investigated include the inert gases, He, N2 and Ar chosen for their wide range of physical properties. The reactive gases include H2, CO, H20

4-90 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

and CR 4 chosen because they are usually produced when coal is pyrolyzed. The light gas and liquid analyses are performed with an on-line gas chromatograph and the heavier liquids and solids are collected at the end of a run to obtain a complete mass balance. The data is to be reduced, correlated, and applied to a kinetic model. (NOTE: This program has appeared in previous issues under the title "Flash Ilydropyrolysis Project.")

Project Cost: $159,000 FLASH PYROLYSIS COAL CONVERSION - DOE, Occidental Research Corporation DOE awarded Occidental a three year $4.5 million cost sharing contract in October 1980 to further develop the flash pyrolysis process of coal conversion. Occidental had a previous contract with DOE to study the process from 1976 to 1978. This process was originally known as the Garrett Process. This process heats coal rapidly at atmospheric pressure in an entrained flow reactor in the absence of oxygen. Under these conditions, the coal breaks down into a carbon-rich char and hydrogen rich gases and liquids which can be upgraded to useable fuels. Earlier work on a 3 TPD unit had indicated that new methods of upgrading liquid quality are needed. One such method which employs hydrogen donor quench will be tested in the present program. The effect on product yield of varying the make-up of the transport gases used in the process will be tested in a small pilot plant with a coal feed rate of 2Kg/HR. In addition, the chemical reactions taking place when the hydrogen donor quench liquid contacts the hot product vapors will be studied using an ESE. Initial work will be with Wyodak Coal. Project cost: Total: $4.5 million DOE: $2.25 million Occidental: $2.25 million Contract No. DE-AC22-8OPC 30264 FLORIDA POWER COMBINED CYCLE PROJECT - Florida Power Corporation, DOE The DOE awarded Florida Power Corporation $1,380,796 for a feasibility study for a medium Btu combined-cycle repowering project to be located in Pinellas County, Florida. The project would use British Gas Corporation's slagging Lurgi gasifiers to supply medium-Btu gas to four General Electric combustion turbines. The Higgins Coal Gasification/Repowering Feasibility Study is complete and the final report has been submitted to the DOE. The study results indicate the project is technologically feasible. However, the capital cost estimate of $485 million is higher than expected. Study Cost: $1,380,796 Project Cost: $485 million FOREST CITY COAL GASIFICATION PROJECT - Billings Energy Corp; Forest City, Iowa; State of Iowa Billings Energy Corporation proposes to build a hydrogen-from-coal plant in Forest City, Iowa. Plant would use entrained or fluidized bed gasifiers to produce low-Btu gas from 300 TPD of coal. Gas quality upgraded by shift conversion, acid-gas scrubbing, and pressure swing adsorption process to produce 4.1 billion Btu per day of hydrogen. Hydrogen to be used for power generation and to supply fuel to an industrial complex. Project funded $100,000 by Iowa State appropriation, and $65,000 contribution from Forest City. Additional funding requested through the Department of Energy. Schedule calls for groundbreaking by January 1, 1983. The application to the SFC cited plans to use the Texaco gasifier for the project. Project Cost: Phase I - Economic Analysis, technical viability-$165,000 Patents and Impact Statements - 24 months Phase 2 - Engineering, contract issuance (12 months) Phase 3 - Construction - $50 million (24 months) GAS TURBINE SYSTEMS DEVELOPMENT —DOE, General Electric Co., and Curtiss-Wright Corp. General Electric and Curtiss-Wright are currently participating in Phase II of a three-phase DOE sponsored program, the High Temperature Turbine Technology (HVrT) Program. Project objective is to develop, during a six to ten-year time period, the technologies for a high temperature gas turbine which can be operated in a combined cycle facility. The turbine would burn coal-derived fuel at a firing temperature of 2,600°F, with a growth capability of extending the firing temperature to 3,000°F. Phase I of the H'FTT Program (Program and System Definition) began in May 1976 and was awarded to four contractors, General Electric, Curtiss-Wright, United Technologies, and Westinghouse. Phase II of the HTTT Program (Technology Testing and Test Support Studies) was awarded to General Electric ($31.5 million) and to Curiss-Wright ($21.4 million) in August 1977. The G.E. Phase II program was successful, and the final report was completed in December 1982. General Electric is developing the technology for a water-cooled gas

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-91 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

turbine while Curtiss-Wright is pursuing a transpiration air-cooled gas turbine approach. Phase III of the HTVF Program (Technology Readiness and Verification Testing) which was to entail the final design of the selected gas turbine and the verification testing of the machine prototype, has been cancelled. Project Cost: Phase I - $ 9 million Phase II - $58 million Phase III - Cancelled

GASIFICATION ENVIRONMENTAL STUDIES - DOE, Grand Forks Energy Technology Center, and the University of North Dakota The Grand Forks Energy Technology Center (GFETC) has the only oxygen-blown fixed-bed gasifier in the United States that is capable of operating on lignite. As such, the slagging fixed-bed gasifier (SFBG) pilot plant provides the only large-scale source of lignite-derived effluents for subsequent characterization and treatment studies. The ability to produce "representative samples" for treatment testing from lignite is critical, since lignite will be the feedstock for a number of the first-generation synfuels plants. The goals of work at GFETC are to develop public environmental data of effluent characteristics needed to satisfy permitting and siting requirements, and proof of concept on advanced control technologies for fixed-bed gasification of lignite. The principal area of uncertainty where research activities should be focused centers around the cooling tower. This view is shared by American Natural Resources, sponsor of the Great Plains Coal Gasification Project. The extent of wastewater treatment needed to produce a satisfactory feed to the cooling tower is unknown, and the environmental and economic risks are substantial. The most cost-effective approach is to feed water directly from the extraction/stripping units to the cooling tower, without intermediate biological treatment. This wastewater, however, contains several thousand mg/i of COD - after phenolics and other organics are reduced to low levels. The behavior of these previously uncharacterized species in a cooling tower with respect to drift, further biological activity, and associated fouling, and their effects on the solubility of dissolved solids is unknown. To establish the effect of various degress of pretreatment, GFETC has installed wastewater treatment process development units which simulate commercially available technology. During the first phase of the program, wastewater will be processed by solvent extraction and ammonia stripping before being fed to a cooling tower to simulate the processes to be employed at the Great Plains plant. A goal of the test, using wastewater derived from the same lignite to be used by GPGA will be to characterize the nature of the drift and evaporate from the cooling tower as well as to assess the potential fouling of heat exchange surfaces. In the second phase, wastewater pretreatment will be enhanced by the inclusion of activated sludge processing, in addition to extraction and stripping, before feeding the cooling tower. In the interim, lignitic wastewater will be tested in improved or alternative treatment processes. An area of treatment currently under investigation is the use of anaerobic degradation of wastewater contaminants, which offers the potential for reduced energy consumption. (NOTE: This project has appeared in previous issues under the title "Slagging Gasifier Development" Project Cost: $2.7 million in FY 1983 GEGAS-D PROJECT - (See IGCC Simulation) GRACE COAL-TO-METHANOL-TO-GASOLINE PLANT- DOE. W. R. Grace & Co. Cooperative Agreement No. DE-FC01-80ET-14759 was awarded to W. R. Grace & Co. in August 1980. A Notice to Proceed with the performance of the efforts required under the Cooperative Agreement was executed on October 6, 1980. The Cooperative Agreement calls for the preliminary process and mechanical engineering design, economic and environmental assessment, construction and operations planning, permit prosecution and financing investigation for a 50,000 barrels per day coal-to-methanol-to--gasoline plant to be located in Haskell, Kentucky. The facility will utilize the Texaco Coal Gasification Process (TCGP) and the fixed bed Mobil Methanol to Gasoline (MTG) process. The plant will utilize approximately 29,000 tons per day of high sulfur agglomerating coal (including utility coal) to produce approximately 16,000 tons of methanol with subsequent conversion into 50,000 barrels per day of gasoline plus by-product Cq and C LPG streams. Contractual arrangements have been completed with the Ralph M. Parsons Company for archifect/engineer and related services, and with Texaco Development Corporation and Mobil Research and Development Corporation for the supply of proprietary inputs regarding their respective processes. Lotepro, a subsidiary of Linde AG, has been selected to provide the preliminary design of a Reetisol acid gas removal system. Activities to date include continuation of land assessment studies, environmental investigations documenting the requirement of an Environmental Impact Statement and the completion of process selection for air separation, methanol synthesis, acid gas removal, sulfur recovery and alkylation technologies. Development of process and mechanical design documentation has been initiated in each of these areas. An application for financial *New or Revised Projects

4-92 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

assistance (loan and price guarantees) and supporting detail has been submitted to the Synthetic Fuels Corporation. However, Grace did not meet the SFC's January 5, 1982 deadline for additional information.

Project Cost: Preliminary design - $11.3million (DOE) Construction cost - $3.0 billion (1980 dollars) GRAND FORKS LIQUEFACTION PROCESS FOR LOW-RANK COALS - (See Low-Rank Coal Liquefaction Research) GRANTS COAL TO METHANOL PROJECT - Energy Transition Corporation Energy Transition Corporation proposed to build a 67 million gallon per year coal-to-methanol plant using the KBW gasifier. Ultimate production would be 500 million gallons per year. Price guarantees of 75 cents per gallon (January 1981 dollars escalated quarterly at the inflation rate plus i percent) were requested from the SFC. The Project was withdrawn from SFC consideration in December 1981. Plant location is the Lee Ranch, 32 miles northeast of Grants, New Mexico. Project Cost: $350 million

GREAT PLAINS GASIFICATION PROJECT - Great Plains Gasification Associates, (Composed of ANR Gasification Properties Company, Tenneco SNG Inc., Transco Coal Gas Company, MCN Coal Gasification Company, and Pacific Synthetic Fuel Company) Initial design work on a coal gasification plant to be located near Beulah in Mercer County, North Dakota commenced in 1973. Michigan Wisconsin Pipe Line retained such companies as C-E Lummus, Raymond Kaiser Engineers and Lurgi Roble and Mineraloltechnik GmbH to perform major engineering work. In 1975, ANG Coal Gasification Company (a subsidiary of American Natural Resources Company) was formed to construct and operate the facility and the first of many applications were filed with the Federal Power Commission (now FERC). The original plans called for a 250 MMcfd plant to be constructed by late-1981. However, problems in financing the plant delayed the project and in 1976 the plant size was reduced to 125 MMcfd. Peoples Gas Company (now MidCon Corporation) was added as an equal partner in 1977. Financing problems still continued and in 1978, at the recommendation of the Department of Energy (DOE), three additional partners were added to the project and a partnership named Great Plains Gasification Associates was formed by affiliates of American Natural Resources, Peoples Gas, Tenneco Inc., Transco Companies Inc. (now Transco Energy Company) and Columbia Gas Systems, Inc. Under the terms of the partnership agreement, Great Plains would own the facilities, ANG would act as project administrator and the pipeline affiliates of the partners would purchase the gas. Proceedings at the FERC continued, and finally in January 1980, FERC issued an order approving the project. Also in this time frame, ANG and DOE entered into a $25 million cooperative agreement that would be repaid once financing was in place. In late March 1980, General Motors, the State of Michigan, the New York Public Utilities Commission and the Ohio Consumer's Counsel filed to have the FERC order overturned on the ground the FERC had overstepped its authority in granting the tariff provisions that would allow the project to be financed. This effectively put a temporary hold on the construction of Great Plains, which had been expected to begin in April. In order to keep the project alive, Great Plains requested and received a $250 million loan guarantee to cover costs during the first year of construction. Site grading and preliminary construction activities began in late July 1980. In November 1980, DOE announced the new conditional approval of up to $1.5 billion of the project cost. However, before this agreement could be finalized, the U.S. Court of Appeals overturned the FERC decision. In January 1981, the project was restructured as a non-jurisdictional project with the SNG sold on an unregulated basis. After months of negotiations among the sponsors, the FERC staff and the intervenors, in April 1981, an agreement was reached whereby the gas would be sold under a formula which escalates quarterly according to

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-93 STATUS OF SYNFIJELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

increases in the Producer Price Index and the price of No. 2 Fuel Oil, with limits placed on the formula by the price of other competing fuels. During these negotiations, Columbia Gas withdrew from the project. However, full scale construction could not commence until August 6, 1981 when DOE announced the approval of a $2.02 billion conditional commitment to guarantee loans for the project. This commitment is sufficient to cover the debt portion of the gasification plant, Great Plains' share of the coal mine associated with the plant, a SNG pipeline to connect the plant to the interstate natural gas system, and a contingency for overruns. Finally, approval of the loan guarantee was received on January 29, 1982. The debt secured by the loan guarantee will be received through weekly drawdowns from the Federal Financing Bank, a corporate instrumentality of the United States of America. The project sponsors are generally committed to providing one dollar of funding for each three dollars received under the loan guarantee up to a maximum of $740 million of equity funds, On May 13, 1982, it was announced that a subsidiary of Pacific Lighting Corporation would acquire a 10% interest in the partnership; 7.5% from ANR's interest and 2.5% from Transco. The consortium is as follows after the transfer which was approved by the DOE in November: o American Natural Resources - Detroit, Michigan Partner - ANR Gasification Properties Company 25.0% Purchaser - Michigan Wisconsin Pipe Line Company 25.0% • Tenneco Inc. - Houston, Texas Partner - Tenneco SNG Inc. 30.0% Purchaser - Tennessee Gas Pipeline 30.0% • Transco Companies, Inc. - Houston, Texas Partner - Transco Coal Gas Company 20.0% Purchaser - Transcontinental Pipe Line Corp. 25.0% • MidCon Corporation - Chicago, Illinois Partner - MCN Coal Gasification Company 15.0% Purchaser - Natural Gas Pipeline Co. of America 20.0% • Pacific Lighting Corporation - Los Angeles Partner -Pacific Synthetic Fuel Company 10.0% Purchaser - (none) The project, when completed in late 1984 will produce 125 MMcfd of high Btu pipeline quality synthetic natural gas, 93 TPD of ammonia, 85 TPD of sulfur, 200 NlMcfd of CO2, and other miscellaneous by-products. Estimated costs to completion is approximately $2.1 billion (excluding any pipeline costs but including $iss million of mine costs). Contracts that have been awarded for major portions of the facility include: o two air separation plants - Lotepro, a subsidiary of Linde AG, West Germany; • three steam boilers fired by waste gas and liquid by-products - Riley Stoker Corporation, Worcester, Mass.; and • Stretford H2S removal unit - Ralph M. Parsons Company. As of the end of October 1982, construction was approximately 31% complete, engineering was about 87% complete, and procurement of all materials was 99% complete. All 14 Lurgi gasifiers had been installed by early November. Spending for the project through October 1982 was approximately $679 million. Project Cost: $2.1 billion GREECO LOW-BTU PROJECT - DOE, General Refractories Company (GREFCO) DOE awarded General Refractories Company approximately $1 million to perform an engineering feasibility study for a low mu facility. The 3.5 billion Btu/D of industrial fuel gas produced would be used for drying of building products and also for fuel in perlite-expanding furnaces. The feasibility study conducted by Drove Corp. is complete. The primary purpose of the study was to provide General Refractories with sufficient engineering and financial information to determine the viability of a gasification facility at their Florence, ICY, plant. Five Wellman-Galusha gasifiers would be required to produce 6 billion Btu per day. The study also investigated a two-gasifier facility that could be expanded by the addition of three more gasifiers. The two-gasifier facility would not become competitive

4-94 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

with natural gas until after 1990 if at all whereas the five-gasifier facility would break even somewhere between 1984 and 1989. General Refractories has decided to wait until more substantiating evidence is available that natural gas prices will rise as is now being predicted. Project cost: five gasifiers - $33 million two gasifiers - $24 million GULF STATES UTILITIES PROJECT - Westinghouse Electric Corporation (sponsor), Gulf States Utilities Co. (partner), Dravo Corporation, Stone & Webster Inc., Energy Impact Associates (environmental Assessment), Arthur Anderson (financial assessment), DOE. The proposed Gulf States Utilities project, to be located at the Gulf States Utilities Roy S. Nelson Station in Louisiana, will utilize the Westinghouse pressurized fluidized-bed coal gasification system in a power generation application. Wyoming sub-bituminous coal will be gasified to fuel a 100 MW Westinghouse W501D combustion turbine in a repowering combined cycle system. A $1.4 million DOE funded feasibility study will be completed during the last quarter of 1982. The coal gasification system could be operational at the site by the last quarter of 1985. HAMPSHIRE GASOLINE PROJECT - Hampshire Energy Group Northwestern Mutual Life Insurance, Metropolitan Life Insurance Company, Koppers Co., and Kaneb Services) and DOE In response to DOE's initial solicitation under Public Law 96-126, Hampshire was awarded $4,000,000 for a feasibility study of a coal-to-gasoline facility. Price and loan guarantees for the project were requested from the Synthetic Fuels Corporation. The project passed the SFC's strength criteria and progressed to the second phase of negotiations for assistance. In September 1981, Hampshire Energy submitted an application for a permit to build the facility at a site 10 miles southeast of Gillette, Wyoming in Campbell County. The plant will convert 15,400 TPD of purchased coal into approximately 19,000 BPD of gasoline, 914 BPD of propane LPG, and 1618 BPD of mixed butanes. Fourteen Lurgi pressure gasifiers (427 PSI) will gasify 11,000 TPD of coal, while 4,400 TPD will be gasified in three parallel Koppers-Babcock and Wilcox (KBW) atmospheric gasification units. The 1<8W gasifiers will use the fines (under 1/4 inch) from the coal preparation operation, leaving the larger size coal (4 inch x 1/4 inch) available for Lurgi feed. Following removal of by-products, the Lurgi crude gas will be mixed with a portion of the 1<8W gas and processed by shift conversion to produce hydrogen to maintain the proper hydrogen-to-carbon monoxide ratio in the methanol synthesis feed gas. The gas stream from shift conversion will be cooled before entering the Rectisol Unit. Naphtha, carbon dioxide and sulfur compounds will be removed from the gas stream. The naphtha will be hydrotreated to remove sulfur compounds before being blended with the main gasoline product. The carbon dioxide by-product from shift conversion will be used in oil fields for enhanced oil recovery (EOR) operations. The sulfur compounds will be converted to elemental sulfur. Purified synthesis gas from Rectisol Unit will be mixed with a recycled hydrogen stream, compressed, and fed to the methanol synthesis loop. The crude methanol product will be converted to high quality gasoline, liquefied petroleum gas (LPG), and isobutane via the Mobil "M" process and associated process units. The methanol-to-gasoline conversion will occur in two trains of process units designed to process the total methanol production. A dimethyl-ether (DME) reactor and five parallel conversion reactors in each train will convert the methanol produced to a marketable grade of gasoline. Gasoline will be transported to market by rail. The potential of gasoline transport by pipeline is being evaluated. Carbon dioxide will be delivered to market by a separate pipeline. Ammonia, propane, butane and sulfur will be delivered to their market destination by rail and/or truck. Initial construction activities were planned for April 1982, contingent upon receipt of applicable permits. However, the Wyoming Department of Environmental Quality requested further information from the project sponsors. The state delayed action on permits for air quality, water quality and solid waste management. Following several weeks of testimony, the Wyoming Industrial Siting Council unanimously approved the project on November 20, 1982. The permit to build the plant was a major hurdle for the project. The sponsors have conducted expanded studies of the water supplies needed for the project. These studies indicate the projects use of the Lance/Fox Hill aquifer will not affect other water users. A 44-month construction period is planned, with mechanical completion originally scheduled by the end of 1985. Estimated construction cost in 1981 dollars is $1.3 billion.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-95 STATUS OF SYNPUELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

On October 19, 1982, Standard Oil of Ohio announced it was withdrawing from the project. four narticinants exoressed confidence in the oroleet. on December 2 the y announced

H-COAL PILOT PLANT - DOE, Ashland Synthetic Fuels, Inc., Conoco Coal Development Co., Mobil Oil Corp., Standard Oil Co. (Indiana), Commonwealth of Kentucky, Electric Power Research Institute, Ruhrkohle AG (West Germany), Hydro- carbon Research Inc. (subsidiary of Dynalectron Corporation) During May 1980, coal liquefaction operations began on the 600 TPD U-Coal pilot plant located near Ashland's Catlettsburg, Kentucky oil refinery. Initial break-in operations were completed in mid-November and the plant was then shutdown for maintenance and mechanical improvements. The plant has completed over 140 days of operation on Illinois Basin coal feeds. Over 20,000 tons of Kentucky and Illinois coal have been processed into synthetic crude since May 1980. Operations were terminated in December of 1981 for plant maintenance in preparation for resuming Syncrude operations on Wyoming coal in early March. The tests using Wyodak coal began in mid-March 1982 using a catalyst called AMOCAT developed by Amoco Oil. In the H-Coal process dried, ground bituminous, subbituminous or lignite coal is slurried with process derived oil then pumped and heated to reactor conditions. The coal is reacted with hydrogen in an upflowing ebullated catalyst bed. Reactor effluent is depressurized and hydrocloned into a low ash recycle and a high ash stream which is fractionated to final products. In a commercial plant, the solids-bearing vacuum tower underflow could be gasified for hydrogen production. HRI is conducting a program of R&D support for pilot plant operations and process improvement for the pilot plant. Project funds have been proportioned: DOE (80 percent) and industrial participants (20 percent).

Project Cost: $296 million (design - $14.7 million, construction - $157.3 million, operation for two years - $124 million) (NOTE: also see Breekinridge Project) HOWMET ALUMINUM PROJECT - Howmet Aluminum Corporation, Lancaster, PA A ten-foot diameter single stage Wellman-Galusha gasifier was installed to produce low-Btu gas equivalent to 500 MMBtu per day for use in aluminum melting furnaces. The low Btu gas from the gasifier was mixed with a small amount of fuel oil natural gas and the mixture was successfully used in an aluminum melting furnace for several months. The unit is presently off-stream because a sufficient amount of natural gas is available. Project Cost: $700,000

IGCC EXPERIMENTAL SIMULATION - General Electric Co. G.E. is using a 24 TPD, 23 atmosphere coal gasification facility to provide an accurate simulation of an integrated gasification, combined cycle (IGCC) power generation system. The plant, located at G.E.'s Research and Development Center at Schenectady, New York, was first operated in 1976. The facility incorporates a fixed bed gasifier developed by GE, to study the gasification of highly caking fuels at reduced steam/air ratios under clinkering conditions. In addition complete fuel gas physical and chemical clean-up equipment is included, and a turbine simulator is used to evaluate combustion characteristics. The entire system is fully operational and has been evaluated over a wide spectrum of operating conditions and with a range of coal types. A test series was completed in which the gasification and cleanup system supplied clean coal-derived fuel to a turbine simulator operating at advanced gas turbine firing conditions of 2,600° F turbine inlet temperature and a pressure ratio 12 to 1. A $9.3M million DOE program is currently underway to develop the technology base needed to ensure compatibility with the constraints imposed by end-use applications. These constraints include dynamic load response to variations in end- use demand, and compliance with environmental regulations. The first two years of this program have resulted in

4-96 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

Project Cost: $12.5 million INTEGRATED TWO-STAGE LIQUEFACTION - DOE and Cities Service/Lummus A program has been initiated between DOE and Cities Service/Lummus for study on the chemistry, mechanisms, and process conditions for the expanded bed upgrading of coal extracts. This study will be combined with the exploratory development of an Integrated Two-Stage Liquefaction (ITSL) process. No effect of solvent boiling range (500 - 850°F to 740 - 850°F) was noted for 850°F4- conversion at a 780°F operating temperature. The denitrogenation was improved with a heavier boiling solvent. The thermal effect upon 850°F-I- SRC-I coal extract conversion using a calcined extrudate (no metals loading) is less than would have been expected from petroleum residuum considerations. A substantial portion of the 850 0 E-I- conversion of coal extracts is catalytic in nature. The first phase of a parametric study on total reactor pressure, space velocity, and temperature has been completed. The high chloride content of SRC-1 coal extracts obtained from the Pyro and Lafayette mines has essentially nc effect on the LC-Fining hydroprocessing. The influence of diffusion on catalyst performance is being measured by comparing the results from three different sized extrudates. In the Integrated Two-Stage Liquefaction process, the non-catalytic short contact time (SCT) coal dissolution and C- E Lummus antisolvent deashing have been successfully combined, and solvent has been hydrotreated in the LC- Fining unit. Using Indiana V coal, this portion of the program has demonstrated the following results: the distillate (Cs-850°F) product contains less than 0.2% nitrogen and 0.2% sulfur; overall distillate yield is 3 barrels per ton of moisture free coal; the LC-Finer catalyst activity has been maintained for over 1300 pounds of 850°F-I- feed per pound of catalyst with a maximum reactor temperature of 780° F; the SCT reaction is in solvent balance and achieves over 90 percent conversion of MAP coal with a chemical hydrogen consumption of less than one percent; the heavy oil product from LC-Fining is an excellent hydrogen donor for the SCT reaction. A SCT Extract from an Illinois 6 coal shows an 850°F-'- conversion within the LC-Finer which was averaging 35-40% higher than the Indiana V SCT Extract at similar operating conditions. However, the Illinois 6 coal showed a more rapid change in catalyst activity for both

have signed a $10.31 million contract to extend the work on ITSL for an additional two The new cor 1/3 tpd PDU. Project Cost: $17.6 million KEN-TEX PROJECT - Texas Gas Transmission Corp. Texas Gas acquired from Consolidated Coal Company a half interest in an extensive block of coal reserves in the Illinois basin area. The reserves are in two parcels. Approximately 3.5 trillion SCF of SNG are recoverable from the reserve. Texas Gas and the Commonwealth of Kentucky, proposed a two-phase program to develop a coal gasification complex to be located on the Ohio River in western Kentucky. HYGAS Process would be used to produce pipeline quality high-Btu gas of 975 Btu/CF heating value. Phase 1 -80 MMSCFD demonstration plant. Phase II -250 MMSCFD commercial facility. Project Cost: $750 million for Phase 1-80 MMSCFD KEYSTONE PROJECT - Westinghouse Electric Corporation, Air Products and Chemicals, Inc; AmeriGas, Inc; Bethlehem Steel Corporation; Dravo Engineers and Constructors; Johnstown Area Regional Industries, Inc.; Energy Impact Associates, Inc.; Lehman Brothers Kuhn Loeb, Inc.; DOE The proposed Keystone Project will utilize domestic coal resources to produce coal liquids using coal gasification and indirect liquefaction technology. The eventual commercial plant will be a nominal 67,000 barrel per thy methanol facility located in the Cambria County area of Western Pennsylvania. The objective of the Keystone Project is to produce methanol as a transportation fuel and fuel supplement, a combustion turbine fuel for power generation, and a chemical feedstock. A 13,300 barrel per day single-train module is planned to validate the commercial applicability of the system. Funding for a feasibility study for this project was awarded by the Department of Energy. Project sponsors applied to the Synthetic Fuels Corporation (SFC) for financial assistance under the SFC's second solicitation that ended June 1, 1982. The requested assistance included loan and price

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-97 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.)

guarantees plus a cost sharing agreement for design and cost refinement. However, the project failed to pass the SFC's project maturity test. Project Cost: $4.8 million - feasibility study. KILnGAS PROJECT - Allis-Chalmers, State of Illinois, Electric Utility participants are: Baltimore Gas and Electric Co., Central Illinois Light Company, Consumers Power Co., Illinois Power Co., Iowa Power & Light Co., Monongahela Power Co., Ohio Edison Co., The Potomac Edison Co., Public Service Indiana, Public Service Co. of Oklahoma, Union Electric Co., West Penn Power Co., Electric Power Research Institute The KILnGAS process is based on Allis-Chalmer's extensive commercial experience in rotary kiln, high temperature minerals processing. A pilot plant in Oak Creek, Wisconsin has operated at 60 TPD throughput. Groundbreaking for a 600 TPO Commercial Module plant occurred on October 31, 1980. Detailed engineering design and procurement of long-lead equipment are more than 60% complete. Foundations for the major equipment are now in place. Fabrication of the 190' long x 13' diameter ported rotary kiln gasifier shell was completed at the West Allis plant of the Allis-Chalmers and was installed at the plant site. Pressure tests of the gasifier were performed at the end of May 1982. In addition, equipment for the auxilliaries are now on order with about 60% already at the site. The plant will provide low-Btu (160 Btu/SCF) gas to the Wood River Station of the Illinois Power Company at East Alton, Illinois. Mechanical completion is scheduled for late 1982. Gilbert/Commonwealth Associates, Inc., is the Architect-Engineer. J.A. Jones Construction of Charlotte, N.C. is the construction manager for the plant. State of Illinois has allocated $18 million in Coal Development Bond Act funds to assist in construction of the plant. EPRI joined the project in March 1982 and will provide funding of two additional tests of high sulfur caking coals (Illinois No. 6 and Pittsburg No. 8). The objectives of the KILnGAS Demonstration Program are the following: (I) Demonstrate technical performance in a utility environment; (2) obtain operating data for forecasts of commercial production costs; (3) obtain data to confirm process design; and (4) establish the design basis for proceeding with 4,000 to 5,000-TPD units. With the successful operation of the Commercial Module plant in 1983, Allis-Chalmers plans to offer these larger plants on a turnkey basis with normal commercial warrantees. Project Cost: Estimated at $137 million, which includes two years of operation. Committed Funding Sources: Electrical Utility Participants $ 34 million State of Illinois $18 million Allis-Chalmers $ 79.5 million EPRI (testing only) $ 5.75 million TOTAL $137.25 million KIN G-WILKINSON/HOFFMAN PROJECT - King-Wilkinson, Inc. and E. J. Hoffman Project sponsors are developing a packaged, skid-mounted unit with a throughput of 100 to 200 TPD of coal to utilize the Hoffman coal gasification process. In addition to synthetic fuels from coal, the process produces carbon dioxide that can be used for enhanced oil recovery. The process is a direct catalytic gasification technology utilizing an ebullating bed reactor. Pulverized coal and alkali (sodium or potassium carbonate) are fed into the catalyst bed. Alkali-nickel catalysts can be used to produce methane whereas alkali-iron catalyst can be used to product liquids. Project sponsors are seeking additional equity sponsors to test a pilot scale unit. Project Cost: not specified LAKE DESMET SNG FROM COAL PROJECT - Texaco Inc. and Transwestern Coal Gasification Co. In May 1982 the project sponsors decided to indefinitely defer the project due to high capital cost estimates and reduced oil prices. The sponsors have indicated that they will reconsider the project at such time when it is believed that the synfuels plant, upon completion, would have a viable economic future. Texaco and Transwestern Coal Gasification Co. (a subsidiary of Texas Eastern Corp.) conducted a privately funded study to evaluate the feasibility of constructing a commercial scale synthetic fuels plant near Lake DeSruet in north-central Wyoming. The plant would convert approximately 38,000 tons of coal per day to approximately 127 million cubic feet of synthetic natural gas and 55,000 barrels per day of methanol. Texaco Inc. has approximately 37,000 acres at the Lake DeSmet site with 2.3 billion tons of coal underlying the property. Texaco has previously completed a multi-million dollar water development program and has sufficient industrial water supplies for the proposed gasification plant and other commercial projects. The two companies plan to become joint participants in the synfuels facility itself, with Texaco Inc. being the sole owner and operator of the mine supplying the feedstock for conversion to synfuels. Included in the study were

4-98 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.) environmental acceptability, site selection, socio-economic impact, financial planning, and preliminary process design. Project Cost: Estimated between $3 - S billion LC-FINING PROCESSING OF SRC EXTRACT - DOE and Cities Service Pilot plant studies were made to demonstrate the use of Lumnius/Cities-Fining (LC-Fining) technology to upgrade solvent refined coal extract (SRC-1). SRC-1, which initially contains 0.8 percent sulfur and 2.0 wt. percent nitrogen, has been upgraded to distillate products which contain c 100 ppm sulfur and 0.3 wt. percent nitrogen using NiMoly catalysts. Ninety percent conversion of SRC-I to distillates has been obtained in recycle operation. Additional work has been undertaken to investigate the effects of processing with a 680°F plus solvent. Both 50/50 and 70/30 SRC-1 solvent feed blend ratios have been run. SRC-I from Western coal, and short residence time (SCT) coal extract prepared at Wilsonville (both deashed and non-deashed) have been tested. The process parameters of hydrogen pressure and space velocity have been examined with both SRC-1 and SCT. Higher pressure operation tends toward a decrease in the catalyst deactivation rate for conversion. Expanded bed processing in the various modes described above has been demonstrated to be completely feasible and desirable to produce low nitrogen distillates (390-850° F). The technical information derived from this work is being used in support of the current DOE-sponsored two-stage liquefaction program. Hydroeracking of the SRC-l/SCT coal extracts in the presence of selective catalyst and under optimum conditions of temperature and space velocity, enhanced the production of middle distillate liquid fuels, minimized the formation of light hydrocarbon gases, and optimized the overall utilization of hydrogen. SCT coal extracts show a greater percentage denitrogenation in the total liquid product than SRC-1 coal extract. Also SCT coal extracts show a lower C. - C4 gas yield. PDU operations under this contract have been completed and a final report has been issued. Thi project has been completed. Project Cost: $2.8 million LIGNITE BRIQUETTE GASIFICATION PLANT - Black, Sivalls & Bryson, Incorporated, Texas Energy and Natural Resources Advisory Council, Elgin-Butler Brick Company A feasibility study jointly conducted by Black, Sivalls & Bryson, Incorporated (BS&B), and Texas A & M, showed that briquetted lignite is usable as a gasifier feed stock. BS&B was awarded a contract to provide engineering design and economic analysis for the construction of a commercial lignite briquette gasification plant. Texas Energy and Natural Resources Advisory Council provided $100,000 of the contract and under the terms• of a cooperative agreement, BS&B and Elgin-Butler Brick will contribute the equivalent of $100,000 and $50,000 respectively. The plant will be designed to produce fuel gas for the brick and ceramic kilns of Elgin-Butler who recovers 140,000 tons of lignite annually in the process of clay mining in central Texas. The design for the plant was scheduled for completion mid-1981. Project Cost: $250,000 engineering design and economic analysis LOW-RANK COAL LIQUEFACTION RESEARCH - DOE, Grand Forks Energy Technology Center, University of North Dakota The Grand Forks Energy Technolgy Center (GFETC) and the Departments of Chemistry and Chemical Engineering at the University of North Dakota (UND) are engaged in a cooperative effort of research aimed specifically toward advancing the technology of low-rank coal (LRC) liquefaction. Liquefaction research facilities at GFETC include: 1) a 10-lb/hr continuous process unit; 2) a batch reactor that can be charged hot and sampled during testing; and 3) highly sophisticated analytical equipment including NMR, GCMS and X-ray spectrometry. UND has both hot- and cold-charged batch reactors and extensive equipment and laboratory facilities for low-rank coal liquefaction research. Program objectives have included work with both lignite and subbituminous coals, and recent efforts have focused on process adaptation, disposable catalysts including hydrogen sulfide, product characterization, kinetic model development, and tracer studies using deuterium and 13CO. Process adaptation studies have included parameteric investigations of reaction variables to identify the necessary changes in design and operating conditions required to adapt the major developing processes of SRC-1, SRC-H, H- coal, and Exxon Donor Solvent for use with low-rank coals while effectively utilizing the unique properties of these coals. These properties include high moisture, high reactivity associated with oxygen functionality and alkaline mineral matter content, which is largely inherent rather than extraneous. The results of these studies indicate that product yield and process operability are improved by inclusion of at least some of the inherent moisture in low-rank coals and by the use of some carbon monoxide in the reducing gas, rather than pure hydrogen. Tests with bottoms recycle to simulate SRC-II showed that lignite could produce distillate oil yields comparable to those from

New or Revised Projects

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-95 STATUS OF SYNPUEL.S (Underline Denoted Changes Since September 1982)

COAL CONVERSION PROJECTS (Cont.) bituminous coals and that this mode of operation resulted in about a 50-percent increase in oil yields over those obtained in the SRC-1 simulation without bottoms recycle. Coal variability studies established a base from which the liquefaction behavior of Gulf Coast and Northern Great Plains lignite could be compared. Aside from geographic location, one obvious difference between the northern and southern lignites was found in sodium content, with the northern lignites having appreciably higher sodium concentrations than the Texas lignites. Batch and continuous liquefaction tests using hydrogen or a mixture of hydrogen and carbon monoxide indicated that the liquid yields and conversions obtained from these lignites were nearly identical and generally less than from bituminous coals when processed in the SRC-I mode. Disposable catalyst studies using hydrogen or syngas and with both hydrogenated and unhydrogenated solvents were performed with eight lignites and three subbituminous coals chosen for their wide diversity of mineral matter. In the batch tests, both hot- and cold-charged which represent 'coal only' non-recycle tests, it was not possible to discern any catalytic effects associated with inherent mineral matter. Experiments in which portions of the THF soluble matter (inorganics and unreacted coal) from previous tests were added back to a fresh coal slurry proved inconclusive. Continuous tests with other disposable additives, such as iron pyrite and magnetite, showed the presence of iron to be beneficial in promoting hydrogenation of the product. The most significant breakthrough for direct LRC liquefaction has been in the area of homogeneous catalysis. Research performed by the Department of Chemistry at UND indicates that the active catalyst in some disposable catalyst systems may not be the metal but rather the sulfur or hydrogen sulfide, a component generally found only in low concentrations in LRC. Continuous tests employing slurry recycle and using added hydrogen sulfide in catalytic quantities have indicated that a significant reduction in processing temperature is possible while maintaining a relatively high yield of distillable oil. Recycle tests made with a low-sulfur Texas lignite and with the addition of hydrogen sulfide showed that nearly equal yields of total oil were obtained at 400°C when compared to the yields obtained at the on- catalyzed optimum temperature of 460°C. At the lower temperature, slightly less distillate and slightly. greater solvent-refined lignite yields were obtained; however, the hydrogen consumption at 400°C was less than a third of that at the non-catalyzed optimum. Thus hydrogen sulfide appears to be an inexpensive, disposable liquefaction catalyst which allows liquefaction to occur at reduced temperatures with excellent distillate oil yields and with significant reductions in hydrogen consumption. The thrust of analytical research in product characterization is to better understand the chemistry of coal liquefaction and relate it to coal structure and process parameters. Work has included development of advanced techniques for characterizing the aliphatic, aromatic, and phenolic fractions of liquefaction products. Recent research efforts have shown that: 1) the concentration of normal alkanes in the distillable oils when syngas was used for processing was about twice that obtained when hydrogen was used; 2) the use of added hydrogen sulfide during liquefaction resulted in higher concentrations of hydroaromatics in the recycle solvent; and 3) sulfur was not incorporated to any appreciable extent in the distillable products during liquefaction with added hydrogen sulfide. (NOTE: This project has appeared in previous issues under the title, "Grand Forks Liquefaction Process for Low- Rank Coals"). Project Cost: $1.2 million, FY 1983 LOW/MEDIUM BTU GAS FOR MULTI-COMPANY STEEL COMPLEX - DOE, Northern Indiana Public Service Company, Bethlehem Steel Co., Inland Steel Co., Jones and Laughlin Steel Co., National Steel Co., and Union Carbide Corporation. DOE funded a study to determine the feasibility of constructing a commercial coal gasification facility to supply low/medium Btu gas to the six participating firms. The study determined the usability of low-medium Stu gas by the steel companies and other industries in northern Indiana, established a conceptual design and economics for the initial commercial plant, analyzed the commercial and financial feasibility of the project and recommended the approach to organize and implement the project. A proposal for a second phase feasibility study was submitted to DOE in April 1981, but was turned down. The project has been shelved and the sponsors do not intend to revive it in the foreseeable future. Project Cost: $922,000 *MAPCO COAL-TO-METHANOL PROJECT - Mapco Synfuels MAPCO proposes to use the Texaco gasification process and the low pressure ICI methanol synthesis process for a methyl fuel project. The mine-mouth site is located near the White County Coal Company, Carmi, Illinois. As presently designed, the plant will convert 4400 t/d of Illinois #6 coal into 2700 t/d of fuel grade methanol, with an option for chemical grade product. The Phase I conceptual engineering and cost estimate was completed in July 1982 by Kellogg/Rust Synfuels of Houston. *New or Revised Projects

4-100 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

The project was under active consideration by the SFC under their 2nd solicitation, but to allow for more orderly project development, MAPCO requested that the project be removed from consideration. Planning efforts are focusing on definition of Phase II work scope and recruitment of additional sponsors. Project Status: Planning Phase II effort MEDIUM BTU GASIFICATION PROJECT - Houston Natural Gas Corporation, Texaco Inc. The feasibility of building a medium-Btu coal gasification plant using the Texaco coal gasification process to produce 260-Btu/SCF synthesis gas has been under study by Houston Natural Gas Corporation (HNG) and Texaco Inc. since late 1979. A preliminary engineering study was completed by Ebasco Services in January 1980. Texaco and HNG received a DOE grant in August 1980, based on a $3.6 million request to study the feasibility of a 6,000 ton/day facility to be located adjacent to Texaco's oil refinery on the Mississippi River at Convent, LA. The facility would utilize synthesis gas to manufacture 26,000 barrels a day of methanol. Status: The study was completed February 1982. The study results indicate the technologies chosen have been individually demonstrated on a commercial basis and operating results of the Texaco Gasification Process to date, and expected operation of commercial sized units under construction support the commercial technical viability. Environmentally, the result of monitoring, modeling, and assessment indicate that licensing is feasible through the use of conventional control equipment. Commercial evaluations resulted in a constructed project cost of approximately $1.1 billion (1981 P. The resulting methanol price indicates a modest return on investment for the project. The project is considered feasible, but market considerations of price and product utilization must be monitored closely before a decision to proceed can be reached. Project Cost: $1.1 billion (1981) MEDIUM BTU SYNTHESIS GAS STUDY - Bechtel, Inc., Conoco, Inc., PPG Industries, AIRCO, Inc., and United Energy Resources, Inc. A feasibility study for a medium-Btu coal gasification plant to be located in Louisiana has been completed. Initial output of the plant was to be 125 billion Btu daily for a variety of purposes, such as expansion of operations, sales to other industrial customers, and feedstocks for products such as methanol. Sponsors conclude that the project should

Estimated Cost: $1,500,000 for the study. MEMPHIS INDUSTRIAL FUEL GAS DEMONSTRATION PLANT — DOE; Mid-South Synfuels, Inc. (Memphis Light, Gas and Water Division; Foster Wheeler Energy Corp.) The Department of Energy awarded Memphis Light, Gas and Water (MLGW) a contract to design and construct a meclidlm-Btu gasification plant converting 3158 tons of coal into 175 MMSCFD of 300 Btu/CF fuel gas. IG'l's U- Gas Gasifier will be used to produce fuel gas for industrial customers in Shelby County, Tennessee. Foster Wheeler Energy Corporation was chosen to provide architect, engineering, and construction management for the project. Delta Refining Company will provide operation experience in the proposed plant. Kentucky No. 9 coal is the proposethfeedstoek. Phase I (Preliminary Engineering and Design) was submitted to DOE on December 1, 1979 for evaluation, and a contract to proceed into Phase II was signed in May 1980. During Phase II Memphis Light, Gas and Water continued as prime contractor. Foster Wheeler Energy Corporation provided the final design work. Tech nAcal support provided by IGT included pilot operations at its Chicago Energy Development Center where the U-GAS Gasifier was developed. The final Environmental Impact Statement was issued in May 1981. On September 25, 1981, the DOE published a record of decision concerning the MLGW plant, announcing plans to terminate future funding support of the project. DOE will continue to provide available prior year funds to the project, with the provision that these funds will be utilized only for the final design and associated technical support pilot plant tests, and necessary vendor engineering. No site work or construction work is included. The project applied to the SPC for loan guarantees and was selected to advance to Phase II negotiations. The project was later moved to the SFC's second solicitation and then voluntarily moved to the third solicitation at the sponsors' request.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-101 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

As was suggested by the SFC, the utility (MLGW) requested private company participation in the project to allow investors to take advantage of tax credits (a municipal utility cannot take advantage of such credits). MAPCO,lnc. and Foster Wheeler Energy Corp. joined the project as equity sponsors in mid-982, but MAPCO later withdrew. MLGW and Foster Wheeler subsequently formed Mid-South Synfuels Inc. to oversee the project. DOE involvement in the orojeet will be terminated when the SFC acts on the loan guarantee and price support request. Project Cost: Phase 1 - $11.00 million (DOE) Phase II - $800 million MINING AND INDUSTRIAL FUEL GAS GROUP (MIPGA) GASIFIER - U.S.B.M. - Twin Cities Metallurgical Research Center; DOE; American Natural Service Company; Amerigas; Bechtel Incorporated; Black, Sivalls, Bryson; Burlington Northern; Cleveland-Cliffs Iron Company; Davy McKee Corporation; Dravo Corporation; The Hanna Mining Company; Inter-City Gas Corporation; Mansfield Carbon Products; Minnesota Department of Natural Resources; Peoples Natural Gas Company; Pickands Mather & Co.; Reserve Mining Company; Riley Stoker Corporation; Stone and Webster; U.S. Steel Corporation; Western Energy Company; Weyerhaeuser; Rocky Mountain Energy; and EPRI. The U.S. Bureau of Mines announced plans to install a 36 TPD Wellman-Galusha coal gasifier at the Twin Cities Metallurgical Research Laboratory (Minn.) in March 1977. The 6' 6" diameter gasifier, supplied by Hanna Mining Co., provides low-Btu fuel gas for a 12 TPD pilot grate-kiln taconite pellet induration furnace presently operating at the Center. The Bureau of Mines' goal is to determine whether iron ore pellet firing with raw, low-Btu coal gas is technically feasible and practical, while DOE is interested in gasifier operations and technology. First shake-down test of gasifier was undertaken on November 13, 1978. Four 120-hour tests were completed in November and December 1978 with Kentucky bituminous, Western subbituminous and North Dakota lignite coals. A 10-day test with a Montana subbituminous coal and North Dakota lignite was completed in September-October 1979. A test with "briquetted" subbituminous coal fines was started October 1979, but was aborted after 10 hours. Modifications to the gasifier facility were completed and testing began in October 1980. A 30 day continuous operation with North Dakota "Indian Head" lignite was completed in November 1980. The test used approximately 1000 tons of lignite, and included pellet testing. Ten day around-the-clock tests completed in mid-1981 included tests with North Dakota "Indian Head" lignite fines (3/4" x 1/4 11), Texas lignite, and Colorado subbituminous coal. "Simplex" Briquettes testing was performed in October 1981.

Two tests have been conducted following equipment modifications by BS&B. Testin g of Western Kentucky bituminous (Jetson) coal began on August 19, 1982. Continuation of these tests began on October 24, 1982. Project Cost: $2.5 million MINNEGASCO HIGH-BTU GAS FROM PEAT - DOE and Minnesota Gas Company A feasibility study has been conducted for an 80 million SCFD plant to produce substitute natural gas from peat in northern Minnesota. The study encompasses work in technical, socioeconomic, environmental, regulatory, and financial areas. A decision not to proceed to detailed design of the peat gasification plant has been made after completion of the study. The final report was completed August 30, 1982. Project Cost: $3.67 million for 19-month project starting October 1, 1980. MINNEGASCO PEAT GASIFICATION PROJECT - DOE, Gas Research Institute, Minnesota Gas Company, and Northern Natural Gas Company (Institute of Gas Technology, Subcontractor) Minnegasco began evaluation of peat gasification in conjunction with laboratory and PDU-scale gasification of peat. The work is being conducted at IGT for conversion of peat to SNG. Current work being conducted on the program includes PDU work on wet carbonization, gasification of Florida and Alaska peat, and gasification tests on peat after dewatering by various methods.

4-102 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

Peat gasification has advanced to pilot plant status at the modified HYGAS facility in Chicago. IGT is negotiating a take-over of the pilot plant from DOE when funding runs out in 1982. Project Cost: $1.2 million for 1976-1978 project Minnegasco recently awarded additions totaling $3.9 million, to the DOE contract to extend work until October 31, 1982. MOLTEN SALT PROCESS DEVELOPMENT - DOE and Rockwell International Rockwell has designed, built and operated a 1 TPH PDU to test a molten salt coal gasification process for low-Btu gas production. The gasifier is designed to operate at 1,800°F and 20 ATM. Reference feedstock is Illinois No. 6 coal. Sulfur and ash from coal are trapped by molten sodium carbonate. Melt is quenched and dissolved in water to allow ash removal by filtration. H95 is stripped from the solution, and dry sodium carbonate is produced for recycle by precipitating and calcining sodium bicarbonate crystals. The PDU is located at Rockwell International's field laboratory at Santa Susana, California. The Phase I program, covering the design, construction and initial operation of the PDU, was completed in June 1980. Four successful runs were made, varying in length from 112 to 385 hours. Gasifier pressures up to 10.5 ATM were tested. The process performed as predicted, producing clean, low-Btu gas from high-sulfur caking coal at feed rates up to 1500 lb/hr. A Phase U program was conducted aimed at completing the development of the low-Btu (airblown) Molten Salt Coal Gasification Process. All major operational objectives were met including gasification at the design feed rate (1 ton of coal per hour), design pressure (20 ATM), and design concentration of ash in the melt (20%). The Phase II work has been completed and the Final Report accepted by DOE. The molten salt gasifier has been mothballed. Project Cost: $12.6 million (Phase!) $4.4 million (Phase II) $17.0 million (Total) MOUNTAIN FUEL COAL GASIFICATION PROCESS - Mountain Fuel Resourges, Inc.; Ford, Bacon & Davis; Department of Energy The sponsors are constructing a process development unit for research and development on components of a high temperature, oxygen blown, entrained flow gasifier. The gasifier operates at slagging temperatures (about 2,800°F), and 300 psig. The heating value of the product gas is about 300 Btu/SCF. Both radiant and convective heat exchangers are used to recover heat from the process. Detailed engineering has been completed for the 30 TPD process development unit which will also be used to fire an existing brick kiln at Salt Lake City. A $6.0 million, 30-month contract has been awarded. DOE will fund 80% of the project costs. Mountain Fuel Resources, the primary contractor, and Ford, Bacon & Davis, the major subcontractor, will share the remaining 20% of the costs. Construction was completed in October and start-up tests started in November 1982. Project Cost: $6.0 million MURPHY HILL - (see North Alabama Coal Gasification) NASA LEWIS RESEARCH CENTER COAL-TO-GAS POLYGENERATION POWER PLANT - NASA Lewis Research Center Lewis Research Center conducted a feasibility study to assess the technical, environmental, and economic factors for a gasification combined cycle cogeneration power plant concept to be sited at the Lewis Research Center in Cleveland, Ohio. A six month conceptual design completed by Davy McKee Corporation in July 1980 verified technical and environmental benefits of the concept. The reference system selected for the conceptual design included two air-blown Westinghouse pressurized fluidized bed gasifiers using Eastern U.S. high sulfur coal, a Holmes-Stretford acid gas removal system, and a 20 MW combined cycle electric generation power plant utilizing an extraction steam turbine to provide up to 90,000 lb/hr of low pressure steam for heating. A capital cost of $58 million (1980 dollars) was estimated for the complete power plant which included site development, design services, construction management and contingencies for this first-of-a-kind plant. A final report, NASA TM-81687, has been completed and an independent environmental assessment has been prepared. The NASA Lewis Research Center has, in addition, completed a technical and economic evaluation of a coal-to-gas Polygeneration power plant for the NASA Kennedy Space Center in August 1981. This plant, based on the cogeneration plant designed for Lewis, would generate 14.5 MW electricity, 10 MW (thermal) for heating, and 10 TPD of liquid hydrogen for Space Shuttle operations. Economic assumption of 70/30 debt-equity ratio, 15% after tax return on investment, and 10 year accelerated cost recovery allows generation of electricity, steam and hydrogen at a cost 35% lower than estimated market prices in the first year of operation (1987). Cleveland Electric illuminating Company (CE!) has withdrawn from the project. This project is not being pursued further because fundin g for further considerations is not

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-103 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

available. (NOTE: This project has appeared in previous issues under the title "NASA Lewis Research Center Coal- to-Gas Cogeneration Power Plant".) Project Cost: $58 million NATIONAL COAL BOARD LIQUID SOLVENT EXTRACTION PROJECT - National Coal Board, British Department of Energy The British Department of Energy is co-sponsoring pilot plant evaluation of the Liquid Solvent Extraction Process developed in a small pilot plant capable of producing 0.2 TPD of liquids.. In the process, a hot, coal-derived solvent is mixed with coal. The solvent extract is filtered to remove ash and carbon residue, followed by hydrogenation to produce a syncrude boiling below 300°C as a precursor for transport fuels and chemical feedstocks. Economic studies, supported by Badger, Ltd. have confirmed that the process can produce maximum yields of gasoline and diesel very efficiently. Work on world-wide coals has shown that it will liquify economically most coals and lignite and can handle high ash feed stocks. Following failure to get sufficient support to proceed with a 25 ton per day

Project Cost: 32 million British pounds (1981 prices) construction cost plus 18 million British pounds (1981 prices) operating costs. NATIONAL COAL BOARD LOW BTU GASIFICATION PROJECT - National Coal Board, British Department of Energy The National Coal Board is developing a fluidized bed gasifier combined with fluidized bed combustor to, produce a low-Btu gas, primarily intended for firing a gas turbine for power generation, but also with applications in industry. Small pilot-plant studies leading to the design of a pilot/demonstration plant of a capacity of 5 ton/hour of coal are in hand. A joint study with the Central Electricity Generating Board led to recommendations to proceed but it is likely that work on this application will be limited to design studies over the next few years. Work is being concentrated by the NCB on developing the gasifier for the industrial market, where the system has been demonstrated at the 0.5 ton/hr scale. Project Cost: Feasibility study and associated experiments - 2 million British pounds Pilot plant program - 15 million British pounds NEW ENGLAND ENERGY PARK - EG&G, Brooklyn Union Gas Company, Eastern Gas and Fuel Associates, Westinghouse, and DOE A feasibility study has been completed for a New England Energy Park. EG&G received a $4 million feasibility study loan from the DOE. A 4,500 acre site near Fall River, MA is under contract with approximately 1,900 acres allocated for the development of the park. Approximately 5,000 TPD of coal will be transported from the eastern Appalachian area of northern West Virginia and Pennsylvania and gasified to a medium Btu gas which will, in turn, fire a 260 MW combined cycle power plant and be used to produce 1699 TPD of methanol or 50 MM scfd of methane. EG&G requested a loan guarantee of approximately $2 billion and price supports from the SFC. Project sponsors reapplied for a loan guarantee under the SFC's second solicitation ending June 1, 1982. The project passed the SFC's project strength and maturity tests and was advanced into Phase II negotiations for financial assistance. The Westinghouse gasification process has been selected. Discussions with potential equity partners and product purchasers are continuing. Brooklyn Union Gas Company, Eastern Gas and Fuel Associates, and Westinghouse Electric Corporation have joined EG&G as participants in the project. An environmental program is nearly complete to ascertain siting feasibility and provide the environmental baseline data required to support permitting requirements. Potential coal suppliers have expressed willingness to supply the needed coal, and the coal transportation scheme has been developed. Bechtel is providing the technical support for the project and Lehman Brothers Kuhn Loeb, Inc., is providing investment banking services. Plant Cost: $1.3 billion in 1981 dollars.billion depending on inflation assumptions. NEW MEXICO LURGI COAL-TO-GAS/METHANOL PLANT - Texas Eastern Corp. and Utah International, Inc. In January 1980, Texas Eastern and Utah International announced a joint feasibility study toward the construction of a coal-based synthetic fuels plant in northwest New Mexico. The plant would utilize the Lurgi gasification process to produce a synthesis gas which would then be converted to liquids, such as methanol, using other commercially available processes. In July 1980, the project was selected by DOE for feasibility study funding under the synthetic fuels commercialization program. Negotiations with the DOE were concluded in July 1981 and $3.1 million was provided for a feasibility study to determine the project's technical, economic and environmental viability. It is estimated that the feasibility study will be completed in September 1982. The study will include preliminary plant design, construction schedules, capital and operating cost estimates, evaluation of plant site alternatives, further

4-104 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNPUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

studies on the characteristics of local coals, evaluation of product transportation alternatives and environmental and socioeconomic impact studies. Project Cost: Studies to provide cost basis by September 1982. NICES PROJECT - Northwest Pipeline Corporation Northwest requested loan guarantees from the SFC for a coal gasification project located near Boardman, Oregon. However, the project was not selected by the SFC for further consideration. The plant would produce the equivalent of 250 million cubic feet per day of high Btu gas in the form of high Btu pipeline quality gas, medium Btu gas, and methanol. The medium Btu gas would be consumed in nearby combined cycle electrical power generating plants. Coal for the gasification plant would be transported from the Powder River Basin in northeastern Wyoming by a coal slurry pipeline designed to move from 25 to 35 million tons of coal annually. The slurry pipeline would also supply coal to the electric utility industry, industrial customers, and to overseas markets. Project Cost: Undetermined NORTH ALABAMA COAL GASIFICATION CONSORTIUM PROJECT - North Alabama Coal Gasification Consortium (Santa Fe International; Air Products and Chemical Co.; Kidder, Peabody & Co.; Raymond International Inc., Peabody Coal Company, and Houston Natural Gas); in conjunction with the Tennessee Valley Authority In October 1979, the Tennessee Valley Authority (TVA) requested proposals for Phase I, the conceptual design of a coal gasification plant capable of processing up to 20,000 tons of coal feedstock per day. Initially, the project intended to serve existing north Alabama with medium-Btu gas via pipeline, but now the consortium plans to produce methanol for use in the motor fuel and chemical markets. Initially the methanol will be blended with gasoline to improve its octane and extend its use. Eventually, neat (pure) methanol will be substituted for gasoline in vehicles designed to use it. The Project will use the Koppers-Totzek (K-T) technology licensed by GKT Gesellschaft for Kohle-Technologie (GET) together with required gas cleanup, shift, compression, and methanol synthesis equipment to process approximately 5,000 tons per day of Eastern bituminous coal into about one million gallons of methanol per thy. When justified by market conditions, the facility could be expanded by installing additional capacity. Site preparation began in the fall of 1981 and completion of the plant is scheduled in 1986. Bechtel National, Inc., C.F. Braun Co., and Foster Wheeler Energy Corporation were awarded a total of $2.7 million for conceptual design studies incorporating five different coal gasification processes for obtaining the medium Stu-gas. The five processes were: Texaco, Koppers-Totzek, Lurgi, the British Gas Corporation's Slagging Lurgi, and Babcock and Wilcox. Each contractor evaluated at least three of the five processes for a total of eleven conceptual designs. Ultimately C. F. Braun was chosen to do the detailed engineering. On June 22, 1982, Kaiser Engineering was chosen as construction manager. TVA has completed its the site preparation work at the Murphy Hill site in northern Alabama. The Draft Environmental Impact Statement (EIS) for the project was released on August 1, 1980. It was prepared in parallel with the conceptual design effort. A supplement to the draft was issued on June 1, 1981, primarily to provide information concerning proposed methods of financing the projects. The final EIS was issued in July 1981. A portion of the Congressional appropriations for the project were rescinded in March of 1981 to the current level of $125 million and the project was restructured. The North Alabama Coal Gasification Consortium is being formed to continue the project under private financing arrangements. The consortium will consist of several private firms, which will own and operate the plant on a commercial basis. To date Santa Fe International; Air Products and Chemicals, Inc.; Kidder, Peabody, & Co.; Raymond International; Peabody Coal Company; and Houston Natural Gas have agreed to join the consortium. TVA, under contractual arrangements with the consortium, will sell the Government's interest in the project to the consortium. The consortium will assume legal ownership of the plant, all obligations for completing and operating the facility, and the project. TVA will make available to the consortium the project site and TVA's project management, engineering design, construction, coal procurement, purchasing, and environmental analyses capability. TVA could also assume the role of project manager during the design, permitting, and construction of the plant at the request of the private consortium. TVA will spend $125 million in appropriated money to get the project started and then transfer the project to the consortium with full payment for work and the site. Kidder, Peabody, & Co., Incorporated as financial agent submitted an application for financial assistance from the United States Synthetic Fuels Corporation for the Consortium on March 31, 1981. On Janaury 4, 1982, the consortium submitted a supplemental application based on project maturity. The SFC chose the project for Phase I consideration for financial assistance on January 18, 1982. However, the project did not pass into the SFC's Phase

SYNTHETIC FUELS REPORT. DECEMBER 1982 4-105 STATUS OF SYNPUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

II, which required that the project pass the SFC's strength criteria. The project sponsors reapplied to the Sit for loan and price guarantees under the second solicitation ending June 1, 1982. The project then passed the strength tests and was advanced into Phase II negotiations for financial assistance. As of December 1981, negotiations were still underway with the SFC. Project Cost: Approximately $1 billion NORTH DAKOTA SYNTHETIC FUELS PROJECT - DOE, lnterNorth is serving as the lead company in an 11-member consortium, (Baukol-Noonan Coal Co., Cooperative Power Association, Froedtert Malt Corp., Minnesota Gas Co., Minnkota Power Cooperative, Montana-Dakota Utilities, Northern States Power Co., Northwestern Public Service, Northwestern Wisconsin Electric Co., and Ottertail Power Company) The North Dakota Synthetic Fuels Group was selected by DOE for a second round grant for a feasibility study. The plant would process North Dakota lignite to produce methanol and SNG. The mine-mouth complex in Oliver County, N.D. would use Lurgi technology to produce 125 billion Btu/D of synthetic fuel from lignite reserves controlled by Baukol-Noonan. The loss of the second-round grant has reduced the funds available for the feasibility study and has extended the timing of the study. Cost: Unavailable OTT HYDROGENERATION PROCESS PROJECT - Coal Fuel Conversion Company, Timberline Fuels, Inc. Sponsors have submitted an application to the Synthetic Fuels Corporation (SFC) for a purchase agreement for a 1000 BPD facility using the Ott Hydrogeneration coal liquefaction process (closed system). However, the project was not selected by the SFC to proceed to Phase I! negotiations. The facility would be located at the mine mouth at Choose Canyon Ranch in Las Animas County, Colorado. Project Cost: Undetermined PEAT METHANOL ASSOCIATES PROJECT - Peat Methanol Associates, (Hoppers Co., Inc., Energy Transition Corp., Jack B. Sutherland) PMA submitted this project, also referred to as the First Colony Project, to the SFC for loan and price guarantees. The plant is a single module KBW gasification train with ICI methanol synthesis which will produce 645 TPD of fuel grade methanol from peat. The plant to be located near Creswell, N.C., can be expanded to 5000 TPD. Commercial production is expected by the 1st quarter of 1986. On March 26, 1982, the United States Synthetic Fuels Corporation announced that this project met the Corporation's project strength criteria and was advanced to Phase II evaluation in the initial solicitation for synthetic fuels projects. Subsequently, the project was moved to Phase II of the SFC's second solicitation on June 18, 1982. In Phase II, projects were subjected to independent verification of the data submitted and discussions were will be held with project sponsors over the amount and kinds of financial assistance. On December 1, 1982, the SFC annni,nrM that neuntiatinns had nrnrnessed to the noint that it intended to si gn a letter of intent with the project

Project Cost: $325 million (first module) PHILADELPHIA GAS WORKS SYNTHESIS GAS PLANT - DOE, Philadelphia Gas Works, United Engineers & Constructors, Inc. Philadelphia Gas Works (PGW) was selected for a DOE award for a feasibility study for a $200 million medium Btu coal gasification plant., The study, conducted by Gilbert Associates, Inc., indicated that long-term purchase agreements and SFC incentives are necessary for the project to be economically viable. Philadelphia Gas Works applied to the Synthetic Fuels Corporation (SFC) for a loan guarantee and a price guarantee under the SFC's second solicitation ending June 1, 1982. However, the project did not pass the SFC's project strength test. The first facility of a potential series of modular plants would be built in northeast Philadelphia on a 32-acre site and would start operation in 1986. The plant would use Kopper-Totzek gasifiers to produce 20 billion Btu per day of medium Btu gas (300 Btu/scf) from 1100 tons per day of Eastern bituminous coal. This gas would then be distributed to Philadelphia industries.

Project Cost: $250 million Study: $1.2 million

4-106 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

PHILLIPS COAL GASIFICATION PROJECT - Phillips Coal Co. Phillips Coal Co. is conducting environmental studies, permitting activities and economic and technological feasibility analyses for a 50,000 barrels oil equivalent per day coal gasification plant. The EPA has issued a Notice of Intent to Prepare an Environmental Impact Statement for the project to be located in Hopkins, Woods and Rains counties near Sulphur Springs, Texas. Seventeen million tons per year of lignite would be mined for thirty years from some 50,000 surface acres. Total Cost: $4 billion

PURGED CARBONS PROJECT —Integrated Carbons Corporation Integrated Carbons Corporation requested a loan guarantee from the U.S. Synthetic Fuels Corporation (SFC) under the SFC's second solicitation. However, on June 18, 1982, the SFC announced that the project had been dropped from further consideration on the grounds that it was clearly not mature. The proposed project, to be located at an unspecified mine site, would produce 100,000 tons per year of de-ashed solids that could be used for several types of alternative fuels. Project Cost: Undetermined

SAN ARDO COGENERATION PROJECT - Pacific Gas & Electric Co., Texaco Inc. PG&E and Texaco have been investigating the possibility of using fuels other than heavy oils to generate steam for heavy oil recovery at the San Ardo, California heavy oil field. The present thinking is that a cogeneration project fueled by natural gas is a more suitable approach than coal gasification for this field. A natural gas cogeneration project appears to be more economic because the gas is available and the project could be brought into use more quickly than a coal gasification plant. Thus, the sponsors are evaluating this approach and are proceeding with making the necessary applications to appropriate authorities to avoid possible delays in start-up. The coal gasification related effort has been concluded.

Project Cost: $585 million (1980$) approximate SASOL TWO AND SASOL THREE - Sasol Limited Sasol Two and Three are a commercial project, based on the success of Sasol One, for the manufacture of mainly !lsid fuels, tar products, ammonia, and sulfur. The plants are situated on the eastern high veld of Transvaal. Estimated coal (low grade) consumption will a Collieries. The facilities include boiler house, reactors, gas reformers, and refineries. The uses oasors bymnoi process. contractor was Fluor Engineers. Construction of

Project Cost: SASOL Two $3.0 Billion SASOL Three $3.8 Billion SESCO PROJECT - Solid Energy Systems Corporation SESCO has proposed a project to the U.S. Syhthetic Fuels Corporation (SFC) under both the first and second solicitations. However, the project was dropped from further consideration on the grounds that it was not mature. The project would produce calcium carbide from coal and limestone. This calcium carbide would then be subsequently converted to acetylene. The proposed facility would produce 220,000 tons of calcium carbide per year. Project Cost: Not available

SHELL COAL GASIFICATION PROCESS - Shell Oil Co. Shell.is developing a pressurized entrained bed, coal gasification process. A six TPD pilot plant has been in operation at Shell's Amsterdam laboratory since December 1976. A number of different coals and petroleum cokes have been successfully gasified at 300-600 PSI pressure. This pilot plant has now operated for over 6000 hours. A 150 TPD prototype plant has been constructed at the German Shell HamburgfHarburg refinery. Since the start-up in November 1978, some 2000 'Iours of operation have been logged. The longest run so far lasted for over 250 hours. The carbon conversion was over 99 percent and a synthesis gas was produced containing, before treating, less than 1.5 percent vol. CO and 0.1 percent vol. CR4.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-107 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1992) COAL CONVERSION PROJECTS (Cont.)

A 1000 tons of coal per day commercial demonstration plant constitutes the next phase in the development program, and its location and timing are under active study. Project Cost: Estimated at $150 million (excluding powerplant) SLAGGING GASIFIER DEVELOPMENT - (See Gasification Environmental Studies) SLAGGING GASIFIER PROJECT - British Gas Corporation, The British Gas Corporation (BGC) constructed a prototype high pressure slagging fixed bed gasifier in 1974 at Westfield, Scotland. (This gasifier has a throughput of 350 TPD). The plant has been successfully operated since that date on a wide range of British and American coals, including strongly caking and highly swelling coals. The ability to use a considerable proportion of fine coal in the feed to the top of the gasifier has been demonstrated as well as the injection of further quantities of fine coal through the tuyeres into the base of the gasifier. By-product hydrocarbon oils and tars can be recycled and gasified to extinction. The coal is gasified in steam and oxygen. The slag produced is removed from the gasifier in the form of granular frit. Gasification is substantially complete with a high thermal efficiency. A long term proving run on the gasifier has been carried out successfully. BCG is constructing an 8 foot nominal diameter gasifier which will gasify 600-800 TPD, to make SNG. BCG is prepared to grant licenses for plants utilizing Slagging Gasifiers of sizes up to 8 feet diameter and will provide fun commercial guarantees. Project Cost: Not available SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-1) - DOE, International Coal Refining Company (Air Products and Chemicals lnc./Wheelabrator-Frye Inc., partnership), and Commonwealth of Kentucky An SRC pilot plant is operating on the site of Southern Electric Generating Co.'s E.C. Gaston Steam Plant near Wilsonville, Alabama. It was designed, built, and is operated by Catalytic, Inc. The process dissolves coal under pressure in the presence of hydrogen. The products are clean solid and liquid fuels with heating values of approximately 16,000 Btu per pound. The sulfur content is reduced to a maximum of 0.8 percent. Plant capacity is 6 TPD. Data from the Wilsonville, and Ft. Lewis, Washington, SRC plants have been correlated, and eleven coals tested. The conceptual design of a 6000 TPD SRC-I demonstration plant was completed July 31, 1979 and submitted to DOE. To carry out the project, Air Products and Wheelabrator-Frye have established the International Coal Refining Company (ICRC). Under terms of a cost sharing agreement, ICRC will invest $90 million in the project, the Commonweath of Kentucky will invest $30 million and the Department of Energy will fund the balance. A site for the demonstration plant at Newman, Kentucky is under option. Products include clean solids and liquids. SEC fuel in the 850°F and lighter fractions will be used to displace No. 6 fuel oil. SRC liquids include heavy oil (650°-850°F fraction oils), a 400 0-600°F middle distillate that can replace No. 2 fuel oil, and naphtha (C5-400°F fraction oils) for reformer feed fdr high-octane, unleaded gasoline blendstock or BTX chemicals. The Final Environmental Impact Statement was released in July 1981. The project baseline was transmitted to Congress in May 1982. The revised cost estimate specified in the report indicates project costs to be $2.9 billion (escalated for inflation). Although previous cost estimates were approximately $2.0 billion, the project revenues are expected to exceed expenditures by $200 million in the first 2 1/2 years of operation. Plant startup is expected in December 1987. Consolidated Edison, Commonwealth Electric, Alcoa, Owens-4llinos, and Florida Power and Light have agreed to purchase SRC-1 fuels for testing in boilers and process units originally designed for oil based use. Estimated Project Cost:• $2.9 billion (Demonstration Plant Only) TENNECO SNG FROM COAL - Tenneco, Inc. Tenneco, through subsidiary companies Intake Water Co. and Tenneco Coal Co., is acquiring and developing resources necessary as feedstocks for a coal gasification plant on the state-line new Wibaux, Montana, and Beach, North Dakota. Intake holds water rights to 80,650 AFY from the Yellowstone River with plans for a diversion works, aqueduct and off-stream storage system to serve Dawson and Wibaux Counties, Montana, and Golden Valley County, North Dakota. Environmental baseline data gathering studies have been underway in connection with this project since 1974. Intake conducted geotechnical investigations at three potential damsites for the off-stream storage reservoir and is preparing an Environmental Impact Statement for one of these sites. Tenneco is conducting an ambient air quality and weather monitoring program in the state-line area. The data is to be used in computer modeling studies addressing potential impacts on regional EPA Class I areas. Tenneco Coal Gasification Co., a

4-108 SYNTHETIC FUELS REPORT, DECEMBER 198 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

subsidiary of Tenneco, Inc., tiled its first annual Long-Range Plan under the Montana Major Facility Siting Act in April 1980 for a 280 MMSCF per day coal gasification plant to produce pipeline quality gas using Lurgi coal gasification technology. The schedule calls for first gas production by 1990. On March 31, 1981 the Company submitted an application for a loan guarantee for the project to the U.S. Synthetic Fuels Corporation. However, the company has not yet responded to the more recent solicitations by the SEC. Tenneco tiled its third annual Long-Range Plan in April 1982. A decision whether to proceed with the project will be made based in part on the successful operation of the Great Plains Gasification Project in which Tenneco is a 30% participant. The exact site of the facility is dependent on the outcome of litigation over water supply. Intake owns sufficient water rights from the Yellowstone River, but movement to the Wibaux site constitutes an interbasin transfer of water which is forbidden by Article X of the Yellowstone River Compact. Project Cost: $2.8 billion in 1982 dollars. TENNESSEE SYNFUELS ASSOCIATES MOBIL-M PLANT - Hoppers Co., Inc. The DOE selected the Tennessee Synfuels Associates project under the interim program established by the Energy Security Act for loan guarantees negotiations for a $700 million plant to produce gasoline from coal. Ultimately, DOE dropped the project from consideration under the Defense Production Act. The project sponsors (then Cities Service and Hoppers) applied to the SFC for loan and price guarantees. However, Cities Service withdrew from the project in February 1982. On March 26, 1982, the SFC announced that the project had not been selected to advance to Phase II negotiations. Hoppers reapplied for loan and price guarantees under the SFC's second solicitation ending June 1, 1982. However, the sponsors requested to have the project voluntarily moved to the SFC's third solicitation. TSA plans to construct the facility in five modules, each capable of producing approximately 10,000 bpd of liquid products. The plant would use 1{BW gasification, ICI methanol synthesis, and the Mobil-M process to convert 10 million tpy of coal to gasoline. DOE is preparing an EIS to assess the transfer of a 1500-acre tract from the DOE Oak Ridge Reservation to the city of Oak Ridge, Tennessee. The city intends to resell the property to TSA to use as the site of the project. Cost: $1.2 billion TEXACO COAL GASIFICATION PROCESS DEVELOPMENT - Texaco Inc. The Texaco Coal Gasification Process has been operating for several years at Texaco's Montebello Research Laboratory in California. The facility has two pilot gasifiers each capable of processing 15-20 TPD of coal. The process has been used on a wide variety of coals and, since the 1973 Arab oil embargo, the development of the Texaco Coal Gasification process has been greatly accelerated. Operation at pressures ranging from 300 to 1.200 psi have been tested. These pilot units, along with the associated coal grinding and slurry preparation equipment, provide design information for a number of commercial projects that are underway. A 165 tons coal per day demonstration plant has been in operation since early 1978 in Oberhausen-Holten, West Germany. The plant which is jointly funded by Texaco Inc., Ruhrchemie AG, Ruhrkohle AG and the Government of the Federal Republic of Germany, has been run on typical coals from the Ruhr region of Germany. The product gas is used as a feedstock to a variety of chemical synthesis processes. Several test runs lasting up to 30 days have successfully demonstrated continuous operation of the process. Operation at pressures between 300 to 600 psi has been completed. The system is complete with a waste heat boiler consisting of a radiant and a convection section. A process optimization program is presently underway. The program includes evaluation of alternate equipment components, of alternate heat recovery concepts, and gasifying of a wider range of coals. The total program is planned to provide information for the design, with ever increasing confidence, of large scale coal gasification plants using the Texaco process. The Texaco Coal Gasification Process has also been licensed for use in a plant of a confidential U.S. chemical company process to gasify coal to produce fuel gas for electric power generation. In addition, over one-half of the coal gasification proposals submitted to the U.S. Synfuels Corp. on March 31, 1981, specified use of the Texaco Coal Gasification Process in production of medium Btu gas, methanol, gasoline, hydrogen, and electric power. Other projects that propose using the Texaco Coal Gasification Process are described separately under the following headings: Cool Water Coal Gasification Project, Medium Btu Gasification Project, Central Maine Power Company's Sears Island Project, TVA Ammonia From Coal Project, Chemicals From Coal Project, Grace Coal-to-Methanol-to- Gasoline Plant, Lake DeSmet SNG From Coal Project, and San Ardo Cogeneration Project. Project Cost: West German Demonstration Plant Program: $50 million

SYNTHETIC FUELS REPORT. DECEMBER 1982 4-109 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

TOSCOAL PROCESS DEVELOPMENT - TOSCO Corp. TOSCO has under development an atmospheric, low-temperature (800-970°F) coal pyrolysis system, named the TOSCOAL Process, at their 25 TPD pilot plant facilities, located near Golden, CO. The TOSCOAL Process is an adaptation of the TOSCO II oil shale retorting process to coal carbonization. The process products are dry char, intermediate-to high-Btu gas, and oil. Coals tested in the pilot plant to date are Wyodak subbiturninous, Illinois No. 6 bituminous, and Utah bituminous coal. Status - Development is continuing with an active pilot plant program. Project Cost: Undetermined TRANSCO COAL GAS PLANT - Transco Energy Company, DOE Transco submitted an application to the SFC for a medium Stu gasification project. However, the project did not pass the SFC's project maturity test. Located near Franklin, Robertson County, Texas, the project would convert 16,500 TPD of lignite to medium-Stu gas using Lurgi high pressure gasification process and transport the gas via a dedicated pipeline to Houston Lighting & Power Company's (HL&P) P.H. Robinson Plant in Galveston County, Texas. The DOE-eofunded feasibility study has been completed. The study concludes that the plant's process, ancillary, and other components are all commercially proven systems. Additionally, the study concludes, "To bring this project to fruition Transco would have to arrive at a pricing mechanism with long-term benefits to the customer, a satisfactory rate of return to the equity owners by finding a method of raising the debt capital on a project secured basis, and demonstrating with reasonable certainty that the economic projections can be achieved or improved." Project Cost: $1.5 billion TRI-STATE PROJECT - Texas Eastern Corporation and Texas Gas Transmission Corporation, Kentucky Department of Energy In July 1980, the project was selected by the DOE for Cooperative Agreement funding under the synthetic fuels commercialization program. Under the Agreement signed in February 1981, DOE was to provide a total of $22.4 million of an estimated $40.9 million, with the remainder financed by Tri-State. The Kentucky Department of Energy was to also provide assistance for the project. The agreement authorized commencement of a project work program which included site-specific environmental, health, safety and socio-economic impact studies; capital and operating cost estimates; developing a financing plan; engineering studies to determine optimum plant size, a complete process design, and product slate; and negotiation of contracts for coal, and other resource requirements and for product sales. Separate from the DOE program, 22,000 tons of Peabody Coal's Camp No. 1 coal, Kentucky No. 9 seam, was tested at a SASOL plant in South Africa in August, September and November 1981. The test was paid for by the KDOE separate from the U.S. DOE Cooperative Agreement. Construction was to begin in 1984, providing jobs for up to 7,500 workers as well as contract work for local shops and businesses. About 1,200 employees would be required to operate the plant. The project originally proposed a Lurgi gasification/Fischer-Tropsch liquefaction process in a 28,000 ton per day coal conversion plant. A wide product slate including gasoline, SNG, diesel fuel, sulfur and some chemicals was planned. In January 1982 the partnership proposed to the DOE changes in its cooperative agreement work program to incorporate design modification and a revised schedule for the project. The changes would include a product slate that would combine Lurgi gasification with methanol-to-gasoline conversion and also produce some LP gas and small quantities of chemicals. Under the revised plan the plant would be substantially smaller with the exact capacity to be determined. Tri-State decided in April 1982 to postpone project activities and to terminate their cooperative agreement with U.S. DOE. The sponsors will continue to update the project, but at a much lower level of effort. Projected Cost: not determined, but approximately $3.5 billion TRW COAL GASIFICATION PROCESS - TRW, Inc. TRW is developing a slagging, entrained bed gasification process which is based upon proprietary slagging gasification and heat exchanger concepts. The gasifier technology is derived, in part, from advanced developments in TRW rocket engine and MHD programs. A 6 atmosphere pressure, 2-ton per hour version of this gasifer has been constructed and is being tested during 1982. Project Cost: Undetermined

4-110 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

TVA AMMONIA FROM COAL PROJECT - Tennessee Valley Authority The TVA is conducting an ammonia-from-coal project at its National Fertilizer Development Center, located at Muscle Shoals, Alabama. A Texaco Partial Oxidation Process coal gasifier is being retrofitted to an existing 225 TPD ammonia plant. Plant construction was completed in mid-1980. A three-year period of demonstration is planned. Capital costs will total $43.2 million. Brown and Root, of Houston held the $25.6 million contract for the construction of the eight ton per hour coal gasifier. The air separation plant was built by Air Products and Chemicals, Inc. at a cost of $s million. The remainder of the work was to be done by TVA. The coal gasifier will provide 60 percent of the gas feed to the existing ammonia plant. The existing plant retains the option of operating 100 percent on natural gas, if desired. The initial feed to the coal gasifier will be Illinois No. 6 seam coal. - The gasifier was dedicated and started up at the TVA's 13th Demonstration of Fertilizer Technology conference in October 1980. However, actual production of feed gas for ammonia manufacturer had not taken place because of mechanical problems. The plant was restarted in April 1982, and operation continued into May during which time the plant was operated a total of 335 hours, including one 4-day run and one 5-day run at full capacity and pressure (500 psi). The plant was then shut down for modifications to downstream equipment in preparation for resumption of operations. The gasification facility began providing synthesis gas to the ammonia plant in mid-November, 1982. Project Cost: $60 million total TWO-STAGE ENTRAINED GASIFICATION SYSTEM - DOE, Electric Power Research Institute, and Combustion Engineering, Inc. C-E's gasification process is a two-stage, atmospheric pressure,"air-blown, entrained-bed system designed to produce a low-Btu gas from coal in an environmentally acceptable manner. A S TPH Process Development Unit (PDU) has been in operation at C-E's Power Systems facility in Windsor, Connecticut. The two-stage gasifier consists of a "combustor" section in which coal and char are burned under slagging conditions, and a "reductor", where the balance of the coal is reacted. A product gas with a heating value of 80-100 Btu/scf is produced. The combustor operates at 3000° F and the reductor outlet temperature is t1800°F. Combustion Engineering was awarded a separate contract for the preliminary design of a demonstration plant. This effort studied retrofit of Gulf States Utilities Nelson #3 150 MW gas-fired unit located at West Lake, Louisiana and has shown that the boiler could achieve full load by integrating the low Btu gas and steam into the boiler cycle. Process Development Unit - Present Status Combustion Engineering's PDU has logged over 5000 hours of operation utilizing coal of which approximately. 3750 hours were in the gnsmaking mode. During this period of operation, approximately 2.7 billion cubic feet of low-Btu gas was produced, a continuous run of two weeks was achieved, and the gasification process was verified to the Department of Energy's satisfaction. The total hours of operation approaches 10,000 hours representing 40% of the maximum available hours. Partial funding for the project has been furnished by DOE; C-E has also contributed financial support. The present Administration's policy concerning DOE's function precludes any further support from them and the PDU has been deactivated. At present, alternate plans for the PDU are being evaluated while other gasification activities are proceeding. Demonstration Unit - Present Status In September of 1980, DOE awarded a contract to C-E for the first phase of a three-phase, six-year project of a commercial size demonstration unit incorporating the C-E gasification process. The overall project would, upon completion, include the design, construction and operation of a 150 MW gasifier retrofitted to an existing natural gas fired boiler at Gulf States Utilities' Nelson Station. The first phase includes the preliminary design and cost estimates. Agreement has been reached with DOE to reduce the scope of the work in the initial phase and it will be completed at an earlier date than originally planned. C-E has not been released by DOE to proceed with the next two phases. Project Cost: Not available TWO-STAGE LIQUEFACTION - (See Integrated Two-Stage Liquefaction)

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-111 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

UNION CARBIDE COAL CONVERSION PROJECT - DOE, Union Carbide/Linde Division In the first round of PL 96-126 solicitations, DOE awarded Union Carbide approximately $4 million for a feasibility study for the production of low/medium Btu gas. Each module of the plant which would be located in the Houston area would be for 125 billion Btu's per day of gas. The feasibility study is expected to be completed in December 1982. Project Cost: $3,945,676 (study) UNIVERSITY OF MINNESOTA LOW-BTU GASIFIER FOR COMMERCIAL USE - DOE, University of Minnesota In February 1977, DOE awarded a five-year cost-sharing contract to the University of Minnesota for design, construction, and operation of a 72 TPD Foster Wheeler Stoic gasifier to be located at Duluth, Minnesota. Foster Wheeler provided the engineering services. The two-stage gasifier utilizes technology licensed by Foster Wheeler from Stoic Combustion Ltd. of Johannesburg, South Africa. The 180-Btu/SCF gas is used to fire a boiler for heating/cooling of campus buildings. The process produces fuel oil as a co-product which will be used as boiler fuel during gasifier maintenance. The Stoic gasifier was started initially in October 1978. Altogether five different western subbituminous coals have been fed to the Duluth unit. The heavy coal oil recovered by means of electrostatic precipitation has been stored and fired successfully in the University's boilers. The gasifier is now fully operational, and on an extended run providing fully the fuel needs for the campus heating plant. Project Cost: $5.5 million (50/50 DOE/participant funding) WESTINGHOUSE ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERATION —DOE/GRI, Westinghouse Electric Corporation Since 1975, Westinghouse has operated a coal gasification pilot plant at Waltz Mill, Pennsylvania. The pilot plant utilizes a single stage fluidized bed ffasifier with dry ash agglomeration and fines recycle. The gasifier has operated at temperatures of 1550°F to 1990 F and pressures between 130 psig and 230 psig. Tests have been performed with air feed to the gasifier to produce low-Btu gas and oxygen feed to produce medium-Stu gas. Pilot plant coal capacity varies from 15 TPD with air feed, up to 35 TPD with oxygen feed. A wide range of coals have been successfully processed, from Texas lignite and Wyoming Sub-C subbituminous to highly caking Pittsburgh seam coal. The pilot plant has recently been integrated with Waltz Mill Test and Development Center, to provide the capability for combustion testing using coal gas as fuel. In addition, tests are currently planned for evaluation of particulate removal and heat recovery systems. A commercial size, 3 meter diameter cold flow fluidized bed scaleup facility has been constructed and began operation in 1981. The purpose of these facilities is to develop a sufficient data base to minimize the technical risks to acceptable levels associated with scaling up to demonstration and commercial size gasification plants. Several demonstration and commercial projects are currently in the feasibility study or design stages for application of the Westinghouse coal gasification system to various industrial and utility applications, including industrial fuel gas, combined cycle power generation and methanol production. These include: the Keystone project, Gulf States Utilities project, and the Fiat/Ansaldo projects. Westinghouse has completed an agreement with Sasol to demonstrate the Westinghouse gasification process at the Secunda complex. A 12 to 15 foot diameter gasifier, 80 to 100 feet high is planned with construction to be completed in 1985. Project Cost: $50 million WHITETHORNE COAL GASIFICATION PROJECT - United Coal Company and Virginia Fuel Conversion Authority A consortium of companies originally composed of Hercules, Inc., Norfolk and Western Railway Company, and the United Coal Company submitted an application for loan and price guarantee to the SFC for a coal-to-methanol-to- gasoline project. Hercules and Norfolk and Western Railway Company subsequently withdrew from the project. Located near Longshop and McCoy in Virginia, the project will use the Texaco coal gasification process to gasify 10,000 TPD of coal. Lurgi Methanol synthesis and the Mobil-M conversion would be used. United Coal is also evaluating other process options including selling the methanol as a chemical feedstock or using the methanol to slurry coal for pipeline transportation. The project is scheduled to start operation in mid-1988 producing 23,000 BPD of gasoline. United Coal is negotiating with several companies to become partners in the project. Project Cost: $1.5 billion WYOMING COAL CONVERSION PROJECT - WyCoalGas, Inc. (a Panhandle Eastern Company) A 150 billion Stu per sd capacity commercial pipeline gas project using Lurgi and Texaco coal gasification followed by methanation was being developed, and an expansion to 300 billion Btu per sd capacity was proposed. The plant would have been 16 miles northeast of Douglas, Wyoming. Rochelle Coal Company, a partnership of subsidiaries of

4-112 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) COAL CONVERSION PROJECTS (Cont.)

Peabody Coal Co. and Panhandle Eastern, had dedicated a Campbell County coal supply of over 500 MM tons of coal that was to be delivered to the plant by railroad. The state issued a 1974 appropriation of water from the North Platte and a permit to construct a 26,000 AF reservoir. Panhandle has rehabilitated the dam on another 26,000 A? reservoir and is entitled to one quarter of the volume and water rights. A water-well-based supply would have backed up these systems. WyCoalGas entered into a cooperative agreement with DOE on October 31, 1980 for partial Federal funding of the work—process engineering, coal tests, environmental and socio-economic investigations, permit applications, etc.—needed before a construction phase could start. An application for financial assistance in the form of a loan guarantee and contingent price supports was filed with the U.S. Synthetic Fuels Corporation on March 31, 1981. Development was substantially reduced because Ruhrgas Carbon Conversion Inc., and Pacific Gas and Electric Company ended their support in late August 1981 after negotiations about forming a partnership were ended by mutual agreement. These sponsors concluded investment could no longer be justified because of the delay in the SFC becoming operational, and the consequent uncertainty about its policies on synthetic gas projects. Immediately before the announcements by the SFC on March 26, 1982, of their selection of projects progressing to Phase II negotiation, Panhandle Eastern announced they were terminating the project. Reasons cited by the company included escalating project costs, high interest rates, and the global oil glut. Contractors were Bechtel, Lurgi, SASOL, Woodward-Clyde, Mountain West, and others. Project Cost: Total Estimated Capital Required $3.5 billion, Stage I, escalated to 1986 UNDERGROUND COAL CONVERSION PROJECTS UNDERGROUND COAL GASIFICATION - World Energy, Inc. On August 31, 1981, Extractive Fuels executed a 50-50 joint venture agreement with World Energy, Inc. of Laramie, Wyoming. Extractive Fuels agreed to put approximately 26,000 acres of its coal property located in the Southern Powder River basin into the joint venture and World Energy, Inc. has committed the use of their licenses and patents, and technical application ability in the in situ coal gasification technology for the express purpose of developing and building the first commercial in-situ gasification synfuels plant. The companies have further agreed to share the organizational cost on an equal basis. A New York investment banking firm has made various commitments to the joint venture to assist in the funding for the eomtnercial facility subject to the economic feasibility studies underway at this time. World Energy applied to the SFC for loan guarantees and price supports for an underground gasification project. According to the original SFC application, the Fischer-Tropsch synthesis would be used for the production of refinable liquids. However, they did not meet the SFC deadline for additional information. The project sponsors reapplied for a loan guarantee under the SFC's second solicitation ending June 1, 1982. The revised project proposed to utilize UCG technolov to Droduce 14 billion Btu of SNG and 436 barrels of li ght nils ner dnu. The nrniert ijid nnt

Project Cost: Unavailable

UNDERGROUND COAL GASIFICATION - Mitchell Energy, Republic of Texas Coal Company, DOE DOE selected Mitchell for the first round PL 96-126 solicitations for a feasibility study of in situ gasification of deep Texas lignite. The medium Btu synthesis gas produced would be converted to hydrogen and carbon dioxide at a site on the Texas Gulf Coast. A small scale production test at 100 to 400 TPD will be conducted, and if successful, commercial production units of 2000 TPD would begin in 1985. Project Cost: $809,000

UNDERGROUND COAL GASIFICATION - University of Texas (Austin), Basic Resources, DOE, Texas Energy and Natural Resources Advisory Committee, and Texas Mining and Mineral Resources Research Institute Laboratory investigations have been underway since September 1974, to determine technical, environmental, and economic feasibility of in situ gasification of large reserves of deep basin Texas lignite. The goat of the research is to establish which geological, physical, and chemical conditions are conducive to in situ gasification as well as establishing design principles for field tests and ultimate commercialization. Laboratory and theoretical studies are being performed by the Departments of Chemical Engineering, Petroleum Engineering, Environmental Health Engineering, and the Bureau of Economic Geology. Laboratory work is focusing on lignite reaction properties tar

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-113 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982)

UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

cracking, combustion tube studies, block experiments, burning rates, sweep efficiency modeling, rock mechanical properties of the overburden, subsidence modeling, and biological charpcteristics of wastewater (surface and subsurface). Project Cost: $200,000/Year UNDERGROUND COAL GASIFICATION, CANADA - Alberta Research Council, Four government agencies, 11 industry participants The Alberta Research Council began in situ coal gasification tests in July 1976 at a site approximately 90 miles southeast of Edmonton, Alberta, at the Manalta Coal, Ltd., Vesta mine. The Forcstburg project involved reverse combustion linkage followed by forward gasification of two pairs of wells at opposite ends of a 9 m x 18 m rectangular pattern. After forward gasification between end-wells, a line-drive was attempted between the two pair of end wells. The latter step was difficult to control and lack of horizontal containment of produced gases led to termination of the gasification test. The gasification site was excavated during the fall of 1977 and the affected zone of the first burn dimensioned and documented. The project is being held in abeyance pending additional technical feasibility and economic viability studies. Work is continuing on the development of a mathematical model for UCG. Recent progress has been the completion of a finite element program for predicting heat penetration into the coal strata. Future work will be directed toward modeling of cavity growth. This work will be complemented by small scale experiments to develop parameters for high temperature pyrolysis associated with UCG. Project Cost: $10 million for 5-year program UNDERGROUND COAL GASIFICATION, HANNA PROJECT - DOE, Laramie Energy Technology Center and Rocky Mountain Energy Co. The Linked Vertical Well (LVW) process for underground coal gasification has been under development since 1972 at a site near Hanna, WY. The process is directed at the gasification of coal seams between 15 and 50 feet thick. This involves the linkage of well bores by reverse combustion, followed by gasification by forward combustion. During Hanna II, the maximum gas production achieved was 11.5 MMSCF/day with a heating value of 175 Btu/SCF (equivalent to 325 barrels of oil per day). Hanna Ill, was a two-well pattern (60 feet apart) designed to provide environmental information—specifically effects to groundwater. Hanna IV is a three-well pattern which began air communication tests September 1977 in preparation for a gasification test. Linkage between origiQal wells over- rode the coal seam. Two new offset wells were drilled to reestablish linkage at bottom of seam. Subsequent gasification test indicated coal over-ride again. Hanna IV was re-injected on April 20, 1979 using a linear pattern of four wells spaced 31.5 feet apart. The reverse combustion link moved across the desired pattern for 75 feet during the first nine days, linking two of the wells. Problems were encountered in further attempts at linking but, by July 11, the link to the third well was complete and at least two links were seen, both low in the coal seam. During the test, gas production of 4500 scf/min was achieved. The test was shut down Sept. 21, 1979 after 37 consecutive days of gasification. Under the new DOE Underground Coal Gasification Program, Hanna V has been deferred indefinitely. Activities at the site are concerned with environmental monitoring. As part of the permit requirements with the Wyoming Department of Environmental Quality, the site hydrology and the effect of the burn areas on the hydrology are being determined. Post-burn coring of the Hanna II, phases 2 and 3 site began in October 1980. Cores from both Hanna H and Hoe Creek 3 are being analyzed. Project Cost: $1.6 million, FY 1976 $2.3 million, FY 1977 $3.6 million, FY 1978 $3.2 million, FY 1979 $2.4 million, FY 1980 UNDERGROUND COAL GASIFICATION, HOE CREEK PROJECT - DOE and Lawrence Livermore Laboratory The project is designed to develop a process for steam-oxygen gasification of underground coal, producing medium- Btu gas suitable for conversion to SNG or as a chemical feedstock. Methods for enhancement of coal bed permeability are included in the project. A preliminary two-well fracture and air gasification test, Hoe Creek No. I, was conducted during October 1976 at a site 25 miles southwest of Gillette, Wyoming. Gasification at Hoe Creek No. 2, which utilized reverse combustion to link two process wells, was initiated on October 14 1977 and completed December 25, 1977, primarily using air gasification. Oxygen injection producing 250-300 Btu/scf gas was carried out for two days during November 1977. Hoe Creek No. 3, initiated in August 1979, was the first in-situ experiment to use a horizontal channel to control the combustion front as it moves through the coal seam. The experiment was carried out in a 25 foot seam of subbituminous coal at a depth of 165 feet from the surface. During the 47 day run

4-114 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

with steam and oxygen injection over a 100 foot link, 3900 tons of coal were gasified, producing a synthesis gas with an average heating value of 218 Btu/SCF. The average coal consumption rate was 80 ton/d. The average gas composition was 37 percent 1121 5 percent CH 4, 11 percent CO, and 44 percent CO2. Gas recovery was approximately 86 percent during the test, and the average thermochemical efficiency was near 65 percent. Subsidence between the injection and production wells began three weeks after gasification stopped. A crater 60 feet by 30 feet, and 9 feet deep resulted. Efforts in 1980 included analysis of the Hoe Creek No. 3 experiment, including postburn coring; modeling; laboratory experiments; and environmental R&D. This work continued into 1981; five small scale cavity development tests were conducted for a coal outcrop near Centralia, Washington for September-December 1981. (See UCG, Tono Project) Project Cost: $3.5 million, FY 1976 $2.7 million, FY 1977 $2.7 million, FY 1978 $5.1 million, FY 1979 $2.6 million, FY 1980 $2.7 million, FY 1981

UNDERGROUND COAL GASIFICATION, PRICETOWN PROJECT - DOE, Morgantown Energy Technology Center, Consolidation Coal Company The project was designed to assess the potential for underground coal gasification in thin seam, swelling bituminous coal. The ultimate gasification process has not been identified, although concepts which utilize directional drilling techniques to place long, parallel, horizontal holes in the coal seam have been given prime consideration. However, the first field test, Pricetown I, was conducted to determine whether the Linked Vertical Well (LVW) technology, can be adapted to recover the unmineable bituminous coal resource. The project site is located near Pricetown, West Virginia, and the target zone is high volatile Pittsburgh seam bituminous coal. Status -The reverse combustion linkage (RCL) phase of the test was initiated on June 9, 1979, with the successful ignition of the high ash, high sulfur coal seam. The initial linkage path over the forty foot section of the test field was found to be insufficient and a second pass of the flame front through the link was completed on July 8, 1979. After successfully relaying the reaction front into the sixty foot section of the field, RCL was continued until breakthrough at the injection well on July 23, 1979. The gasification phase of the field test was initiated on September 23, 1979, and was continued until October 5, 1979. During the period, air injection into the 60 foot long coal seam section was maintained at about 1.8 MMCF/day at 300 PSIG pressure. Production flow averaged 4.2 MMCF/day at system backpressures up to 120 P51G. A relatively clean combustible gas having an average heating value of about 127 Btu/cf (527 MMBtu/day) was produced through the gasification phase. During the four month burn, more than 850 tons of coal was effected with approximately 20-25 tons consumed per day during gasification. Test operations were shut down on October 19, 1979, and post-test coal seam and environmental monitoring initiated. Post test core drilling (consisting of 4 core Wells) was initiated in December 1980, and completed in February 1981. Burn analysis was completed and a Report of Investigation (RI) is scheduled for completion in July 1982. Post monitoring of deep and shallow well water and surface streams was terminated as all data indicate pre-burn conditions. A one year effort was completed to inject actual data into a 3-D thermodynamic model to evaluate burn predictions and results. A contract Williams Brothers Engineering Co. to assess the flat and steeply dipping bituminous coal beds in the eastern part of the U.S. The work was completed in January 1982, and includes site selection, site availability, resource availability, and linking and gasification technology best suited to the resource. Three concepts were developed. The METC/UCG program was terminated as of September 1982. Project Cost: $1.1 million, FY 1977 $3.2 million, FY 1978 $0.9 million, FY 1979 $0.56 million in FY 1980 $0.592 million in FY 1981 $0.553 million in FY 1982- revised UNDERGROUND COAL GASIFICATION, ROCKY HILL PROJECT - ARCO ARCO conducted an in situ coal gasification test near Reno Junction, Wyoming. A linked vertical well gasification program using three in-line wells was completed. Target zone was a 110 foot-thick coal seam at a depth of 630 feet. Construction took place in the summer 1978 with operation in August-September. Two 75-foot reverse combustion links were established at the bottom of the coal seam, and, significantly, the second link was a relay of the first.

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-115 STATUS OF SYNPUELS (Underline Denoted Changes Since September 1982) UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

This was followed by 60 days of forward combustion at air flow rates up to maximum capacity of 4,009 SCFM. Average gas quality exceeded 200 Btu/SCF. No further testing is planned. Site decommissioning and reclamation are underway. UNDERGROUND COAL GASIFICATION, STEEPLY DIPPING BED PROJECT —DOE and Gulf Research & Development Company Gulf R&D, Harmarville, PA, was awarded a cost-sharing contract in September 1977 to develop technology for underground gasification of steeply-dipping coal seams (dipping greater than 45 0 ). The project includes site evaluation and environmental assessment, followed by two field tests for process evaluation. A site was selected eight miles west of Rawlins, Wyoming, in Section II, T2IN, R89W. The first test was completed in December of 1979 and met all of the test objectives. The coal was ignited at a vertical depth of 400 ft. utilizing a directionally drilled process well pair with a drilled link between well bases. The 35-day test included both water/air injection and steam/0 2 injection phases. According to plan, approximately 1200 tons of coal were utilized. During the air gasification phase, product gas quality initially climbed to 189 Btu/SCF and, as expected, gradually declined to the 120-130 Btu range over a 21-day period at production rates between 3000 and 4500 SCFM. The five-day steam/O test yielded 230-280 Btu/SCF gas at rates ranging between 2000-4000 SCFM. Post-test characterization has bee completed and included drill coring, sonar measurements, and TV camera logging of the resultant burn cavity. The results of this work has produced a complete model of this cavity, and has contributed appreciably to the understanding of the mechanism of gasification. In Test 2, at the Rawlins site, the coal was ignited at the base of the injection well on August 23, 1981. Operation continued for 40 days with a series of experiments studying the effect of 02 injection rate, steam/02 ratio, residence time, and reactor pressure. Product heating value ranged 320-400 Btu/SCF with 350-400 Btu/SCF maintained over much of the period. Gas quality did not degrade as seen in Test 1 and at other sites. About 4500 tons of coal were gasified in this period. Wet product gas rates were 5000-8000 SCF/m with project oxygen ratios of 6-11 observed. Maximum daily coal gasification rates were 210 TPD. Operation was then switched to the vertical injection well for a 14 day test. In this mode, heating values of 270-340 Btu/SCF were observed. Approximately 2000 tons of coal were gasified during this time with product/oxygen ratios of 3-5 obtained. In the final 12 days of operation, both injection wells were operated simultanedusly producing up to a single product well. Coal gasification rates of 150-200TPD and product heating values of 280-350 Btu/SCF were realized. Project Cost: $18.25 million UNDERGROUND GASIFICATION OF TEXAS LIGNITE, TENNESSEE COLONY PROJECT - Basic Resources, Inc. Basic Resources, Inc., a wholly owned subsidiary of Texas Utilities, has purchased underground gasification technology developed in the Soviet Union to determine the feasibility of gasifying deep lignite deposits in east Texas. They have prepared an underground gasification experiment in western Anderson County. Permit for project was granted by Texas Railroad Commission. Ignition was achieved on August 9, 1979. Lignite was gasified in line drive between two parallel rows of wells spaced 80-100 feet apart. Testing was terminated March 4, 1980. Operation during the last two weeks of the six-month test was with an oxygen steam mixture. During the first phase of testing, the heating value of the gas produced averaged 81 Btu/sef with an average production rate of 285 MMBtu/day. In the second phase utilizing steam-oxygen, the heat content of the product gas averaged 230 Btu/scf with the maximum value obtained being 260 Btu/scf. Project Cost: Undetermined UNDERGROUND GASIFICATION OF TEXAS LIGNITE - Texas A&M University Texas A&M is presently conducting field tests to develop the Linked Vertical Well process for in situ gasification of Texas lignite. The first project site was about three miles southwest of the campus at College Station, Texas. The objectives of the field experiment were to test the procedures of ignition, back burn, gasification, and to gather environmental data. Water intrusion from an overlying aquifer prevented sustained combustion at this site. A second gasification test site has been selected in Milam County, Texas on lands owned by Alcoa. Target zone is a 14-foot thick lignite zone at a depth of 227 feet. Project Cost: $250,000/year

UNDERGROUND COAL GASIFICATION, TONG PROJECT - DOE, Washington Irrigation and Development Company (WIDCO), Pacific Power and Light, Lawrence Livermore National Laboratory, and the State of Washington In 1979, Congress appropriated funds to study UCG in the State of Washington. Most of the state's coal resources are deep, steeply dipping, thin, or dirty. The tests were designed to demonstrate how these resources can be

4-116 SYNTHETIC FUELS REPORT, DECEMBER 1982 STATUS OF SYNFUELS (Underline Denoted Changes Since September 1982) UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

recovered by UCG. Sandia National Laboratory participated in the site selection at Tono near Centralia, Washington. Five tests were conducted to determine the effects of changing the mixture of air, oxygen, and steam. Each test lasted three to five days and consumed approximately 40 tons of coal. At the conclusion of each test, the burn cavity was visually inspected by a remote television system and then excavated. The final test was concluded in January 1982. Project Cost: $800,000 (NOTE: also see Washington State UCG Site Selection and Characterization.) UNDERGROUND COAL GASIFICATION, WASHINGTON STATE UCG SITE SELECTION AND CHARACTERIZATION - Sandia Laboratories This project selected and characterized a site in the State of Washington suitable for conducting an underground coal gasification experiment. Of the areas identified as likely having large enough resources for commercial development, the Centralia-Chehalis District was selected as the primary area for further study. This district covers 570 square miles in west-central Washington, and it contains about 3.3 billion tons of coal in nine seams at various depths. A major market exists in the form of fuel for electrical power generation. The geology is complex and includes sharp structures, but it is believed that there is enough area of gentle to moderate structure to provide for UCG sites. The Tono Basin near Centralia, Washington, was selected for DOE's first programmatic activity in the new Underground Coal Gasification program. SNL completed the site characterization activities which utilized surface geophysical techniques, borehole and cross-borehole geophysical techniques, and taking and analyzing overburden and coal cores, LLNL performed hydrologic testing and an environmental investigation. The surface geophysical techniques were used to delineate geologic structure and determine coal seam continuity. The reflection seismic data uncovered a more complex structure at the site than was determined from boreholes alone. The borehole geophysical logs were used to identify coal seams and their thicknesses, estimate overburden strength and coal quality, help determine lithology, and used for stratigraphic correlation between exploratory boreholes. The cross-borehole, in-seam seismic wave studies were used to determine coal seam continuity, and the results of these studies are in basic agreement with the reflection seismic survey results. The coal quality was determined from coal cores. The hydrologic tests were used to estimate the permeability of the overburden and coal seam which will be used to estimate water influx rates for a UCG process. The environmental work evaluated the Potential consequences to ground, air, water, and archeological conditions. The project activities, which are complete, uncovered no characteristic that would prevent a UCG test in the Tono Basin. Five small scale cavity development tests are planned for a coal outcrop near Centralia, Washington, for September-December 1981. Future tests on the site will be covered under Underground Coal Gasification, Tono Project. Project Cost: $850,000 UNDERGROUND COAL GASIFICATION, THUNDERBIRD II PROJECT - Wold-Jenkins The project, located in Johnson and Campbell Counties,

Project Cost: Undetermined

*New or Revised Projects

SYNTHETIC FUELS tEPORT, DECEMBER 1982 . 4-117 RECENT COAL PUBLICATIONS

Abichandani, J. S., et al, 'Kinetics of Short Contact Time Coal Liquefaction -Effects of Nature of Solvent and Coal Type," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Anthony, Rayford G., et al, "A Kinetic Model for Lignite Liquefation on a Continuous Stirred Tank Reactor," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Atherton, Linda F., and C. J. ICulik, Electric Power Research Institute, "Advanced Coal Liquefaction," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Bakker, W., EPRI, S. Darling, Combustion Engineering Co. and W. Coons, Lockheed Space and Missile Co., "Behavior of Coal Slag During Gasification, presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Baldwin, R. M. and M.K. Mohalland, Colorado School of Mines, "Hydroprocessing of Coal-Derived Asphaltenes," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Barker, R. E., et al, "Physical Property Estimation for Coal Liquids," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Bartholomew, C.H., and R. M. Bowman, Brigham University, "Sulfur Poisoning of Cobalt and Iron Fischer-Tropsch Catalysts," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Bixler, A.D., et al, "Characterization of SRC-I Ash Residues and Implications for Gasifier Selection," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Rocker, 0., W. Dolkemeyer, K. H. Keim and U. Lenz, Rheinische Braunkohlenwerke Aktiengesellschaft, "New Results on Hydroliqucfaction of Rhenish Brown Coal," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Briggs, Dale E., University of Michigan, "The Physical State in Direct Coal Liquefaction," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles; California. Brule, M.R., Kerr-McGee Corp.. and Kenneth E. Starling, University of Oklahoma, "Applications of Multiproperty Analysis in the Prediction of Complex-System Thermophysical Properties", AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. CANMET Co., "The CANMET Hydrocracking Process to Upgrade Residual Oil," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Chao, K.C., H.M. Lin and H.Y. Kim, Purdue University, "Equilibrium Vaporization of Coal Liquids and Their Mixtures with Hydrogen," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Chang, H. L., D. M. Himmelblau, and T. F. Edgar, University of Texas at Austin, "Flow Characteristics in Underground Coal Gasification," In Situ 6(2), 143-162 (1982). • Conkle, H. Nicholas, et al, "Preparation of Low-Sulfur Fuel Gas by Gasification of Battelle Treated Coal," presented at the AIChE National Meeting, Anaheim, California, June 7-9, 1982. Cook, L., C. Chiang, National Bureau of Standards, and T. Hahn, Naval Research Laboratory, "Tectosilicates - New Data on Processing, Physical and Electronic Properties, and Chemical Durability," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Department of Energy Reports, available from National Technical Information Service, 5285 Port Royal Road, Springfield, VA 22161. DOE/PC/30232-T3, "Pollutants from Coal-Conversion Process," Third progress report, September 1, 1981 - May 31, 1982. N.C. State University, 1982.

Reviewed in this issue

4-118 SYNTHETIC FUELS REPORT, DECEMBER 1982 DOE/ET/11029-1191, "Bench-Scale Development of Catalysts for Reforming Aromatic and Heterocyclic Hydro- carbons." Final report, February 1980 - February 1982. Parsons Co., April 1982. DOE/ET/14884-1224, "Dew Points of Hot Gases from Coal-Gasification Processes." Final report. California University, May 1982. DOE/MC/16220-T7, "Engineering Analyses for Evaluation of Gasification and Gas-Cleanup Processes for Use in Molten-Carbonate Fuel-Cell Power Plants." Westinghouse Electric Corp., February 1982. DOE-MC/24591-1173, "Coal-Gasification Catalysis Mechanism." GE Co., April 1982. DOE/MC/19151-T1, "42 Inch Gas Producer Run 99: Holmes-Stretford System Evaluation." Final report. Peabody Process Systems, Inc., May 10, 1982. DOE/PETC/TR-82/11, "Formation/Decomposition of Condensible Hydrocarbons During the Gasification of Coal." DOE, April 1982. DOE/RA-20225-T3, "Wastewater Treatment System for a Lurgi Coal-Gasification Plant." ANG Coal Gasification Co., 15 February 1982. DOE/OR/03054—T12-Vol. 1, "SRC-1 Demonstration Project: Executive Summary." International Coal Refining Co., 1982. SAND-82-0758, "Analytical Solutions for Predicting Coal Drying." Sandia Nat. Labs., April 1982. SSS-R-81-5057, "Computer Modeling of Coal-Gasification Reactors. Theory of Idealized Coal Devolatilization." Systems, Science and Software, April 1982. UCID-19356, "High-frequency Electromagnetic Probing at LLNL's Large-Block Coal Gasification." Lawrence Livermore Nat. Lab., 6 April 1982. UCRL-87662, "Review of Underground Coal-Gasification Field Experiments at Hoe Creek." Lawrence Livermore Nat. Lab., 26 May 1982. BMI-2092, "Thermophysical properties of Coal Liquids: Final Report." Battelle Columbus Labs., 23 April 1982. UCRL-87611, "Large Block Tests." Lawrence Livermore National Lab., May 11, 1982. LBL-14216, "Homogeneous Hydrogenation of Model-Coal Compounds." Lawrence Berkeley Lab., May 1982. LBL-13228-Rev., "Heat and Mass Transfer Effect in Slurry Bed Fischer-Tropsch Reactors." Lawrence Berkeley Lab., February 1982. ORNL/MIT-343, "ASPEN Simulation of an Indirect Coal-Liquefaction Plant." Oak Ridge National Lab., June 1982. ORNL/TM-8222, "Coal-Liquefaction Letdown Valve Operating Experience at Coal-Liquefaction Pilot Plants." Oak Ridge National Lab., June 1982. *Department of Energy, "A Wastewater Treatment System for a Lurgi Coal Gasification Plant," A Report on the Development of a Wastewater Treatment Design for the Great Plains Gasification Plant in Mercer County, North Dakota, February 15, 1982, work performed under Contract No. FCO3-79RA20225, with ANG Coal Gasification Company. Dierks, D, Argonne National Laboratory, "Performance of Refractories in Coal Gasifier Slag," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Dry, M.E., Sasol One (Pty) Ltd., "Sasol's Fischer-Tropsch Experience," Hydrocarbon Processing, Vol. 61, No. 8, August 1982. Durrfeld, R., at al, Ruhrkohle Oel und Gas GmbH, "Results of 4 Years Operation of the Texaco-Coal-Gasification-Plan at Oberhausen-Holten as Developed By Ruhrkohle AG and Ruhrchemie AG," Bottrip den 28 Mal 1982. Ekerdt, J.G. and C.J. Wang, University of Texas, "Fischer-Tropsch Synthesis over Iron Catalysts: The Use of Radioactive Scavengers to Identify Reaction Intermediates," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California.

Reviewed in this issue

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-119 Firestone, R. and R. Yurkewycz, ITT Research Institute, "Corrosion/Degradation of Test Materials in Westinghouse POt) Fluid Bed Gasifier," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization. Firnhaber, Bernd and Rolf Wetzel, GKT Gesellschaft fur Kohle-Technologie GMBH, "Fuel Evaluation for Entrained-Bed Coal Gasification," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Fischer, R., Integral Engineering lndustriebedarf-GmbH, "The Sulfint Process," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982 Gac, F., C. Cappiello and J. Bennett, Los Alamos National Laboratory, "Materials Needs for the Design of a 'Ceramic' Lockhopper Valve," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18 9 1982, Gaithersburg, Maryland. Gardner, N.C. at al, Case Western University, "Hanging Reactor Thermobalance Study of Coal Gasification Kinetics," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Gas Research Institute and U.S. Department of Energy, "Pipeline Gas from Coal - Hydrogenation (KIT Hydrogasification Process)," Project 70101 Final Report, Period August 1, 1976 through August 31, 1980, published March 1982, FE-2434-68, Dist. Category UC-90c. Gullies, M. T., "C1-Based Chemicals from Hydrogen an Carbon Monoxide," Chemical Technology Review No. 209, ISBN 0- 8155-0901-4 (1982). Given, P. H., et al, Pennsylvania State University, "The Relation of Coal Characteristics to Liquefaction Behavior," Final Technical Report, July 1976 to February 1981, Part II, DOE/ET/10587-T1(Pt.2) ( FE-2494-FR-2) (DE82016938) Gouker, T.R., B.E. Beasley and W. J. Calvin, Exxon Research & Engineering Co., "Support of Process Improvements in the Catalytic Coal Gasification Development Program," presented at the AIChE 1982 Annual Meeting, November 14-19, 19829 Los Angeles, California. Hastie, J., E. Plante, D. Bonnell and W. Horton, National Bureau of Standards, "Experimental and Theoretical Activity Models for Slags and Related Materials, presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. • Happel, J., at all, Institute of Gas Technology, "Direct Methanation of Raw Synthesis Gas," 1981 International Gas Research Conference. Ilumenick, M.H., University of Wyoming; L. N. Britton and C. F. Mattox, University of Texas; "Natural Restoration of Ground Water in UCG," In Situ, 6(2), 107-125 (1982). Humphrey, J. and F. Pourahmadi, University of California, Berkeley, and A. Levy, Lawrence Berkeley Laboratory, "Prediction of Erosive Wear by Solid Particles in a Turbulent Curved Channel Flow," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Humphreys, B. and E. Vesely, Jr., ITT Research Institute, "Corrosion/Degradation of Test Materials in Westinghouse PDU Fluid Bed Gasifier," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Ishiguro, T., Y. Murakami, K. Ohnishi and J. Watanabe, Japan Steel Works, Ltd., Japan, "Alloy Modification of Cr-Mo Steel for the Coal Liquefaction Reactor," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18,1982, Gaithersburg, Maryland. Kaiser, J. and R. Judkins, Oak Ridge National Laboratory, "Performance of Materials in Coal Liquefaction Systems," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburgh, Maryland. Knickle, Harold N. and Anand Kamat, University of Rhode Island, "Prediction of Hydrodynamic Effects in Bubble Column Type Coal Liquefaction Reactors," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Kunesh, J.G., at al, "Problems in Pilot Plant Engineering - A Case History," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Lacey, John A., British Gas Corp., "British Gas SNG Program," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Reviewed in this issue

4-120 SYNTHETIC FUELS REPORT, DECEMBER 1982 •Langhoff, J., at al, "RUHR 100 - New Results on the Advanced Development of the Pressurized Lurgi-Gasification," presented at the 9th Annual International Conference on Coal Gasification, Liquefaction, and Conversion to Electricity, August 3-5, 1982, Pittsburgh, PA. Ledent, P., Institution Pour le Developpement de la Gazeification Souterraine, "Underground Coal Gasification: A New Way for the European Chemical Industry," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Lee, Bernard S., "Synfuels from Coal," Thirty-third Annual Institute Lecture, AIChE, 1982, M-14. Lie, C., Cornell University, "Observation of Hydrogen Attack," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Lin, C. and C. Hirayama, Westinghouse Research & Development Center, "Solid Electrolyte Cell for Monitoring of Sulfor Oxides, presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-19, 1982, Gaithersburg, Maryland. Mangold, Edward C., at al, "Coal Liquefaction and Gasification Technologies," Ann Arbor Science Publishers, Inc. (The Butterworth Gruop, 10 Tower Office Park, Woburn, MA 01801), 1982. Massaquoi, J.G.M., D. M. Rohaus and J. B. Riggs, West Virginia University, "Discovery of a Mechanism for Oxygen Transport During UCG, "In Situ, 6(2), 127-141 (1982). Masudi, H., R. Griffin and T. Pollock, Texas A&M University, "Determining the Properties of Solid Particles Collected During In Situ Gasification of Lignite and Evaluating Their Effect on the Erosion of Metals," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18,1982, Gaithersburg, Maryland. Mather, V. K., and E. Fakoukalis, University of New Hampshire, "Coal Liquefaction Using Ore Catalysts," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. McGee, T. and G. Kim, Iowa State University, "Creep of Refractory Concrete Gasifier Linings," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Mehta, D. C, at at, "Heat Capacity of Coal-Solvent-Hydrogen Mixtures," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. 'Meyer, Howard S., Vernon L. Hill, Ab Flowers, Gas Research Institute and John Rappel, Miguel A. Hantow, Catalysis Research Corporation, "Direct Methanation - A New Method of Converting Synthesis Gas to Substitute Natural Gas," American Chemical Society, Division of Fuel Chemistry, Vol. 27, No. 1., March 28 - April 2, 1982. Mikhlin, J.A., SNC Inc., "Coal Liquefaction in Canada," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Milewski, J., F. Gac, and J. Petrovic, Los Alamos National Laboratory, "Production and Characterization of Beta-Silicon Carbide and Alpha-Silicon Nitride Whiskers for Ceramic Matrix Composites," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-28,1982, Gaithersburg, Maryland. Nangia, Vinod K., "Materials of Construction for Advanced Coal Conversion Systems," Energy Technology Review No. 75, ISBN 0-8155-0884-8 (1982). Odette, R., University of California at Santa Barbara, "Modeling of Hydrogen Attack," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Paschen, Henrich, Waldhecker, KHD Humboldt Wedag AG, "The Humboldt Coal Gasification Process," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Pappas, Nicholas, at al, Purdue University, "Changes of the Crosslinked Macromolecular Structure of Coal During Extraction and Solubilization," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Pollina, R., R. Larsen and D. Westpfahl, Montana State University, "The Electrical Behavior of Western Coal Slag," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Rankin, J.L. at al, Brigham Young University, "Fischer-Tropsch Synthesis on Promoted and/or Supported Iron and Cobalt Catalysts," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. 'Reviewed in this issue

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-121 Rehmat, Amir and Anil Goyal, "Support Studies for the U-Gas Coal Gasification Process," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Ruhrkohle Get und Gas GmbH, "Coal Refining Activities," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Salvador, Louis A., Westinghouse Electric Corp., "The Joint Westinghouse/SASOL Commercial-Scale Fluidized-Bed Coal Gasification, Project," presented at the 9th Annual International Conference on Coal Gasification, Liquefaction and Conversion to Electricity, August 3-5, 1982. Santosh, K., et al, "Vapor Phase Catalytic Cracking of Coal Pyrolysates in Presence of Raw Gases from Coal Gasification," presented at AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Satriana, M.J., "Hydroprocessing Catalysts for Heavy Oil and Coal," Chemical Technology Review No. 202, Energy technology review No. 74, ISBN 0-8155-0883-2 (1982). Satterfield, C.N. and G.A. Huff, Jr., Massachusetts Inst. of Technology, "Kinetics of the Fischer-Tropsch Synthesis over Reduced Fused Magnetite," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Saville, D.A., et al, Princeton University, "Time-Resolved Kinetics of Coal Pyrolysis and Hydropyrolysis," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Schad, M.K. and C.R.H. Hafke, Lurgi Kohle und Mineraloltechnik GMBH, "Lurgi Coal Gasification Development," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Schlupp, Karl F., Ruhrkohle Del Und Gas GmbH, "First Experience and Results Gained During Operation of the 200 Tb COAL OIL Plant in Bottrop," presented at the COGLAC 1982 Conference, Pittsburgh, Pennsylvania, August 5, 1982. Schwartz, Carl W., "A Comparison of Air and Oxygen Blown Coal Gasification for Combined Cycle Plants," AIChE Conference, Anaheim, California, June 7-10, 1982. Shiflet, W. et al, "Fischer-Tropsch Synthesis Over Ru Catalysis Derived from Ru Carbonyls," presented at the AIChE 1982 Annual Meeting. November 14-19, 1982, Los Angeles, California. Shimda, M., T. Yonezawa and M. Koizumi, Institute of Scientific and Industrial Research, Japan, "Oxidation of High Pressure Hot-Pressed Si3N4 Without Additives," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Sikka, V., Oak Ridge National Laboratory, "Development of Modified 9Cr-IMo Steel," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Singh, C.P.P., and N. L. Carr, Pittsburg & Midway Coal Mining Co., "Solvent Refined Coal (SRC) Process: Simulation of an SRC-II Plant," prepared for U.S. Department of Energy, DOE/ET/10104-51 (DE82012487), February 1982. Singh, C.P.P. and N.L. Carr, Gulf Research & Development, "Kinetics of SRC-11 Coal Liquefaction," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Singh, C.P.P., and N. L. Carr, Gulf Research & Development, "Effect of Mixing Energy on Hydrogen Reaction Rates in 5CR-11 Coal Liquefaction," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Skov, A., B. Normann Jensen, Haldor Topsoe A/S, "Manufacture of SNG," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Starling, Kenneth, K. Hemanth Kumar and Suphat Watanisiri, University of Oklahoma, "Application of Multiparameter Corresponding States Methods to Predict the Thermodynamic Properties of Polar and Associating Pure Coal Fluids," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Suuberg, Eric, Brown University and P. Unger, Carnegie-Mellon University, "Molecular Weight Distribution of Tars Produced by Flash Pyrolysis of Coal," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Tabakoff and A. Hamed, University of Cincinnati, "Investigation of Gas Particle Flow in Erosion Wind Tunnel," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland.

*Reviewed in this issue

4-122 SYNTHETIC FUELS REPORT, DECEMBER 1582 Thomas, M.G., and A.W. Lynch, Sandia National Laboratories, "Kinetics and Mechanisms of Secondary Reactions," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Todd, J., University of Southern California, 'Development of a New Class of Pressure Vessel Steels," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Torti, M., D. Reed and J. Lucke, Norton - Company, "Silicon Carbide Ceramics for Coal Conversion Applications," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Tsotsis, T.T., and W.C. Li, University of Southern California, "Deactivation Phenomena During Catalytic Coal Liquefaction: A Theoretical and Experimental Study," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. U.S. Department of Commerce, National Bureau of Standards, "Construction Materials for Coal Conversion: Performance and Properties Data," NBS Special Publication 642, September 1982. U.S. General Accounting Office, "Government Support for Synthetic Pipeline Gas Uncertain and Needs Attention," GAO/EMD-82-23, Mary 14, 1982 Varghese, P., F. J. Derbyshire and D.D. Whitehurst, Mobil R&D Corp., "The Kinetics of Thermal and Catalytic fl-Transfer in the Liquefaction of Sub-bituminous Coal," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Varma, Vinod K., "Costs of Producing Fuel Grade Methanol and Medium Heating Value Gas By Underground Coal Gasification," Science & Technology of Synfuels: I, Colorado Springs, March 1-3, 1982. Verma, S., Ill Research Institute, "Corrosion Behavior of Selected Alloys in Laboratory and Pilot Plant Coal Gasification Environments," 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Wads, T., T. Cox and F. Fletcher, Climax Molybdenum Co., "A New 3-1/4Cr-1-1/2Mo Steel for Heavy Plate Applications," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Washburn, M., Norton Company, "Rotating Sample Slag Test for Refractories," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Wei, G. C., C. S. Morgan and D. R. Johnson, Oak Ridge National Laboratory, "Synthesis, Characterization and Fabrication of SiC Structural Ceramics," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland. Weimer, L.D., and D. A. Austin, Resources Conservation Co., "Evaporator Developments in Synfuels Process Slowdown Treatment - Recent Experience," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Weller, Sol W., P.I. Chien and M.C. Tsai, State University of New York, "Catalysis of Hydrogen Transfer from Tetralin to Coal," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Wham, R.L., et al, "Examination of Short-Contact-Time Coal Liquefaction Product Stability," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Wilming, H, C. Peuckert, R. Muller, Chemische erke Buis Aktiengesellschaft, "Acetylene Production from Coal in the Huts H2 Plasma Process," presented at the Synfuels' 2nd Worldwide Symposium, October 12, 1982. Yesavage, V.F. and A. J. Kidney, Colorado School of Mines, "A Review of Enthalpy Measurements on Coal-Liquids and Model Compounds," presented at the AIChE 1982 Annual Meeting, November 14-19, 1982, Los Angeles, California. Zeilinger, H., B. Stemmler, and A. Muhlratzer, M.A.N. - Neue Technologies, West Germany, "Deliverate Pre-Oxidation of High-Temperature Materials by the M.A.N.-CYCLOX Process," presented at the 7th Annual Conference on Materials for Coal Conversion and Utilization, November 16-18, 1982, Gaithersburg, Maryland.

Reviewed in this issue

SYNTHETIC FUELS REPORT, DECEMBER 1982 4-123 y. APPENDIX

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GLOSSARY OF TERMS RELATIVE TO

A feature commonly observed in geology whereby a property will show different rates of change in values when measured from a fixed point along different directions.

Anisotropy Ellipsis Graphical representation of the magnitude of the measured property along different directions.

Continuity Qualitative measurement of the homogeneity of any measurable phenomena.

Correllogram Classical statistics tool showing the variation of correlation with respect to distance between two observer positions.

Drift - Term used to describe a systematic variation in the measured values of a phenomena within a certain field. For example, the decrease in elevation when one moves down dip.

Extrapolation Term used to describe the generation of estimates beyond existing measurements using a functional relationship, measured and modeled on these same measurements.

Generalized Covariance Sophisticated mathematical and statistical model of the functional relationship of the variability of measurements in space which employs a random component, a deterministic component and a correlated component (see Universal Kriging).

Interpolation Estimation of values at unsampled locations situated between existing measurements. -

Jacknifing - A technique for evaluating the quality of an estimator by comparing an estimate with a known measurement.

Kriging An estimation method based on the variogram and used in geostatistics that minimizes the error of estimation and gives optimal unbiased estimates.

Linear Variogram A frequently used function to model the observed spatial variability between measurements which increases linearly with separation distance.

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Nugget Tern, given to the random component of the spatial correlation model of a phenomena. The nugget can include sampling error and natural microscale variation. The term is also given to the value of the intercept at the origin of the variogran,.

Proportional Effect Observation of a functional relation between measurement variance and the average value of those measurements.

Range The distance between two measurements where no correlation exists, i.e. each measurement is independent. Term given to the Intercept of the variogram model with the sill.

Sill The variance of the measurements when no correlation exists.

Spherical Variogram A frequently used function to model observed spatial variability. This function incorporates a nugget, a range and a sill.

Stationarity (assumption) A rigorous set of assumptions which allow the use of geostatistics for local valuation: 1. The mean is independent of position. 2. The variance between measurement is independent of position and is only related to the separation distance and direction.

Trend An observed functional relationship between observations that is considered deterministic in nature. Considered synonymous with drift.

Universal Kriging A more generalized estimator used in geostatistics that employs a model with a deterministic component, a correlated component and a random component to represent the variability of regionalized variables.

Variogram A functional relationship that describes the amount of variability (opposite of correlation) of measurements and their separation distance. This function in essence describes the correlated component used in kriglng or universal kriging.

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