23 oY°°Y

JannIiltteffftc] lis0

OIL SHALE 0 COAL OIL SANDS

VOLUME 17 - NUMBER 4 DECEMBER 1980

QUARTERLY

T!1 Ertl Repository .'\tthur Lakes Library C½ rd -11School of Mines

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

") Reg. U.S. Pal. OFF. Cameron Synthetic Fuels Report is published by the Rocky Mountain Division of the Pace Company Consultants & Engineers, Inc. (Formerly Cameron Engineers, Inc.) as a multi-client service and is intended for the sole use of clients or organizations affiliated with clients by virtue of a relationship equivalent to 51 percent or greater ownership. Cameron Synthetic Fuels Report is protected by the copyright laws of the United States; reproduction ofan y 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 Division also has an extensive Information Services Department which publishes a variety of periodic and other reports analyzing developments in the energy field.

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

S. FRANK CULBERSON, PRESIDENT JOHN 0. BAKER, VICE PRESIDENT-INFORMATION SERVICES

SYNTHETIC FUELS STAFF

RHONDA J. DETAMORE AGNES K. DUBBERLY THOMAS A. HENDRICKSON CHARLES 0. HOOK EUGENE L. JOJOLA COLLEEN D. KELLEY KENNETH E. STANFIELD WELANA WENDORFF

CHERRY CREEK PLAZA It 650 S. CHERRY ST., SUITE 400 DENVER, COLORADO 80222 303/3213919 CONTENTS

HIGHLIGHTS ...... A-i

I. GENERAL GOVERNMENT

DOE Issues Program Solicitations for Proposals for Financial Assistance of Commercial Synfuels Projects via Loan & Price Guarantees and Purchase Commitments ...... 1-1 Synthetic Fuels Corporation Will Be the Major Vehicle for Administering Synfuels Commercialization Programs ...... I-? U.S. Synthetic Fuels Corporation Gets a Chairman, Five Regular Board Members, and Plenty of Controversy ...... 1-3 Synthetic Fuels Corporation Issues Its First Solicitation of Project Proposals ...... 1-5 DOE Solicits Proposals for Assistance for Cooperative Agreements and Feasibility Studies of Systems for Direct Combustion of Minerals and Organic Materials ...... 1-6 The [EA and Its Interests in Synthetic Fuels Are Examined ...... 1-6 World Bank Recommends Oil Importing Developing Countries Expand Their Domestic Production of Fuels ...... 1-s Missouri River Basin Commission Prepares Water Resources Management Plan ...... 1-8 Energy Security Act Encourages Production of Alcohols ...... 1-8 ENVIRONMENT

EPA's Approach to Regulating First Commercial Synfuels Facilities Reviewed ...... I-Il EPA No Longer Exempts Fugitive Dust from Being Included in Air Quality Review for PSD Permit ..... 1-13 051-IA to Create a Standards Advisory Committee on Synthetic Fuels ...... 1-13 EPA Contends that Western Energy Developments Need Not Move Forward at "Break Neck" Speed ..... 1-14 BLM Publishes Final Guidelines with Regard to "Areas of Critical Environmental Concern" ...... 1-15 DOE's Environmental Advisory Committee Discovers Oil Shale, Discusses SRC-II EIS ...... 1-15 GAO Notes an Uneasy Partnership Exists between EPA and the States in Administration of Environmental Programs ...... 1-17 ENERGY FORECASTS

Tenneco Projects U.S. Energy Profile through the Year 2000 ...... 1-18 Shell Updates Its "National Energy Outlook" Assessment for the 1980-1990 Period ...... 1-21 CEO Reviews Selected Studies of Low Energy Futures for the United States ...... 1-22 Petroleum Industry Research Foundation, Inc. Reports on the U.S. Energy Perspective—to 1990 ...... 1-23 CEQ Completes Its Global 2000 Report to the President ...... 1-27 ECONOMICS

Synfuels Are a Bargain--if All Costs Are Considered ...... 1-28 Critical Mineral Needs of the United States Are Not Limited to the Mineral Fuels ...... 1-28

U.S. GOVERNMENT SYNFUELS PROCUREMENT NOTICES AND PROGRAM SOLICITATIONS LISTED . . 1-29

RESEARCH AND DEVELOPMENT SOURCES SOUGHT ...... 1-34 U.S GOVERNMENT CONTRACT AWARDS LISTED ...... 1-35 COMING EVENTS ...... 1-39 RECENT GENERAL PUBLICATIONS ...... 1-43 II. OIL SHALE PROJECT ACTIVITIES Status of Major Permits Presented 2-1 C-a Proposes Surface Mine for Lurgi Demonstration 2-1 Rio Blanco Ignites First MIS Retort ..... 2-3 Dow Completes DOE Antrim Shale Contract 2-3 Paraho's Plans Are Reviewed ...... 2-4 Union Discusses Project Plans in Shareholders' Report 2-5

LAND Sohio, Cleveland-Cliffs, Superior Announce Joint Resource Holdings 2-6 Independents Oppose Near-Term Oil Shale Leasing ..... 2-6 Interior Announces Results of Oil Shale Technology Nominations 2-8 Russell's "History of Western Oil Shale" Is Published .... 2-8 Interior Files Brief in Opposition to Mineral Patent Applications. 2-8 Southern Uinta Basin Shale Resources Characterized .... 2-9 Status of Oil Shale Legal Proceedings Noted 2-10 ENVIRONMENT Oxy Petitions Colorado for Relaxed SO Standard ...... 2-13 Draft EIS Issued for Paraho Module at Anvil points 2-IS Naval Oil Shale Reserve Draft EIS Issued 2-IS Environmental Control Technology Tested at Laramie ...... 2-20

GOVERNMENT DOE Inspector General Investigates Laramie's Programs ...... 2-21 LETC Participates in Oil Shale Meetings in Morocco, Israel, and Switzerland 2-22

STATUS OF OIL SHALE PROJECTS ...... 2-24

RECENT OIL SHALE PUBLICATIONS 2-30

III. OIL SANDS PROJECT ACTIVITIES Controversy Arises over Syncrude's SO Emissions 3-1 Cat Canyon Steamflood Updated ..... 3-I Suncor Hurt by New Energy Policy 3-4 Alsands and Esso Cold Lake Projects Put on Hold 3-4 PCE Pilot Project Progresses ...... 3-5 Esso Applies for Cold Lake Fuel Change. 3-5 BP Canada Announces New Pilot Project 3-6 DOE Tar Sand Field Experiment Is Completed 3-6

TECHNOLOGY Papers Presented on Hydrothermal Studies ...... 3-9 DOE Heavy Oil Contractors Make Presentations 3-10 Confab '80 Held in Laramie 3-11 Steam Drive Papers Presented at AIME Meeting 3-12 Canada-Cities Service to Perform Pilot Test in Oil Sands near Cold Lake 3-13 Mining at Suncor Discussed 3-13 Conoco Presents Details of Oil Mining Project ...... 3-14 Two Tar Sand Mining Methods Patented ...... 3-16 Three Papers Presented on Shell Peace River Project ...... 3-IS Solvent Extraction Study Results Presented by National Research Council ...... 3-20 Geotechnical Frontiers in Oil Sand Mining Examined ...... 3-23 GOVERNMENT

Canadian Government Impasse Shelves Oil Sands Plants ...... 3-25 ERCB Procedures Reviewed ...... 3-27 Tar Sand Leasing Bill Dies in Senate ...... 3-30 ECONOMICS

Cost of the Combustion Process in Utah Tar Sand Is Projected ...... 3-31 Heavy Oil Surplus Exists in Canada ...... 3-33 ENVIRONMENT

Environmental Assessment of Utah Tar Sand Test Made ...... 3-34 Environmental Regulations for Tar Sand Development Are Analyzed ...... 3-35 STATUS OF OIL SANDS PROJECTS ...... 3-39 RECENT OIL SANDS PUBLICATIONS ...... 3-52

IV.. COAL PROJECT ACTIVITIES

Great Plains Coal Gasification Project Underway ...... 4-1 SRC-I/TSL Commercial Plant Economics Presented ...... 4-I Exxon Adds New Partner for the Donor Solvent Project ...... 4-7 ENVIRONMENT

TVA Medium Btu Coal Gasification Demonstration Plant Draft EIS Released ...... 4-9 Final Report on Environmental Impact of Kaiparowits Coal Development Released ...... 4-14 NIOSH Assesses Health Aspects of Coal Liquefaction ...... 4-17 GOVERNMENT

DOE and EPA Reach Agreement on SRC-II EIS ...... 4-19 GAO Says DOE Needs to Develop a Methanol-from-Coal Program ...... 4-21 GAO Report Promotes Indirect Coal Liquefaction ...... 4-22 ENERGY POLICY & FORECASTS

Market Penetration of Methanol as a Fuel Is Projected ...... 4-25 TECHNOLOGY The British Gas Westfield Operations Are Described ...... 4-29 Enhanced Oil Recovery Is a Possible Use for Carbon Dioxide from Gasification ...... 4-31 Development of Gas Turbines for Use with Coal-Derived Fuels Discussed by GE Representative ..... 4-35 Enthalpy and Phase Equilibria Data for Coal Gasification Plant Designs Said to Be Inadequate ...... 4-36 CORPORATIONS Update on Westinghouse Coal Gasification Program Given ...... 4.33 Texaco Involvement in Coal Gasification Reviewed ...... 4-40 LAND to Federal Coal Lease Sale Be Held in January; Includes Small Business Set Aside ...... 4-43 DOE's Production Goals Criticized by the General Accounting Office ...... 4-49 Industry Also Critical of DOE's Coal Production Goals ...... 4-SI

UI

Green River-Mains Fork Final Environmental Impact Statement Released ...... 4-54 U.S. District Court Rules on Alluvial Valley Floor Issues ...... 4-57 Surface Mining Activity Reviewed ...... 4-58

WATER Water Assessment Report for SRC-II Published by Water Resources Council ...... 4-64 Resources for the Future, Inc. Reports on Water Rights and Energy Development in the Yellowstone River Basin ...... 4-67 STATUS OF COAL PROJECTS ...... 4-69 RECENT COAL PUBLICATIONS ...... 4-102

V. APPENDIX

Meeting Report: DOE/EPA-SRC-11 EIS ...... 5-1 Tennessee Valley Authority Draft Environmental Impact Statement Appendix B Waste Characteristics and Flow Diagrams ...... 5-5

iv HIGHLIGHTS The Newly-Created United States Synthetic Fuels Corporation is Becoming Operational President Carter, acting under authority granted to him by Article II, Section 2 of the U.S. Constitution, appointed a Chairman and five Board Members of the newly-created U.S. Synthetic Fuels Corporation. Carter acted because the U.S. Senate recessed without having confirmed the nominations he had submitted to the Senate, and because he desired to form the Corporation before the new administration takes office. Despite being created amidst controversy, and despite some doubts about its future existence under a new administration, the U.S. Synthetic Fuels Corporation is acting quickly to become operational. It issued a draft of its Initial Solicitations for Proposals for Financial Assistance for Synthetic Fuels Projects on October 31. We reproduce the Draft Initial Solicitation in this quarterly. Please refer to page 1-5. During November, the Corporation's board of directors approved the draft, making only one change - that being the addition of a requirement that applicants discuss the availability of water to meet project needs and the potential water quality impacts on other water uses. The Department of Energy has authority under the Energy Security Act to administer the "fast track" synfuels commercialization program during the interim period until the U.S. Synthetic Fuels Corporation becomes operational. In August, DOE issued Solicita- tions for Proposals for Financial Assistance of Commercial Synfuels Projects via Loan and Price Guarantees and Purchase Commitments. These solicitations are discussed in an article which begins on page 1-1 of this quarterly. The Environmental Protection Agency's Approach to Regulating the First Commercial Synfuels Facilities Are Reviewed In an article which begins at page 1-11 of this quarterly, we present a rather thorough review of the EPA's approach to regulating the first commercial synthetic fuels facilities. This includes a discussion of the on-going preparation, by EPA, of a series of Pollution Control Guidance Documents -- one such document for each of the major technologies. In reference to a recent decision issued by a U.S. Court of Appeals, the EPA no longer exempts fugitive dust emissions from being included in the Air Quality Review of any major stationary source. This development is discussed in an article which begins at page 1-13 of this quarterly. The Council on Environmental Quality Completes its "Global 2000" Report to the President The CEQ has completed a report, requested by President Carter, on probable changes in the world's population, natural resources, and environment through the remainder of this century. It is entitled "The Global 2000 Report to the President." A review is presented at page 1-27 of this quarterly. Concerning energy, the CEQ sees no early relief from the world's energy problems. It calls for a world transition away from petroleum dependence, but acknowledges that it is uncertain as to how the transition may occur. Per capita energy consumption is expected to increase everywhere.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 A-I HIGHLIGHTS Status of Major Permits for Oil Shale Projects Presented In October the Colorado Mined Land Reclamation Board approved a permit for Colony, the last major "go-no go" approval needed for construction and operation of a 48,300 BPSD plant. Union is fully permitted for a nominal 9,000 BPD plant. Our survey of major permit status appears on page 2-1. Rio Blanco Proposes Surface Mine for Lurgi Demo Oil shale for the Lurgi-Ruhrgas demonstration retort will be mined from a small, 20- acreopen pit located near the northwest corner of Tract C-a. Up to 9 million tons of overburden will be removed to permit the mining of 1.5 to 3 million tons of oil shale ranging in grade from 18 to 35 GPT. See page 2-1 for additional details. Paraho's Plans Are Reviewed Paraho is planning a 138' x 25' x 100' tall rectangular retort to produce 10,000 BPD. We discuss Paraho's other endeavors on page 2-4. Sohio, Cleveland-Cliffs, and Superior Exchange Land Holdings

Sohio has paid Cliffs $15 million for part of Cliff's interest in oil shale mineral rights on the southwest portion of Piceance Creek basin, the so-called Pacific property. Land exchanges have made Superior/Sohio/Cliffs co-owners of the Pacific property, where the Superior demonstration retort will now be built, and Superior's tract at the confluence of Piceance Creek and the White River. A discussion appears on page 2-6.

OX)' Petitions Colorado for Relaxed Air Standard Occidental has asked the State of Colorado to change its 502 standard of 0.3 pounds per barrel of shale oil produced. We review sc -ne of Oxy's testimony and industry reaction on page 2-13. Three Draft EISs on Oil Shale Issued Draft Environmental Impact Statments have been issued for Anvil Points, the Naval Oil Shale Reserves, and the USBM - Multi Mineral shaft at Horse Draw. Reviews appear on pages 2-15 and 2-18. DOE Inspector General Investigates LETC Programs The IG specifically investigated Oxy's cooperative agreement with DOE's Laramie Energy Technology Center. The three reports issued as a result dealt with project management, dissemination of technical information, and financial management in the Oil Shale Program. Our report begins on page 2-21.

A-2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 HIGHLIGHTS

Solvent Extraction Study Results Presented by National Research Council

The National Research Council of Canada has been studying the solvent extraction process as a substitute for the hot water separation process for tar sands. The solvent extraction process would eliminate the environmental problems associated with tailing disposal from the hot water process. The study found that solvent retention was influenced by the method of agglomeration, particle size distribution, moisture content of the agglomerates, water wettability of the mineral surface, and residence time in the agglomerator. Further details on the process can be found on page 3-20.

61' Canada Announces New Pilot Project In August, BP Canada announced plans for a $100 million in situ pilot project in the Cold Lake area of northern Alberta. The project will use in situ combustion and produce between 5000 and 10,000 barrels of oil per day. An application will be submitted to the Energy Resources Conservation Board in 1981 and a tentative start-up date is set for 1983. Information on the project can be found on page 3-6.

Leasing 6111 Dies in Senate

Although the McKay tar sand leasing bill (H.B. 7242) passed quickly through the U.S. House of Representatives, the bill ran into opposition in the Senate and was tabled. The bill ran into trouble over the definition of tar sand, lease terms and royalty conditions. In spite of the bill's demise, the Interior Department has stated that it will lift the moratorium on tar sands leasing and put into effect a system for evaluating the deposits in Utah for possible leases. A leasing program is expected to be in place approximately two years after the preparation of an environmental impact statement. Further details on the proposed program can be found on page 3-30.

Conoco Presents Details of Oil Mining Project

Conoco has completed a successful underground oil mining project in Wyoming, involving the driving of an adit into the side of Tisdale Mountain, located about 70 miles north of Casper, Wyoming. The adit intersected the pay zone, the Lakota Sand formation, at approximately 720 feet. A chamber was excavated at this point and a ventilation shaft drilled. Specialized horizontal drilling equipment was used to drill production holes into the Lakota. First year average production was approximately 68 barrels per day with expected production leveling out to around 40 barrels per day. A description of the project can be found on page 3-14.

Papers Presented on Hydrothermal Studies Two papers on hydrothermal studies of in situ oil sands operations were presented recently at the Symposium on Water-Rock Interaction in Edmonton, Alberta. In the first study on mineral transformation during in situ recovery of bitumen, core material from the Peace River, Wabasca, Cold Lake and Athabasca formations were treated with aqueous solutions of varying pH, salinity and temperature. This study concluded, among other things, that the bicarbonate content increased with temperature and pH and its relation to carbonate mineral content of the cores. The second paper outlined research

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 A-3 HIGHLIGHTS done in support of the Norcen Primrose pilot in Cold Lake. This study concluded that there was a definite post-steam increase in size fraction and gas production was observed in all hydrothermal experiments. Further details of the studies can be found on page 3-9. U.S. Department of Energy Tar Sand Field Experiment The U.S. Department of Energy's Laramie Energy Technology Center has recently completed the LETC TS-15 steam drive field experiment in the Asphalt Ridge property near Vernal, Utah. The project ran from April 1980 to September 1980 with a cumulative oil production of 990 barrels and water production of 6,000+ barrels. The experiment was conducted to determine the technical feasibility of injecting steam to mobilize Utah bitumen, to evaluate various injection and production well completions and to determine the feasibility of recycling produced water and using bitumen as fuel. Project details can be found on page 3-6. Cost of the Combustion Process in Utah Tar Sand is Projected In a paper presented by R. J. Barrett of the Laramie Energy Technology Center, the feasibility of using forward and reversed combustion technology for in situ thermal recovery of oil from Utah tar sand was examined. The overall dominant cost of the process is the cost of providing compressed air. Process costs for the project came to $25.20/bbl with a corresponding crude oil price of $39.00/bbl. Since this is a high price for crude oil, it is difficult to say whether the project would be economic. Calculations can be found on page 3-31. Environmental Regulations for Enhanced Oil Recovery and Tar Sands Discussed Two documents on environmental regulations relating to tar sand development and enhanced oil recovery have been published recently. The reports concentrate on U.S laws and regulations for the control or prevention of pollution from both processes. The reports address the combined effect of simultaneous development of both tar sand and oil shale and possible violations of air quality standards from a total industry standpoint. It is hoped that the tar sand industry can borrow extensively from control technology being utilized in both the mining and refining industries. A summary of the two reports appears on page 3-35. Canadian Government Impasse Shelves Oil Sands Plants The new budget and energy policy presented to the provinces by the Canadian Federal Government in October has brought progress on the new oil sands plants in Canada to a halt. The new policy emphasizes Canadian ownership of the oil and gas industry in Canada. Specifically, it places management of the natural resources in the hands of the Canadian Federal government at the expense of the provinces. In a retaliatory move, the Province of Alberta has shelved all consideration of the new oil sands plants and threatened to cut off oil exports to eastern Canada in an effort to get the Federal government to agree to a new oil pricing and energy development policy. Details on the controversy can be found on page 3-25.

A-4 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 HIGHLIGHTS

Great Plains Gets $1.5 Billion Loan Guarantee, but Negative Appeals Ruling

In a court ruling on December 8, the U.S. District Court of Appeals found that the Federal Energy Regulatory Commission was incorrect in its decision regarding the Great Plains Coal Gasification Plant. The ruling came too late to be reviewed in this issue, but will be included in the March 1981 Quarterly. The case before the Court is described on page 4-4 of the June 1980 Cameron Synthetic Fuels Report. Ground- breaking for the project began in July at the site in North Dakota. Subsequently, the design for the plant has been modified to include methanol production and the feasibility of producing carbon dioxide for enhanced oil recovery is being investigated. A review of these recent events begins on page 4-1.

Production of Carbon Dioxide from Gasification Plants Could be Used for Enhanced Oil Recovery

The American Gas Association commissioned a study of the use of carbon dioxide produced from high-Btu coal gasification for use in enhanced oil recovery. A review of the study on page 4-31 also included a detailed analysis of the amount of carbon dioxide available from the Great Plains Project.

Japanese Solidification Process Selected for SRC-1 Project Of particular interest regarding the product solidification of SRC-I is the selection of the water bath (Mitsui-Miike) alternative to be used in the Demonstration Plant designed by the International Coal Refining Company. The selection of the deashing and gasification process is also discussed in the article beginning on page 4-1. In addition, the economics of a 30,000 TPD Commercial plant using both high and low severity hydrocracking is also presented.

AGIP Joins the Exxon Donor Solvent Project

The Exxon Donor Solvent Project added another foreign partner, AGIP, to the program. An update of initial projects operation at the Donor Solvent plant begins on page 4-7. TVA Issues Draft Environmental Impact Statement for Medium-Btu Plant

The Draft Environmental Impact Statement for the medium-Btu plant that has the potential to be the first completed commercial coal coal conversion plant in the U.S. was issued by the Tennessee Valley Authority in August, less than a year after plans for the project had been announced. As a result of $2.7 million worth of design studies, the Texaco and Kopper-Totzek gasifiers were selected as the two candidate processes for further evaluation. Based on pilot plant testing in late 1980, one of these processes will be selected for the first module of the four module plants which is scheduled to begin operations in 1985. The draft EIS might well be a model for other plants and is reviewed beginning on page 4-9. The entire Appendix B from the Draft is reproduced in the Appendix beginning on page 5-5. Data concerning the waste characteristics of four gasifiers studied for the plant are given.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 A-5 HIGHLIGHTS Environmental Impacts of Development of Kaiparowits Coal Noted The 6LM recently published a study that summarizes the potential environmental impacts of various levels of coal development and various modes of coal transportation from the Kaiparowits plateau in Utah. While not an EIS, the study is important because of the possibility that the coal could be used for gasification in Southern California. The review of the study begins on page 4-13. NIOSH Assesses Health Aspects of Coal Liquefaction A recent report published by the National Institute of Occupational Safety and Health (NIOSH) concludes that coal liquefaction material contains potentially hazardous and biologically active substances and that the effects of exposure to these substances has not been documented. A review of the report beginning on page 4-17 include results of industrial hygiene studies at two liquefaction plants. DOE and EPA Roles in the Environmental Impact Statement Preparation Processes Examined The Solvent Refined Coal (SRC-I1) plant to be built near Morgantown, West Virginia has been the subject of much interest and controversy. DOE and EPA reached an agreement concerning the Draft EIS for the plant. The agreement is reproduced in the appendix on page 5-4. The EPA's action concerning the EIS and DOE's method of preparing the EIS are described in the article beginning on page 4-19. Another action concerning SRC-Il includes publication of the Water Resources Council Report for the plant at Morgantown which is described on page 4-64. Two GAO Reports Promote Indirect Coal Liquefaction The Energy and Minerals Division of the General Accounting Office (GAO) sent a letter to the Secretary of Energy this summer pointing out the lack of DOE policy for developing methanol-from-coal. The letter outlined the reasons that DOE needs to develop a program to promote alcohol fuels, but especially methanol from coal. Specific recommendations were made to DOE and are presented on page 4-21. The following article summarizes another GAO report "Liquefying Coal for Future Energy Needs." This report also stresses the importance of indirect liquefaction processes.

Methanol a Viable Alternative to Gasoline Badger completed a study for the DOE to determine the market for coal derived methanol fuel and methanol derived gasoline for use in simple cycle peaking gas turbines and passenger vehicles. The study is reviewed beginning on page 4-25. Included in the study was a detailed account of current demands and uses for methanol from traditional sources as well as a detailed analysis of the electrical utility industry and some of the problems it is facing.

A-6 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 HIGHLIGHTS

British Gas Westfield Test Results Presented

A description of the British Gas/Lurgi Slagging Gasifier development is presented on page 4-29. Results of the trial runs at Westfield are given and work for the Electric Power Research Institute is reviewed. A brief analysis of the gasifier is also contained in the article on the TVA's Draft Environmental Statement on page 4-9. Gas Turbines Developed for Use with Coal Derived Fuels

An overview of the development of gas turbines capable of utilizing coal derived gaseous and liquid fuels by the General Electric Company is presented in the article beginning on page 4-35.

Westinghouse Also Involved in Coal Gasification

The involvement of Westinghouse in coal gasification is contained in the article on page 4-38. A review of the projects using Westinghouse technology is also given.

Texaco Gasifier to be Used in Many Projects

Texaco has been developing the Texaco Coal Gasification process at the Montbello, California research laboratory. An update of Texaco's plans begins on page 4-40. Both equity and licensed projects are summarized.

Federal Coal Leasing Scheduled for January 1931

The Final Environmental Impact Statement for the Green River-Hams Fork Federal Coal Leasing Region was released in September. A review of the final EIS begins on page 4-54. Following release of the statement, Secretary of Interior Cecil D. Andrus announced in October, that the first coal lease sale to be made under the new Federal Coal Management Program would take place in January. A description of the tracts to be offered in the Green River-Hams Fork Region begins on page 4-43. The targeted leasing goals for this sale were highly critized by many including the General Accounting Office (GAO). A review of the GAO's criticism follows the article on the sale. A third article concerning the sale reviews the criticism by the ICF, Incorporated, of the projected leasing goals. The report by ICF is of significance since ICF developed the coal model used as the basis for the coal production goals. Interest in Synfuels is Increasing Rapidly

In this issue, there are more than 170 synthetic fuels projects (not all of which are in the U.S.) about which we report. A decade ago there were about 50 projects that we followed. Interest in synfuels is destined to continue to increase. As this issue was going to press, DOE announced its selection of 79 proposed projects (out of some 971 proposals it had received in response to a solicitation) for which it plans to award grants in support of feasibility studies for commercial-scale ventures. We have a national goal of achieving the production of synfuels equivalent to at least 500,000 barrels per day of crude oil by 1987 and at least 2,000,000 barrels per day of crude oil by 1992. The year 1992 is just eleven years away.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 A-7 ______1 T fl finds: general GOVERNMENT

DOE ISSUES PROGRAM SOLICITATIONS FOR Corporation at such time as the SFC issues its first PROPOSALS FOR FINANCIAL ASSISTANCE OF solicitation. Actually, all programs underway within COMMERCIAL SYNFUELS PROJECTS VIA LOAN & DOE under the interim program are to be tranferred to PRICE GUARANTEES AND PURCHASE COMMITMENTS the SFC anyway. On August 26, the DOE issued two draft program solicita- While there are differences between the draft and final tions for proposals to assist synthetic fuels production. versions of these solicitations, the changes are rather These were: minor, and are for clarification and for correcting typos. Program Solicitation for Proposals for Finan- More specifically, the types of financial assistance avail- cial Assistance under the Federal Non-Nuclear able through these solicitations consist of: Research and Development Act (P.L. 93-577), as Amended for the Development of Synthetic Contracts for purchases of, or commitments to Fuels. (Solicitation DE-PS60-81RA50480) purchase, synthetic fuels for Government use for defense needs; Program Solicitation for Proposals for Finan- cial Assistance under Title I, Part A of the Price guarantees through purchase commit- Energy Security Act (P.L. 96-294) for the ments in the event that the Government exer- Development of Synthetic Fuels Under the cises the right to refuse delivery of a synthetic Defense Production Act. (Solicitation DE- fuel and pays an amount by which the contract P560-81 R A5 0481) price exceeds the prevailing market price; and, Through these solicitations the Department of Energy is Loan guarantees to finance the construction of offering financial assistance for the construction and synthetic fuel production facilities issued in operation of alternative fuels projects through commit- conjunction with contracts to supply synthetic ments. As noted in the titles of the solicitations, this fuels for Government use for defense needs. financial assistance is being made available under two separate legislative authorities; the Defense Production The goal of this Solicitation is to expedite the construc- Act (as amended), and the Federal Non-Nuclear Energy tion and operation of commercial scale facilities for the Research and Development Act. production of synthetic fuels for national defense needs at the earliest time practicable and in a manner consis- These solicitations are part of the "interim" synthetic tent with commercial practices. fuels program established under the Energy Security Act (Part A) pending operability of the United States Syn- Proposers seeking financial support for synthetic fuel thetic Fuels Corporation, which will ultimately handle the projects need not propose that all of the products to be program, as provided in Part B of the Energy Security produced by those facilities comprising the project be Act. intended for sale to the Department of Defense. Syn- thetic fuel projects proposed should, in fact, be designed Projects to be supported under these solicitations are to suit the maximum potential of the technology used. limited to those which are essentially ready to begin the construction of commercial synthetic fuels production Synthetic fuel is defined in the solicitation as any solid, facilities. liquid, or gas or combination thereof, which can be used as a substitute for petroleum or natural gas (or any Prior to the issuance of these solicitations for applica- derivatives thereof, including chemical feedstocks) and tions for loan guarantees, price guarantees and purchase which is produced by chemical or physical transforma- commitments, the DOE had issued interim program solici- tion (other than washing, coking, or desulfurizing) of tations for proposals for feasibility studies and coopera- domestic sources of— - tive agreements. These earlier solicitations were described in the March 1980 issue (draft) and the June coal, including lignite and peat; 1980 issue (final) of the Cameron Synthetic Fuels Report, shale; at pages 1-2 and 1-50, respectively. tar sands, including those heavy oil resources where— The final solicitations for proposals for assistance for loan guarantees, price guarantees, and purchase commitments (a) the cost and the technical and economic was issued by DOE on October 15. Closing date was set risks make extraction and processing of a heavy as November 14, 1980, which allowed only one month's oil resource uneconomical under applicable time for response. This was done because of the need for pricing and tax policies; and accelerated progress on the interim program, as mandated by Congress. (b) the costs and risks are comparable to those associated with shale, coal, and tar sand Those companies which could not meet the response date resources (other than heavy oil) qualifying for still have the opportunity to approach the Synthetic Fuels assistance under section 305, of the Defense Production Act, as amended;

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 water, as a source of hydrogen only through Loan Guarantees for amounts in excess of $38 electrolysis. million are subject to Congressional disapproval in accordance with Section 305 (b) (3) of the Such term does not include solids, liquids, or gases, or Defense Production Act, as amended. combinations thereof, derived from biomass. For purposes of this Solicitation, loan guaran- For Purchase Commitments: tees are only available to recipients of purchase commitments or contracts for financing the No contract to purchase or commitment to supported synthetic fuel project. purchase with any person can exceed 100,000 barrels per day of crude oil equivalent of syn- General Considerations: thetic fuel. Each contract to purchase, or commitment to Prior to award of a contractor commitment to purchase, or to provide for loan guarantees any person which exceeds 75,000 barrels a day shall define the maximum liability to the crude oil equivalent, the President must submit Government under the contract, such maximum to the Congress notification of such proposed liability to be valued at the maximum potential contract or commitment to contract and the Government exposure on such contract at any proposed contract or commitment to contract time during the life of such project. and the proposed action is not disapproved by Congress. For purposes of section 102(2)(C) of the National Environmental Policy Act of 1969, no S No synthetic fuel may be acquired under the action in providing financial assistance pursuant authority of Section 305 of the Defense Pro- to this Solicitation shall be deemed to be a duction Act, as amended (and therefore under major Federal action significantly affecting the this Solicitation), unless it is determined by the quality of the human environment. Secretary of Defense that such synthetic fuel is needed to meet national defense needs and that No synthetic fuel project constructed pursuant it is not anticipated that such synthetic fuel to this Solicitation shall be considered to be a will be resold by the Government. Federal project for purposes of the application for or assignment of water rights. Purchases or commitments to purchase involv- ing higher than established ceiling prices shall not be made unless it is determined by the Secretary that supplies of synthetic fuel could SYNTHETIC FUELS CORPORATION WILL BE THE not be effectively increased at lower prices or MAJOR VEHICLE FOR ADMINISTERING SYNFUELS on terms more favorable to the Government. COMMERCIALIZATION PROGRAMS • Each contract or commitment topurchaseshall Congress, in its efforts to encourage and hasten develop- provide the right of the Government to refuse ment of synthetic fuels industries in the United States delivery of the synthetic fuel contracted for, first enacted the Interior Appropriation Act (P.L. 96- and for the Government to pay an amount equal 126) which established an Energy Security Reserve of to the amount by which the price for such $19 billion to stimulate commercial production of syn- synthetic fuel exceeds the prevailing market thetic fuels. This Act, its provisions, its Solicitation for price on the delivery date involved in a manner feasibility studies and cooperative agreements, and specified in the contract or commitment. selection of proposals to DOE from industry for assis- tance were discussed in the March, June, and September issues S Each contract or commitment to purchase syn- 1980 of the Cameron Synthetic Fuels Report. thetic fuel shall provide that the parties agree Responsibility under 96-126 were assigned to the Depart- to review and to possibly renegotiate such con- ment of Energy. Then, on June 30, President Carter tract within 10 years after the date of initial signed the Energy Security Act (P.L. 96-294), which production at the synthetic fuel project extended the Defense Production Act of 1950 to provide involved. additional financial assistance and created the U.S. Syn- thetic Fuels Corporation to oversee the program, after • Advance payments may not be made unless the Corporation becomes operational. Certain responsi- construction has begun on the synthetic fuel bilities for program control thus resided in the Depart- project involved or it has been determined by ment of Defense. the Secretary that all conditions precedent to construction have been met. Executive Order Clarifies Responsibilities of DOE and DOD in the "Interim" Synfuels Development Program S A contract or commitment to purchase syn- thetic fuel may be entered into only for syn- On September 30, 1980, President Carter issued Execu- thetic fuels which are produced in a synthetic tive Order 12242 which clarified the responsibilities of fuel project located in the U.S. the Departments of Energy and Defense in the admini- stration of the "interim" synthetic fuels program until For Loan Guarantees: the Synthetic Fuels Corporation becomes operational and can assume full responsibility for the various programs.

1-2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

Neither DOE nor DOD are assigned all responsibility for consideration no later than thirty days prior to the the interim period. The division of responsibilities is date on which it is to be transmitted to the defined from the Executive Order as follows: Congress. 11 1-101. The functions vested in the President by "1-109. No new awards for purchases or commit- Sections 305(0(1) and 305 (0(2) of the Defense ments for financial assistance shall be made under Production Act of 1950, as amended (50 U.S.C. the provisions of this Order after the date on which App. 2095 (f) (1) and (2)), are delegated to the the President determines that the United States Secretary of Defense. Synthetic Fuels Corporation is established and fully operational. That determination is to be made in 11 1-102. The Secretary of Defense shall, after accord with Section 305 (k) of the Defense Produc- consulting with the Secretary of Energy, determine tion Act of 1950, as amended (50 U.S.C. App. 2095 the quantity and quality of synthetic fuel which is (k)), and in accord with the appropriations to the needed to meet national defense needs from time Departments of Energy and the Treasury pursuant to time. This determination shall be made in to the Supplemental Appropriations and Rescission accord with section 305(0(1) of the Defense Pro- Act, 1980 (P.L. 96-304; 94 Stat. 857, 880-882). duction Act of 1950, as amended, and shall promptly be furnished to the Secretary of Energy. "1-110. No award for a purchase or commitment for financial assistance shall be mad& which would "1-103. In accord with Section 305(f)(1) of the preclude projects or actions initiated by the Secre- Defense Production Act of 1950, as amended, the tary of Energy under the provisions of this Order Secretary of Defense shall ensure that his deter- from being transferrable to the United States Syn- mination of the national defense needs for synthe- thetic Fuels Corporation. tic fuel does not include any synthetic fuel which the Secretary anticipates will be resold by the "1-111. Prior to issuing any loan guarantee under Government. the provisions of this Order, the Secretary of Energy shall obtain the concurrence of the Secre- 11 1-104. The functions vested in the President by tary of the Treasury with respect to the timing, subsections (bRl)(A)(i) and (ii), (c)(l)(B), (c)(3), interest rate, and substantial terms and conditions (d)(2), (d)(3), (d)(5), (d)(6), (e), and (g)(2)(C) of of such loan guarantee. In establishing an interest Section 305 of the Defense Production Act of 1950, rate, the current average yield on outstanding as amended (50 U.S.C. App. 2095), are delegafed to marketable obligations of the United States with the Secretary of Energy. comparable remaining periods of maturity shall be considered. To the extent practicable, the timing, 11 1-105. The Secretary of Energy, to the extent interest rate, and substantial terms and conditions practicable, shall apply laws regarding the procure- of such guarantees shall have the minimum possible ment of goods and services by the Government to impact on the capital markets of the United the terms and conditions contained in purchase States, taking into account other Federal direct contracts awarded under subsection (b)(1XA)(i) of and indirect securities activities." Section 305 of the Defense Production Act of 1950, As amended. The terms and conditions of these contracts shall be subject to the concurrence of the Secretary of Defense. U.S. SYNTHETIC FUELS CORPORATION GETS A CHAIRMAN, FIVE REGULAR BOARD MEMBERS, "1-106. The Secretary of Energy shall, after AND PLENTY OF CONTROVERSY consulting with the Secretary of Defense, exercise the functions delegated to him under Section 305 The United States Synthetic Fuels Corporation was born of the Defense Production Act of 1950, as into controversy on June 4, the date the Act was signed amended, in order to meet the national defense by the President. The Act provides that the Corpora- needs for synthetic fuel as determined by the tion's powers be vested in a Board of Directors. The Secretary of Defense. Board of Directors is to consist of a Chairman and six directors to be appointed by the President "by and with 11 1-107. The Secretary of Energy shall exercise the the consent of the Senate." The chairman and the functions delegated to him under Section 305 of directors are to serve seven-year terms. Initially, how- the Defense Production Act of 1950, as amended, ever,the directors serve staggered terms. One serves in a manner consistent with an orderly transition to seven years,one serves six, and one serves five, etc. the separate authorities established pursuant to the After the expiration of the intial term of each director, United States Synthetic Fuels Corporation Act of subsequent directors all serve seven years. 1980, as provided by Section 305(a)(1)(B)(iii) of the Defense Production Act of 1950, as amended. President Carter encountered difficulties in locating people he desired to serve as chairman of the SFC Board. "1-108. The Secretary of Energy, after consulting First there was Richard DeLauer of TRW who declined with the Secretary of Defense, shall prepare for the President's invitation to serve as chairman. Then the President's transmittal to the Congress the there were Erskine White (Textron), Gordon Ahalt (Ash- report required by Section 106 of the Energy land Oil), and Fletcher Byrum (Koppers Company). Security Act (Public Law 96-294). The proposed Byrum, it turned out, was a business advisor to presiden- report shall be submitted to the President for his tial candidate Ronald Reagan. Finally, the White House

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1.3 came up with the nominations of John Sawhill for ference Report on the Energy Security Act, specifically Chairman, and Frank Cary, Lane Kirkland, Cecil Andrus, guarded against recess appointments being made by the Frank Savage, John DeButts, and Catherine Cleary as President. Also, Dingell noted that the Board members directors. Frank Cary withdrew his name, leaving five met and acted, even though their appointments have not directors plus the chairman. yet been confirmed by the Senate. Dingell asked for response from Civiletti to a group of questions (para- The Senate, facing an impending election and a recess, phrased) which included: ran into problems in its efforts to confirm the Presi- dent's nominations. Republicans objected to the Demo- • What authority is there within P.L. 96-294 cratic Administration's efforts to choose the directors for the President to make recess appoint- with which a Republican President may have to work. ments? Western senators strongly objected to the lack of Western representation on the Board, despite the fact • What authority does the President have to that one appointee, Cecil Andrus, was once the Governor make recess appointments to a body which of Idaho. Westerners generally regard Andrus as having has not yet been constituted? compromised his position on Western matters, thuspre- judicing his ability to reflect the broad outlook necessary • Would provisions of sections 3345-3349 of to protect Western interests. The infamous reclamation Title 5, U.S. Code apply to appointment of water project "hit list" which emerged during Andrus' members of the Board of Directors of the tenure as Secretary of the Interior, was most unpopular SFC? If not, why not? to Western Senators. Also objectionable to many Sena- tors was the absence of any nominees from the energy • What is the legal status of the actions taken industry. by the SFC Board at the October 8th meeting? On October 1, Senator Hart placed a "hold" on further Senate action. Finally, the Senate recess (until the lame • If it is determined that the meeting was not duck session of Congress) came without Senate approval authorized, are the Board members liable for of the nominations. This however, cleared the way for damages, penalties, and criminal prosecu- President Carter to appoint whomever he chose, using tion? powers granted to him by the U.S. Constitution to make appointments during the time Congress is not in session. • Do you (Civiletti), pursuant to your responsi- Article II, Section 2 of the Constitution of the United bilities, intend to initiate any suit under States clearly states that "The President shall have Section 163(b) of the Act? power to fill up all vacancies that may happen during the Recess of the Senate, by granting Commissions which • May the Secretary of the Treasury legally shall expire at the end of their next Session." Under this purchase the obligations of the Corporation authority, on October 5, President Carter announced the (bonds) issued at the October 8, meeting? recess appointments of five members of the Board of Directors for the U.S. Synthetic Fuels Corporation. "I • Etc. am taking this action because the United States Senate failed to confirm these nominees before it adjourned last A somewhat similar letter was sent to SFC Chairman week," his announcement states. Andrus, of course, joins Sawhill requesting explanations and statutory basis the Board of Directors at the expiration of his term as supporting the SFC Board's actions. Secretary of the Interior. Board members appointed by Carter will have their term of office expire in late 1981. The SFC, its Board, and its Chairman, are all in some peril. They will continue to function, we believe, despite SFC Board Holds First Meetings—Representative Dingell the objection of Representative Dingell. Indeed, the Objects SFC has continued to function, as demonstrated by its issuance of its first Program Solicitation, which is At its first organizational meeting on October 8th, the discussed under separate heading. It's future under the SFC Board agreed to give John Sawhill a free hand in Reagan administration is a matter of conjecture. How- hiring a professional staff. Previously, the five Board ever. Chairman Sawhill continues his efforts to form the members had told the Senate Energy Committee that SFC, and has made the following appointments:. they disagreed with Sawhill's statement that the Board would serve only in an advisory role. The Board As vice presidents: members told the Senate they intended to play a big role in staff selection, decision making, and in running the • J. J. McAtee Corporation. • A. C. Haskell • R. C. Harris More controversy erupted on October 24, when Repre- sentative John Dingell, Chairman of the House Sub- As director of project management: committee on Energy and Power wrote identical letters • Larry Lukens to Benjamin Civiletti (Attorney General) and Elmer Stoats (Comptroller General) complaining that the SFC As manager of state and local government rela- Board of Directors was meeting and acting in the tions: absence of legal authority. Dingell noted that the legislative intent of Congress, as expressed in the Con- • Jim Monaghan ..,

1-4 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 SYNTHETIC FUELS CORPORATION ISSUES ITS FIRST for basic evaluation by the Corporation. Applicants SOLICITATION OF PROJECT PROPOSALS should adequately describe their financial resources and expertise for the project; their proposed project, includ- Section 127 of the United States Synthetic Fuels Cor- ing the technology and plant input and output, their poration Act of 1980 (Part B, Title I, Pub. L. 96-294) scheduling timetable and risks with respect to comple- directs the United States Synthetic Fuels Corporation to tion; their ability to deal with environmental considera- issue its first solictation for proposals from concerns tions and regulatory requirements; socioeconomic interested in the construction or operation, or both, of impacts; and their financing plan. synthetic fuel projects not later than the end of this calendar year. The Corporation has prepared a draft "In Phase One, the Corporation is not requiring proposals solicitation for applications for projects requiring finan- to meet detailed specifications. The Corporation wishes cial assistance and this initial solicitation was published to have the benefit of the experience and expertise of in the FederalRegister, Vol. 45, No. 213 (the October project sponsors. The Corporation recognizes that in 31, 1980 issue), at page 72374. Comments were reques- order to attain the goals set by Congress even with ted to be submitted by November 14, a very short time assistance from the Corporation, private sector commit- allowance. ments of capital and management and technological effort of a magnitude not previously attempted in the As discussed in the September 1980 issue of the Cameron United States are essential. To facilitate these commit- Synthetic Fuels Report, the Energy Security Act, which ments, the Corporation will be flexible and will co- created the U.S. Synthetic Fuels Corporation had two operate fully with project sponsors, financial institu- titles, Part "A" and Part "B". This solicitation by the tions, investment bankers and other private sector Synthetic Fuels Corporation comes under Part "B", and interests that are involved in synthetic fuel projects. signals that the Corporation is beginning to function as an "operational" entity. Part "A" of the Act set up a "In Phase Two, promising proposals selected under Phase fast-start interim program, and, under Part "A", the One for further evaluation will be invited to submit DOE has already issued several solicitations, which have detailed, supplemental technical, business and financial been discussed under separate headings. Some $5 billion information. On the basis of such submissions the were earmarked for the interim program, to be adminis- Corporation will decide whether to negotiate definitive tered by the DOE, and some $15 million are earmarked financial assistance. for use by the Synthetic Fuels Corporation as soon as it becomes operational. "Forms of Available Financial Assistance. The Corpora- tion offers, in order of priority, the following general Because of its importance, the text of the Initial Solici- categories of financial assistance; loan guarantees, tation of the Corporation, will be reproduced, as follows: price guarantees and purchase agreements; loans; and joint ventures. Financial assistance awarded by the "To All Interested Parties: The United States Synthetic Corporation is intended to encourage and supplement, Fuels Corporation invites the submission of proposals for rather than to compete with or supplant, private invest- financial assistance from concerns interested in the ment capital which otherwise would be available to a construction and/or operation of synthetic fuel projects, proposed synthetic fuel project. In order to qualify for in accordance with the United-States Synthetic Fuels assistance, a party submitting a proposal must demon- Corporation Act of 1980. The Act establishes a national strate the capability to undertake successful completion goal of achieving a synthetic fuels production capability of the design, construction and/or operation of the from domestic resources equivalent to at least 500,000 project, barrels per day of crude oil by 1987 and at least 2,000,000 barrels per day of crude oil by 1992. The "All proposals must meet the necessary conditions and Corporation will provide financial assistance, in conjunc- requirements of the Act before they may receive finan- tion with private sources of capital, to help attain these cial assistance, and interested parties should familiarize goals. themselves with the Act in preparing their proposals. Copies of the Act are available upon request. "The Corporation will carry out its responsibilities free of rigid, detailed procedural requirements and with max- "Factors to be Considered. Among the factors which imum flexibility. The Corporation encourages the sub- will be considered in awarding financial assistance to a mission of the broadest range of synthetic fuel projects particular proposal are the diversity of its technology involving a diversity of technologies. Proposals may from existing projects; the potential unit production request any one or more of the methods of financial cost; the long-term potential of the technology, consi- assistance which the Corporation is authorized to pro- dering the extent of the natural resources required and vide—loan guarantees, price guarantees, and purchase their geographic distribution; and the compliance of the agreements; loans; and joint ventures, in that priority. technology with applicable regulatory requirements. In addition, the Corporation is obligated to give due consi- "Submission of Proposals. This initial solicitation deration to promoting competition in the synthetic fuels consists of a two-phase process for the submission and industry. In the case of projects involving companies evaluation of proposals for financial assistance to syn- whose rates are regulated, the Corporation may consider thetic fuels projects. whether the rate-making agencies are likely to protect the financial interest of investors and the Corporation. "The Phase One, which will open December 1, 1980 and The Corporation will give priority consideration to pro- close March 31, 1981, interested parties are invited to posals to be sited in a state which will expedite regula- present proposals for all types of synthetic fuels projects tory, licensing and other governmental activities related to such project.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 - 1-5 'Address for Submission. Ten copies of each proposal world energy situation. As a result of the United States' should be submitted to the Corporation before March 31, initiative, the International Energy Agency (lEA) was 1981, addressed to: (Address omitted in Federal established in November 1974, within the framework of Register notice). the Organization for Economic Cooperation and Development (OECD). The original members were: "Public Summary. Each proposal should contain a Austria, Belgium, Canada, Denmark, Federal Republic of separate summary for public release and distribution to Germany, Ireland, Italy, Japan, Luxembourg, the Nether- interested parties as well as the Governors of the States lands, Spain, Sweden, Switzerland, Turkey, the United in which projects are to be located. Kingdom, and the United States. Australia, Finland, France, Iceland, New Zealand, Norway and Portugal "Questions concerning this solicitation may be submitted joined subsequently. to the Corporation at any time." lEA was organized into a Governing Board composed of United States Synthetic Fuels Corporation. one or more ministers or their delegates from each participating country; a Management Committee com- For the Board of Directors posed of one or more senior representatives of the government of each participating country; and a Secre- John C. Sawhill, tariat, which is the lEA's administrative body. Four Chairman standing groups and a committee were then formed in 1974 and 1975, each with a specific objective. The II II fill Standing Group on Emergency Questions was formed to take common, effective measures to meet oil-supply DOE SOLICITS PROPOSALS FOR ASSISTANCE FOR emergencies by encouraging self-sufficiency in oil COOPERATIVE AGREEMENTS AND FEASIBILITY supplies, restraining demand, and allocating supplies STUDIES OF SYSTEMS FOR DIRECT COMBUSTION among member countries on an equitable basis. The OF MINERALS AND ORGANIC MATERIALS Standing Group on the Oil Market was charged with promoting secure oil supplies on reasonable and equitable On November 5, 1980, the Department of Energy issued terms for member nations. The Standing Group on Program Solicitations for proposals from industry for Relations with Producer and Other Countries was formed financial assistance for feasibility studies and coopera- to promote cooperative relations with oil-producing tive agreements for innovative systems for the direct countries. Finally, the Committee on Energy Research combustion of minerals and organic materials, other than and Development (R&D) and the Standing Group on petroleum and natural gas, for energy production. Con- Long-Term Cooperation shared responsibility for ceivably, these solicitations could be of interest to reducing the dependence of member countries on im- developers of synthetic fuels projects. Recovery of ported oil by undertaking long-term cooperative efforts energy via combustion of spent oil shale may be an on conservation of energy, accelerated development of example. alternative sources of energy, and energy-related R&D. The Program Solicitation for grant application for feasi- The United States has been most actively involved in lEA bility studies is Number DE-PS01-81RA50535, and the activities conducted under the Committee on Energy and Program Solicitation for cooperative agreement pro- R&D. posals is Number DE-PSCA0I-81RA50536. Under the committee, member nations interested in Public Law 96-369, the Joint Resolution making continu- developing and conducting cooperative R&D projects ing appropriations for Fiscal Year 1981, which was establish working parties. Currently, 12 working parties recently signed by the President, expands the definition have been established: of alternative fuels for purposes of P.L. 96-126 and P.L. • Biomass Conversion 96-304 to cover this technology area. The sum of $30 • Fusion million is directed to be taken from the $300 million • Geothermal Energy appropriated under P.L. 96-304 for these feasibility • Coal Technology studies and cooperative agreements. Direct combustion • Energy R&D Strategy of urban waste is not covered under this solicitation. • Energy Conservation R&D • Hydrogen Production from Water Proposals for Feasibility Studies and Cooperative Agree- • Ocean Energy Systems ments for the direct combustion of urban waste are • Radioactive Waste Management eligible under the Program Solicitations No. DE-PS0I- • Small Solar Power Systems 80RA50412 and DE-PS01-80RA50413 which were issued • Solar Heating and Cooling on August I, 1980, and closed on September 30, 1980. • Wind Power. 'Ill/Ill The United States Participates in Various lEA Programs

THE lEA AND ITS INTERESTS IN SYNTHETIC FUELS Various United States agencies are participating in all 12 ARE EXAMINED of the working parties listed above. The United States was a signatory to 53 cooperative R&D agreements for In response to the oil crisis of 1973, the United States non-nuclear energy as of September 1979, including 35 urged the international community to develop a program agreements sponsored by lEA and 18 bilateral agree- of cooperative action for dealing with the changing ments. The United States has agreed to contribute in

1-6 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

the range of $100 million in support of the lEA agree- measurement, electrical resistivity, high fre- ments, which run from 2 to 8 years. quency electromagnetic, induction, passive acoustic, induced seismic and geotechnical One of lEA's primary objectives is to encourage member methods are included. The report is intended countries to reduce dependence on imported oil by to define the state of the art of reaction undertaking accelerated development of alternative zone mapping and to provide a reference sources of energy and energy research and development. document for all those interested in under- ground coal gasification. A comprehensive GAO Reviewed DOES Management Efforts in Coopera- list of published reports and papers and the live International Energy R&D in 1979 names and addresses of people associated with the development of reaction zone During 1979, the U.S. General Accounting Office re- mapping methods are included. viewed the Department of Energy's management efforts in cooperative international energy R&D and found a "Trace Elements from Coal Combustion- number of problems. These included the need for: Atmospheric Emissions." This is a technical review of the literature relating to trace • mechanisms to identify potential cooperative elements in coal combustion. Some data on international energy projects; trace element concentration in coal is pre- sented. Trace element behaviour and their • guidelines and criteria for determining a emission from coal combustion is studied reasonable level of U.S. contribution; from the point of view of atmospheric pollu- tion. Comparisons are also made with • opportunities for U.S. private sector compe- atomospheric emissions from other sources. tition; and Environmental effects and potential health hazards are discussed. The literature on • controls over the status of research and radioactive emissions and trace element development payments. accumulation around power plants is also reviewed. A brief summary is given of types To correct these problems, GAO recommended that the of equipment used for particulate control in Secretaries of Energy and State develop a clear policy power plants. The importance of coal com- statement and establish guidelines for U.S. participation bustion as a polluter will depend upon the in cooperative bilateral and multilateral energy research establishment of regulations for emission and development arrangements. control and on how far power plants comply with these regulations. A Coal Working Group Was Set Up Within lEA in 1975 "Methane Production in Coal Mines." This Particular member nations were asked to take the initia- report is a review of the published literature tive in organizing collaboration in the various fields of relating to the prediction of methane research and development and the UK was invited to emission into underground coal mine take the lead in establishing the Coal Working Group, workings. The retention of methane in coal covering coal technology, lEA Coal Research was set up and the methods of determining the methane in 1975. This at present covers five projects, an content of coal measures strata are experimental Fluidized Bed Combustion Plant; Economic described. The influence of mining and geo- Assessment Service; Technical Information Service; Data logical factors on the release and flow of Bank of World Reserves & Resources; Mining Technology methane are discussed. Methane prediction Clearing House. methods in use and under development in Belgium, France, FRG, Poland, UK, USA, and Coal Abstracts is a monthly abstracts journal produced the USSR are described and compared. The by the Technical Information Service of [EA Coal review is intended to define the state of the Research to give comprehensive world-wide coverage of art of methane prediction and to provide a all journal and report literature and conference procee- reference document for all those involved dings in the field of coal science and technology, from with coal mine ventilation. the mining of the coal to its ultimate use as a source of energy, including any environmental considerations. The following publications are available from lEA Coal Research at a cost of Li to organizations within member Several other publications are produced by the Technical countries, 1.10 to organizations in non-member countries. Information Service of lEA Coal Research. These A charge of LI is made for airmail postage outside include: Europe:

"Underground Coal Gasification--Reaction • Underground transport in coal 'nines Zone Mapping." This report reviews the published literature concerning the methods • Carbon dioxide and the 'greenhouse effect' of mapping the reaction zone during under- • Combustion of low grade coal ground coal gasification (UCG). The reaction zone mapping methods described relate pri- • Methane prediction in coal mines marily to the U.S. Department of Energy's • Hot gas cleanup UCG program. Mapping with temperature

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-7 • Trace elements from coal combustion-- The report contains convenient tables which show, on a atmospheric emissions country-by-country basis, the world's known reserves of • Underground coal gasification--reaction zone oil, gas, coal, oil shale, heavy oil, and hydro potential. mapping /111/11/ • Coal thesaurus 1978 (updated annually) • Serial title abbreviations 1979 (free with MISSOURI RIVER BASIN COMMISSION PREPARES Coal Abstracts, extra copies L2.50) WATER RESOURCES MANAGEMENT PLAN • Coal Calendar The Missouri River Basin Commission has published "Missouri River Basin Water Resources Management The address of the lEA Technical Information Service is: Plan."

Technical Information Service This report presents a water and related land resources lEA Coal Research management plan for the Missouri River Basin. The plan 14/15 Lower Grosvenor Place was prepared through the joint efforts of the 23 State, London SWIW OEX Federal, and interstate members of the Missouri River ENGLAND Basin Commission as well as numerous other water resource agencies. Appendix A of the report contains (I fl/Ill the draft environmental impact statement on the plan, which was prepared in accordance with the National WORLD BANK RECOMMENDS OIL IMPORTING Environmental Policy Act of 1969. DEVELOPING COUNTRIES EXPAND THEIR DOMESTIC PRODUCTION OF FUELS The purpose of the plan is to serve as a guide for the development, conservation, preservation, and manage- "Energy in the Developing Countries" is the title of a ment of water and related land resources in the Missouri recent report by the World Bank. After surveying the River Basin. Because the findings in the plan are the demand for energy and its management in developing product of extensive interagency and interstate coopera- countries and the countries' prospects for developing tion and collective judgement, they may also serve as a their own energy resources, the World Bank concludes guide for programming and budgeting for all levels of that expansion of domestic production of energy should government. The recommendations are intended to be the principal task of these countries in the 1980's. support the Congress, the Federal government, and States in programming, budgeting, and funding water The World Bank report notes also that in 1980, the oil resources programs and projects in the Missouri River importing developing countries will spend almost US$50 Basin. billion on importing oil. If their domestic energy produc- tion continued to grow no faster than in recent years The Commission has prepared a separate plan for each of (about 7 percent annually) their oil import bill (in con- eight subbasins in order to facilitate both the prepara- stant 1980 US dollars) would rise by 1990 to $110 billion, tion and presentation of the plan. Also included is a set a level which would add greatly to the difficulty of of basinwide and statewide recommendations which financing an already large external deficit. should be considered in close conjunction with any of the subbasin plans. Although the increase in the real price of oil has put considerable strain on the balance of payments of the oil The Commission's first basinwide plan was presented in a importing developing countries, it has also provided them report published in August 1977, titled "Missouri River with ample opportunities to tap energy reserves of oil, Basin Water Resources Plan." This is an update of the gas, coal, and hydroelectric and forest resources that 1977 plan. were previously regarded as uneconomical, or of mar- ginal value. By maximizing energy production between Copies of the new report are available from the Missouri now and the end of the decade, and by a vigorous River Basin Commission, 10050 Regency Circle, Suite program of energy conservation, the World Bank esti- 403, Omaha, Nebraska 68114. mates that these countries could cut their oil-import bill in 1990 by $25-30 billion (1980 dollars). "fl//Il World Bank estimates are that the total investment ENERGY SECURITY ACT ENCOURAGES needed for an expanded energy program in the oil PRODUCTION OF ALCOHOLS importing developing countries is $450 to $500 billion (in 1980 dollars) over the next decade. The financing of The Energy Security Act (P.L. 96-294) is an omnibus law such a program will make heavy demands on domestic containing eight separate titles dealing with a wide savings and external capital, including assistance from range of synthetic fuels programs and issues. A rather the World Bank. detailed description of the Act was presented in the September 1980 issue of CameronSynthetic Fuels Present plans call for Bank lending for energy in the Report in an article which begins at page 1-4 of that amount of $13 billion over the five-year period, fiscal issue. 198 1-85. This amount is, however, some $12 billion short of what is considered both desirable and feasible. The provisions in the Energy Security Act which encourage the production of alcohol are contained in

I-S CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Title I (Synthetic Fuels) and Title If (Biomass Energy and producing fuels from biomass feedstocks. Under Title II, Synthetic Fuels). $1.27 billion will be made available for financial assis- tance to alcohol production from biomass and to various Title I establishes the United States Synthetic Fuels municipal waste-to-energy projects. Corporation and provides $20 billion to the Corporation for financial assistance during its first four years of DOE and USDA Both Authorized to Issue Loan Guaran- operation. During the period of time before the Corpor- tees for Ethyl Alcohol Plants ation becomes fully established and operational, the DOE may commit $5.3 billion of these funds for "fast start" Subtitle A of Title II of the Energy Security Act provides synthetic fuels projects which utilize non-biomass feed- authorities for the Departments of Energy and Agricul- stocks. Included therein would be methanol-from-coal ture to offer loans, loan guarantees, price guarantees, projects and methanol from other non-biomass feed- and purchase agreements to encourage production of stocks, such as shale, tar sands, water (as a source of alcohol from biomass. The authorities of the DOE and hydrogen), and mixtures of coal and combustible liquids. USDA differ in accordance with the size of the proposed plants, as indicated in Table I. Most of the alcohol fuels provisions of the Energy Security Act are contained in Title II, which concerns

TABLE 1

TYPES OF ASSISTANCE AVAILABLE FOR ALCOHOL-FROM-BIOM ASS PROJECTS

Project Description Funding Agency Types of Assistance Available Funds Annual production capacity be- Department of Agriculture -loans up to $I million $525 million low IS million gallons and uses -loan guarantees biomass feedstocks other than -purchase agreements aquatic plants. -price guarantees

Annual production capacity of IS Department of Energy -loan guarantees $525 million million gallons or more and uses -purchase agreements biomass feedstocks; and all pro- -price guarantees jects (of any size) that use aquatic plants.

Annual production capacity of IS Either: -loan guarantees Any of the funds million gallons or more that (1) Department of Agriculture, -purchase agreements for USDA or use wood feedstocks, or (2) use or Department of Energy -price guarantees DOE shown above biomass feedstocks (other than aquatic plants) and are owned by cooperatives.

Municipal Waste-to-Energy Department of Energy -construction loans $220 million -loan guarantees -price support loans -price guarantees Office of Alcohol Fuels Established Within The Act imposed mandatory deadlines on both the DOE and USDA for soliciting, evaluating, and awarding finan- The Energy Security Act established an Office of Alco- cial assistance to alcohol fuels projects. These deadlines hol Fuels as an independent office within the Depart- are as follows: ment of Energy to administer DOE's financial assistance program for alcohol fuels production. Steps Deadline I) Issue Within 90 days of June 30, Farmers Home Administration to Administer USDA Pro- Solicitation 1980 gram Guidelines The Energy Security Act established the alcohol fuels 2) Solicit Within 30 days of comple- production within the Department of Agriculture, and Financial tion of Step I the program is expected to be administered by the Assistance Farmers Home Administration. It is possible, however, Applications that a separate "alcohols" office may be created within 3) Application Within 120 days of depart- USDA. Evaluation inent receipt of application & Funding Deadline Set for Awarding of Financial Assistance to Ethyl Alcohol Projects Decision

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-9 DOE Publishes Proposed Loan Guarantee Rules for Ethyl Alcohol Projects The Federal Register of August 14, 1980 contained DOE's proposed loan guarantee rules for alcohol fuel projects. These are the first rules promulgated by DOE to imple- ment those portions of the Energy Security Act (P.L. 98- 294) which concern the forms of financial assistance to alcohol fuel projects. Both the Department of Agriculture and the DOE are authorized under the Act to issue loan guarantees for alcohol fuel projects. The USDA is authorized to provide assistance to plants of less than 15 million gallons of ethanol per year. DOE is authorized to assist ethanol projects of larger capacity. The plants, however, must use wood, wood residues, or agricultural residues as the feedstock.

DOE's proposed rules were prepared in coordination with the USDA, and allow for voluntary applications to be submitted to DOE for loan guarantees. The U.S. National Alcohol Fuels Commission Will Go Out of Existence in December

There is a U.S. National Alcohol Fuels Commission, It was created by the Service Transportation Assistance Act of 1978 as an independent, temporary study group and task force to act in an advisory capacity to Congress in matters relating to the production of alcohol fuels. This Commission is not connected with either the DOE or USDA, and was created prior to enactment of the Energy Security Act. By December of 1980, the Commission will have com- pleted its final report to Congress. At the time that report is presented, the Commission will go out of existence.

1/ 1/1111

1-10 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 ENVIRONMENT

EPA'S APPROACH TO REGULATING FIRST important to maximize the air emissions control for each COMMERCIAL SYNFUELS FACILITIES REVIEWED facility.

In a paper entitled "The Permitting Process for New A no-discharge-of-pollutant concept is being considered Synfuels Facilities," Terry Thoem, Director of EPA's by several developers as a means of handling their Region VIII Energy Policy Coordination Office, presented wastewater streams. Three types of water should be first a thorough review of the permitting process and considered--mine, process, and in situ water. A no- second a good discussion of EPA's proposed approach to discharge-of-process-water concept has been written regulating the first commercial synfuels facilities. into water permits. If any water is discharged to surface Thoem spoke before the EPA Symposium on Environ- streams or reinjected into the groundwater system, it mental Aspects of Fuel Conversion Technology, which would consist of mine inflow (but not process or in situ was held in St. Louis during September. water) or uncontaminated surface runoff. Treatment may or may not be necessary. Effluent limitations will As described by Thoern, EPA's approach to regulating the be defined for certain pollutants including toxics for first synfuels facilities must ensure compliance with certain process streams in the NPDES permit. best existing standards, but, more important, should empha- available technology economically available (BATEA) size characterization of residuals from the facility. must be provided. Major concepts to be addressed by Rigorous testing programs and data analyses should be regulatory agencies and the developer are summarized as performed on the first facilities, which would be repre- follows. First, because of the semi-arid, water-short sentative of commercial size. Comprehensive moni- condition of potential development areas, it may be toring of emissions, effluents, and waste materials environmentally best to encourage treatment, if neces- should be performed. Research programs designed to sary, and discharge (to a surface stream) of mine water. define the optimum control technology for a given Second, because of salinity considerations, treatment of pollutant for a synfuels industry should be conducted. mine water and/or minimization of water consumption is Trade-offs among air pollution, water pollution, and solid a desirable policy. Third, disposal of process water onto waste must be defined. The energy penalty, water processed shale piles or ash piles without treatment may consumption, and cost of control must be defined. The not be desirable. The high organic and salt concentra- comprehensive monitoring efforts should not be limited tion of the process water may represent too great a risk to only the regulated pollutants, but should characterize to groundwater/surface water quality because of poten- nonregulated pollutants. tial catastrophic events or unexpected permeabili- ties/leaching, and they represent a deterrent to success- Emphasis should be placed on source characterization. A ful revegetation. Fourth, maximum recycling and reuse moderate degree of ambient impact monitoring should be of process and nonprocess water will be encouraged; cost performed to validate predicted impacts and to docu- effectiveness must be considered. Finally, land applica- ment frends and changes from baseline. Programs to tion of untreated mine water may be desirable only for a evaluate effects on receptors should be performed to short period of time because of the potential source provide feedback on the source and ambient monitoring runoff problems. programs. There are two principal bases for writing permits for synfuels facilities. The first relies upon the Solid and hazardous wastes should be disposed of in a transfer of pollution control technology from related manner that avoids contact with water and subsequent industries. The second relies upon the development of toxic concentrations. Disposal practices should also be EPA's Pollution Control Guidance Documents. designed that preclude (or at least minimize) the poten- tial for the solid material from becoming airborne as a The BACT for air pollutants must be employed for any fugitive dust. Safe disposal practices as defined at 40 proposed synfuels facility with the potential for emitting CFR 264 apply to synfuels facility hazardous wastes such 91 tonnes (ioo tons) or more (controlled) per year of any as spent catalyst, API separator sludge, tank bottoms, regulated air pollutant. Those facilities that have cooling tower sludge, and water treatment plant sludge. smaller potential emissions do not need BACT but should Surface disposal for solid wastes from a synfuels industry perform comprehensive monitoring in order to develop at a minimum should conform to those practices found in emissions data for potential permit applications. Two 40CFR 257. primary mechanisms exist to define the BACT. First, several synfuels facilties have received Prevention of Regulating new, presently non-existent energy indus- Significant Deterioration (P50) permits. The BACT has tries, of course, presents different problems from regu- been defined on a case-by-case basis for these facilities. lating long-standing segments of United States industry. Second, air pollution control technology that has been The differences are of such an extent that a unique defined as the BACT for synfuels-related facilities may regulatory approach is demanded. The differences arise be considered as transferable to the industry. It is highly primarily from the facts that the new energy industries likely that air quality requirements may prove to be the are, for the most part, not yet commercialized in the governing constraint to the size of the synfuels industry United States and have potentially different effluents in certain parts of the country. Therefore, in order to and emissions from those from existing pollution sources. maximize the amount of production capability, it is

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-lI Pollution Control Guidance Documents to be Prepared It should be noted that providing an early indication of EPA's concerns for various pollutants and options on There is little or no existing source of commercial-scale pollution limits will not just produce "passive reactions." data on which to base a conventional' regulatory On whatever information EPA provided, it will receive approach at this time. In some instances standards from feedback and criticism. By precipitating this feedback related industries may be borrowed. Because of these process while the energy technologies are still being circumstances, the general approach EPA is taking is to developed, many issues regarding environmental protec- issue, as pre-regulatory guidance, a series of Pollution tion should be resolved prior to construction and opera- Control Guidance Documents, (PCDG's), -- one for each tion. The advance notice of EPA's thinking will permit of the major energy technologies. The focal point of regulators, developers, and other segments of the public each PCGD is to be a set of recommendations on to work together to a greater degree than has been available control alternatives for each environmental possible in the past. discharge along with associated performance expecta- tions. The intent is to present guidance for plants of The specific energy technologies for which separate typical size and for each significantly different feed- PCGD's are now planned are the following: stock likely to be used. PCGD's will not have the legally binding authority of regulations but each will be Low Btu Coal Gasification reviewed extensively both within and outside of EPA. Indirect Coal Liquefaction These documents will provide useful and realistic guid- Oil Shale (mining and milling) ance to permit writers within EPA and the States and to Direct Coal Liquefaction the energy industry itself during its formative stages. Geothermal (first revision of existing PCGD) As the energy industry develops, permits for individual Medium Btu Coal Gasification installations are being issued based on best engineering High Btu Coal Gasification judgement and, as the various PCGD's become available, permits will be prepared in light of the information the Tables I and 2 provide the schedule for development of PCGD's contain. Then, as the energy technologies the various PCGD's. mature, EPA will invoke its normal regulatory proce- dures: in the water quality area, for example, the issuance of effluent guidelines and establishment of appropriate water quality standards. TABLE 1 The Pollution Control Guidance Documents, therefore, POLLUTION CONTROL GUIDANCE have two key purposes: (i) to aid permit writers in DOCUMENT REVIEW SCHEDULE preparing realistic, comprehensive permits for the energy industry by describing and characterizing pro- 1st Draft Public Final Technology jected waste discharges from the various energy techno- (data base) Forum Publication logies under development and by providing the best Low Btu possible information on the expected cost and perfor- Gasification Il/SO mance of the variety of control options that appear 4/81 S/SI applicable and (2) to provide guidance to the energy Indirect industry itself with regard to the kinds of environmental Liquefaction Il/SO 5/8I 9/8I impacts with which EPA will be concerned for their particular kind of facility, the control options which EPA Oil Shale Il/So 5/8I 9/8I has deemed to be potentially applicable, and EPA's Direct projections of probable cost and performance of the Liquefaction 9/8I 3/82 7/82 various options. High Btu The document will consist of three volumes. Volume I is Gasification 4/82 10/82 2/83 a summary report including recommended pollution con- Medium Btu trol technology options and related costs; Volume II is a Gasification 1/82 7/82 11/82 detailed report describing pollutants, waste streams, and alternative control options, including cost and perform- ance; Volume III is an appendix providing the data base for stream and pollutant characterization and control costs and performance. The major users of the PCGD's are expected to be the permit writers. For the developers, the PCGD's should influence the choices they have to make on control options and even on certain process alternatives. If industry and the other Federal and State agencies which directly support energy development are aware of antici- pated environmental problems and available control technologies, their development and plant design efforts can incorporate features which will help to avoid the necessity for future retrofitting of control technology.

1-12 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 2 adjacent processing facility will generally result in exceeding the PSD, Class I, and Class II increments for PROCESSES TO BE COVERED IN particulates. POLLUTION CONTROL GUIDANCE DOCUMENTS NOW UNDER PREPARATION This conclusion, of course, means that it generally would be impossible for most future processing facilities to • Low Btu Gasification locate next to the mine which provides the material (Single State, Atomospheric Fixed Bed) input. Haul roads suddenly become the major source of overall plant emissions, and, even using BACT on the - Riley-Morgan mining operations, it may now be impossible for mine- - Wilputte-Chapman mouth projects to cortly with the current PSD Class II - Wellman-Galusha increment of 19 pg/m

• Indirect Coal Liquefaction In addition to deleting the former "fugitive dust exemp- tion," the new (final) regulations published in 45 FR Gasification Synthesis 52676 also:

- Texaco Coal-To-Methanol Redefine fugitive dust emissions as being - Lurgi Mobil 'M" (Methanol for those emissions released directly into the Gasoline) atmosphere which could not reasonably pass - Coppers Totzek Fischer-Topsch through a stack, chimney, or other function- ally equivalent opening. • Oil Shale Redefine a PSD (stationary) source as being a - TOSCO II grouping of all pollutant emitting activities - Paraho at one location, owned by or under the con- - Union trol of the same person(s). - Superior - Occidental Delete the "50-ton exemption" for both non- - Rio Blanco attainment and PSD.

• Direct Coal Liquefaction The Clean Air Act comes up for congressional review next year, hence many aspects of plant siting require- - H-Coal ments may change. - SRC - Exxon Donor Solvent f/I/fl II

1/1/ fl/l OSHA TO CREATE A STANDARDS ADVISORY COMMITTEE ON SYNTHETIC FUELS EPA NO LONGER EXEMPTS FUGITIVE DUST FROM BEING INCLUDED IN AIR QUALITY REVIEW FOR The National Advisory Committee on Safety and Health PSD PERMIT (NIOSH) has recommended to Eula Bingham (Assistant Secretary for Occupational Safety and Health, U.S. In response to the decision of the U.S. Court of Appeals Department of Labor) that a special subgroup be formed for the District of Columbia Circuit in Alabama Power to address safety and health concerns associated with Company vs. CoMic, the EPA has amended its regula- synthetic fuels production. Ms. Bingham has informed us tions by deleting the former exemption of fugitive dust that the suggestion is being followed and the subgroup emissions from being included in the Air Quality Review will be formed in the near future. of any major stationary source. Herewith is the recommendation of NACOSH for Formerly fugitive dust emissions of the type created by creating the Synthetic Fuels Advisory Committee: large-scale mining and earth-moving equipment opera- tions were exempted from being included in the Air "The energy crisis has created major pressure for Quality Review process. The former PSD regulations the development of synthetic fuels and other alter- may be found at 43 FR 26388. native energy technologies. We are concerned that a war-time psychology might develop--and, in fact, On August 7, the EPA (45 FR 52676) amended its might well be necessary to rapidly advance this regulations so as to delete this exemption. This deletion technology--without appropriate regard for health poses serious problems for operations which utilize haul and safety measures that should be implemented. roads for transport of mined rock from the mine to the It is imperative that an accelerated effort to processing plant. These problems were examined in a develop these technologies be accompanied by all study conducted for the EPA by Energy and Environ- necessary measures to minimize health and safety mental Analysis, Inc., and published in March of 1980. risks. In other words, a fast-track approach to the Entitled "The Impact of Including Fugitive Emissions development of new energy technologies must be from Mining Operations on Contiguous Processing Facili- accompanied by a fast-track program for assuring ties," the study concludes that the inclusion of mining workers' health and safety. fugitive dust emissions in the air quality review of an

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-13 The interagency committee on health and environ- and tar sands resources. The EPA is currently putting mental effects of energy technologies has docu- together a list of the projects proposed for the region. mented specific hazards. Previous OSHA involve- ment in developing the coke oven standard suggests Apparently concerned by Congress attempts to get the a similarity between the carcinogens generated in development of a commercial synthetic fuels industry coking coal and those generated by many of the established quickly, EPA's Regional Administrator Roger synfuels processes. By analogy we know that some Williams assured the attendees that energy development of the synfuel processes will also be "carcinogen in the West cannot and will not take place in lieu of rich" environments. Hence, a critical issue in adequate environmental safeguards. "It is not necessary developing synfuels is the timely implementation to move forward at break neck' speed," he continued, of adequate process and control technology. In so claiming that, "...it is likewise not necessary to over- far as possible, this process and control technology haul our environmental authorities and programs, that should be anticipated and "built-in" to new plants, some would suggest." Williams seems to be saying that not retrofitted at a later date. A control techno- despite Congress attempt to develop programs for "fast- logy based upon "no exposure" to carcinogens, i.e., track" establishment of commercial synthetic fuels faci- a closed system, must be mandated for these lities, EPA will not move at a speed which that agency processes in order to prevent employee exposure. considers "break neck."

"Thus, with regard to pending legislation, it is WESTPO's Chairman Addresses EPA Meeting on Subject critical that OSHA's authority to require that of Responsible Energy Development in the West introduction of control technologies at the developmental stages of alternative energy sys- Wyoming's Governor Ed Herschler, Chairman of the tems be maintained and strengthened. Western Governor's Policy Office (WESTPO), proposed a blueprint for the responsible development of energy in "Because of the multifacetted complexity, the the west. He pointed out that the Act which established potentially hazardous nature and projected size of the Department of Energy also allowed the Governors to this industry, we recommend the chartering of a appoint Regional Energy Advisory Committees. The Standards Advisory Committee to OSHA and Governors appointed themselves as the advisory NIOSH on synthetic fuels and other alternative committee to DOE so that regional coordination could be energy technologies. Among the issues which pursued at the highest level among the states. He asked should be addressed by such a committee would be that the Federal government follow suit and form a the institution of a universal, uniform, long-term cabinet-level council to meet with the WESTPO system of health and environmental monitoring and governors at least annually. the establishment of a national registry of workers. OSHA and NIOSH ought to aggressively avail them- In total the following eight-point cooperative synthetic selves of information available to DOE, EPA and fuels strategy was proposed by Herschler: other agencies with responsibilities for developing energy technologies. "First, the WESTPO states have already agreed to develop individual synthetic fuels plans as well as a "It is critically important that both NIOSH and regional plan to accelerate development. OSHA become deeply involved and assume major responsibility for shepherding development of these "Secondly, synthetic fuels development must be new technologies in a manner that will minimize phased or paced so that impacts within the states the occurrence of adverse health and safety and region can be avoided and so that resources effects. In this regard, these agencies should such as water and skilled labor can be optimized. immediately request the additional manpower and resources "Third, the states should continue to be primarily responsible for developing and enforcing environ- II I/I//, mental regulations as well as allocating resources. Attempts to circumvent state laws, for example, EPA CONTENDS THAT WESTERN ENERGY simply invite lengthy court delays. DEVELOPMENTS NEED NOT MOVE FORWARD AT "BREAK NECK" SPEED "Fourth, the WESTPO states have agreed to intensify their efforts to expedite and streamline The Environmental Protection Agency's Region VIII held the permitting of key energy facilities. a conference in Denver on October 8 and 9 on the subject of "Environmental Regulation Relating to "Fifth, we should agree at the onset that federally Energy.' A review of each EPA regulation which may assisted synfuels projects be given adequate finan- have an effect on energy industries was given. The cial assistance to incorporate the best available conference was designed to deal with the large number environmental controls. We must not compromise of new and proposed regulations that have been promul- primary health standards. gated since May 1980. The conference was particularly important because of the magnitude of the energy 'Sixth, however, we must have the flexibility to resources in the region. As Roger Williams, Regional modify some environmental standards, particularly Director of the EPA Region VIII pointed out, the region those that are based on aesthetic values such as has 50 percent of the nation's coal and uranium resources EPA's visibility standards. and essentially all of the nation's recoverable oil shale

1-14 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 'Seventh, we must develop a way of internalizing a BLM PUBLISHES FINAL GUIDELINES WITH REGARD portion of the community costs within the project To "AREAS OF CRITICAL ENVIRONMENTAL costs of a synfuels plant. In this manner the same CONCERN' financial safety net which the Federal government is offering the oil companies can be extended to The U.S. Bureau of Land Mangement has published its our communities. final guidelines with regard to Areas of Critical Environ- mental Concern (ACEC). The final guidelines appear at "Finally, I propose the establishment of a Federal, pages 57318-57330 of the August 27, 1980 issue of the cabinet-level coordinating council to meet with the FederalRegister. Formulation of such guidelines was WESTPO governors on a regular basis in order to mandated by the Federal Land Policy and Management better coordinate Federal/state actions in the Act of 1976 (43 USC 1701 et seq.). These final guide- development of synthetic fuels." lines will be incorporated into regulations and also will be combined with more specific policy and operational Second Day of Conference Devoted to Regulations procedures as a part of a Bureau of Land Management manual. The guidelines relate to the following basic The second day of the conference provided discussion on concepts: information requirements and the review criteria asso- ciated with individual permit applications for the • Protective Management Policies Apply to All following: coal fired power plants, coal mining, syn- Public Lands. thetic fuels, and uranium mining/milling. • ACEC's Are Special Places Within the Public The session concerning synthetic fuels began with a Lands. discussion of the requirements for an Environmental Impact Statement. Wes Wilson presented the steps in • The ACEC Process is Part of Multiple-Use the Federal Decision Making (see the article concerning Management. the SRC-lIl EIS for a detailed description of developing an EIS). • Development May Occur in Some ACEC's. He cited 40 CFR 55978, the revised Council on Environ- • Each ACEC's Special Management Require- mental Quality EIS guidelines, as designed to reduce ments Are Site-Specific. paper work in an attempt to reduce the size of the EIS from 150 to 300 pages, but he stressed that important • The ACEC Process is Part of the Planning issues must still be emphasized. Alternatives analysis is Process. the heart of the EIS and the EPA is encouraging a third party approach where expert technical assistance should • Identification and Designation are Separate be sought, particularly in developing mitigating Steps. measures. In much the same light as Scheckless testi- mony regarding the SRC-II EIS before the House • An ACEC Designation Constitutes a Manage- Committee, Wilson also insisted that a wide variety of ment Commnittment. alternatives--not just similar technology, but even possibly competing technology such as OTEC or Biomass • ACEC Designation May Complement Other should be addressed. He also insisted that the alterna- Forms of Management. tives of conservation and no action must also be addressed. • Public-Interest Determination Are Required for ACEC Designation and Revision. The conference addressed all of EPA's alphabet soup from P50 regulations, NPDS's regulation, the visibility • Opportunity for Public Involvement Is program and RCRA. Perhaps the RCRA (Resource Provided at Each Step. Conservation and Recovery Act) discussion gave industry participants the most pause. This Act was recently 1/1/111/ revised under a re-authorization bill passed in November. Not only is the program still in the formation stages and DOE'S ENVIRONMENTAL ADVISORY COMMITTEE constantly in a flux, but those aspects that are defined DISCOVERS OIL SHALE, DISCUSSES SRC-II EIS need to be given special consideration by anyone interested in synthetic fuels development. 40 CFR 265 An Environmental Advisory Committee (EAC) has been gives the regulations for operating an onsite hazardous established to advise DOE's assistant secretary for the waste facility. In the case of most synthetic fuels environment (EV) on a broad range of topics. The EAC plants, this might well be the most economical and least and a synfuels subcommittee met in Denver and toured complicated method of conforming with the Act. the oil shale region in October. Much of the meetings addressed the SRC-II draft environmental impact state- ////#11 ment (EIS). The discussion gave rise to five recomnmen- dations applicable for all synfuet demonstration projects. It was advised that DOE should commit to: (I) "demon- stration and application of the most advanced and effec- tive environmental control technologies in demonstration Plants;-' (2) "compliance with all existing environmental regulations;" (3) monitoring to assess the performance of

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 I-IS environmental control technology; (4) "forecasting envi- The composition, approach, and direction of the EAC are ronmental laws and regulations which may be violated in much different from the Department of the Interior's Oil scale-up to full commercialization; 11(5) completion, prior Shale Environmental Advisory Panel (OSEAP). OSEAP is to commercial production, of an EIS which evaluates the primarily composed of representatives from various results of the demonstration and projects the full government agencies plus two environmental and two impacts of commercialization. In addition, the industrial representatives. EAC has no Federal repre- committee resolved that DOE should meet all National sentation, as illustrated by the membership list in Table Environmental Policy Act requirements and address all 1. OSEAP offers advice to the Area Oil Shale Supervisor public comments in the final EN for SRC-11 and give the on specific environmental matters in the Federal proto- EV secretary time for review. Oil shale briefings were type leasing program. EAC's advice to DOE is more in presented by representatives from Rio Blanco Oil Shale the form of internal procedural and policy recommenda- Company (Tract C-a), Friends of the Earth, and the tions. For example, Jonathan Gibson of the Sierra Club University of Colorado Oil Shale Task Force, which pushed through a resolution urging DOE to lengthen the performs much of EV's environmental research. review and comment period for draft EISs from 30 days to 60 days; the resolution is obviously self-serving.

TABLE I EAC MEMBERSHIP LIST, OCTOBER 1980

Mr. T. William Booth, Chairman *Mr. lames E. Monaghan Ralph D. Anderson & Partners/ Assistant to the Governor Booth and Koch (Architects) Denver, Colorado Seattle, Washington Dr. Eugene P. Odum *Ms. Merilyn B. Reeves, Vice Chairman Callaway Professor of Ecology & Natural Resources Coordinator Director, Institute of Ecology League of Women Voters U.S University of Georgia Laurel, Maryland Athens, Georgia Mr. Alan W. Beringsmith Mr. Barney Old Coyote Economist and Assistant to Vice Bozeman, Montana President - Rates & Valuation Mr. Edward L. Pastor Pacific Gas & Electric Company Supervisor, District 5 San Francisco, California Maricopa County Board of Supervisors Mr. Jackson B. Browning Phoenix, Arizona Corporate Director Mr. Paul R. Shoop Health, Safety & Environmental Affairs International Representative Union Carbide Corporation International Brotherhood of New York, New York Electrical Workers Mr. Brant Calkin Washington, D.C. Sierra Club *Dr. Howard Slack Southwest Representative Vice President - Technology - ARCO Santa Fe, New Mexico Los Angeles, California Mr. Ellis Cose Mr. Gregory A. Thomas Detroit Free Press Natural Resources Defense Council, Inc. Attn: Editorial Page San Francisco, California Detroit, Michigan Mr. Roger R. Wallis *Mr. Jonathan Gibson Deputy Director, Standards and Regulations Sierra Club Texas Air Control Board Washington Representative Austin, Texas Washington, D.C. Mr. Robert W. Welch, Jr. *Mr. Joseph S. Ives, Jr. Vice President, Environmental Affairs Environmental Counsel Columbia Gas System Service Corp. National Rural Electric Wilmington, Delaware Cooperative Association Washington, D.C. Mr. Ivan W. Wyatt Vice President, Kansas Farmers Union Mr. Thomas L. Kimball McPherson, Kansas Executive Vice President National Wildlife Federation *Ms. Louise B. Young Washington, D.C. Winnetka, Illinois Dr. Merle Lekoff SUN/REP Atlanta, Georgia *Members of the synfuels subcommittee

1-16 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Another resolution passed by the EAC urges DOE to Staffing constraints at the State level are a fact of life. prepare a programmatic EIS addressing the entire These problems are magnified by delayed and uncertain Federal synthetic fuels program, including future actions Federal funding as well as EPA paperwork or reporting that may be taken by the U.S. Synthetic Fuels Corpora- requirements. Consistently late annual program grants tion. This action would circumvent the specific exemp- result in termination or threatened termination of State tion from EIS requirements provided by the Energy employees and delays in filling badly needed positions. Security Act, which established the Corporation and amended the Defense Production Act to include synthe- Nearly all environmental programs have been affected to tic fuels. A related article appears in the Coal Section some extent by EPA's late issuance of regulations. State of this report which discusses the agreement between officials identified this as the greatest single obstacle to DOE and EPA resulting from concern over the SRC-II the management of their programs. As a result, State draft EIS preparation. DOE is performing the tasks of implementation of programs has been erratic, confused, the Synthetic Fuels Corporation on an interim basis. and slow; legislative deadlines have been missed and extended; and the credibility of some State programs has One EAC resolution emerged as a result of the been hurt. committee's tour of the oil shale region. It advises DOE to adopt, as a matter of policy, socioeconomic impact They identified the inflexibility of EPA regulations as mitigation by providing front-end community funding and the second greatest obstacle to program management. ensuring that phased and paced development occurs. To these State officials, the price of inflexible national regulations is wasted State resources, stifled initiative, I/I/fill and unnecessary increased costs for environmental control. GAO NOTES AN UNEASY PARTNERSHIP EXISTS BETWEEN EPA AND THE STATES IN To improve the EPA-State partnership, the GAO recom- ADMINISTRATION OF ENVIRONMENTAL PROGRAMS mended that the EPA Administrator should establish, as a high priority and in conjunction with State representa- In a report to the Congress by the Comptroller General, tives, a formal program to improve the partnership. the General Accounting Office recommends that the EPA move to strengthen its shaky partnership with the I/I/fill States. The report (CED-80-I06), is entitled, "Federal- State Environmental Programs: The State Perspective." The GAO claims that nearly three-fourths of State environmental officials believe that EPA headquarters staff does not understand the obstacles States face, both individually and collectively, when trying to implement EPA directives. A total of 66 percent of these officials believe that lack of understanding hinders the effective- ness of their programs. As a result, hostility permeates much of the relationship between the States and EPA. State officials believe that EPA does not trust the States, as evidenced by EPA's total control over their programs through regulations, guidelines, and grant con- ditions. Much of the problem is said to stem from poor communication. Most troublesome to the States and probably the root cause of many program management obstacles identified by the States is the overwhelming perception by State officials that EPA ignores their comments on matters directly affecting their programs.

When State officials or their representatives were directly involved in the actual development of regula- tions and guidelines, they were generally pleased with the practicability of those documents. Conversely, when they did not have input, they were critical of many of the regulations, guidelines, and policy memorandums.

In contrast to their relationship with EPA headquarters staff, States generally had good relationships with EPA regional staffs. They cited the key ingredients as good communications and interaction between States and regional people who jointly pursued environmental goals. The State's criticism, however, arises not because controls exist, but because of their excessive detail and inflexibility.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-17 ENERGY FORECASTS

TENNECO PROJECTS U.S. ENERGY PROFILE Energy conservation will have some impact on the level THROUGH THE YEAR 2000 of energy demand. However, the tendency to resist rapid changes in lifestyles along with the existence of in- In mid-1980 Tenneco published a booklet entitled place plants and facilities dependent on specific fuels "Energy: 1980-2000" which, accompanied by a second are factors which limit significant changes in energy booklet entitled "Energy Book Backup Data," projects consumption patterns in the near term. - the United States energy profile through the year 2000. Copies of the two publications are available from the Tenneco's data concerning the consumption of primary Long Range Planning Office of Tenneco Gas Trans- energy in the U.S., by consuming sector, for the period mission Company, P.O. Box 2511, Houston, Texas 77001. 1965-2000 are presented as Table 2. The objectives of the booklets, in addition to presenting U. S. Energy Supplies That Can Reasonably Be Expected the U.S. energy profile through the year 2000, are to Are Examined demonstrate the relationship between energy require- ments and GNP and to show that continued high levels of The percentage composition of the United States fossil oil imports will be required to sustain the U.S. fuel base will change between now and 2000 as coal resources are developed. The rate of development for Gross National Product and Energy Consumption Re- coal reserves is projected to increase. quired Are Both Forecasted to Decline Nuclear power is projected to contribute about 10 per- U.S. economic growth, as measured by real GNP, is cent of the total United States energy requirement by forecast to decline from 2.3 percent per year today to 2000. However, the significant growth barriers already about 1.8 percent by the year 2000. The growth in noted must be overcome in order for this estimate to be energy required to fuel this economic growth is forecast realized. to decline to 1.0 percent per year by the end of this century. Imported oil will continue to supply about 20 percent of total United States energy requirements until the 1985- In the future, higher prices and conservation will reduce 87 time period. Thereafter, rapidly increasing oil prices energy requirements per unit of GNP. The slope of the and increasing competition for the world's oil supplies line may change over time due to higher prices and will hold U.S. oil imports at about the IS percent level conservation, but a definite relationship will continue. for the remainder of the century. If the premise that the U.S. will not tolerate a "no- The mix of fuels cannot be changed quickly because the growth" economy is accepted, then increases in GNP will transportation and distribution facilities for other energy require an increasing supply of energy. sources do not exist--much less the equipment to utilize them. Tenneco believes that although the energy/GNP ratio is generally trending lower, an underlying relationship will Tenneco's data concerning the types of fuels which will continue to exist, because there are limits to the amount constitute the U.S energy supply during the 1965-2000 of energy that can be saved through conservation and period are presented as Table 3. technical efficiencies. Tenneco's data for U.S. Energy vs GNP for the years 1920 through 1985, plus projections #1111/I for 1990, 1995, and 2000, are presented as Table 1. Consumption of Primary Energy in the U.S. Will Increase by About 28Per the Next 20 Years The projected consumption of primary energy in the United States indicates that electric power generation will continue to be the dominant user of primary energy. The transportation and industrial sectors rank second and third, respectively, in total primary energy require- ments. The power plant sector will become a more dominant user of primary energy. This will occur since more coal and nuclear power will be utilized, and both of these fuels are well suited for the generation of electrical power.

1-18 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE I

U.S. ENERGY VS. GNP (1958- $)

Energy Energy Energy Year QBtu GNP Year QBtu GNP Year QBtu . GNP 1920 19.8 140 ------

1921 16.4 128 3951 36.9 383 1983 79.9 944 1922 17.2 148 1952 36.6 395 1982 81.4 966 1923 21.7 166 1953 37.7 433 1983 81.9 990 1924 20.5 166 1954 36.4 407 3984 82.5 1013 1925 20.9 179 1955 40.0 438 1985 83.5 1038 1926 22.5 190 1956 42.0 446 1927 21.8 190 1957 41.9 453 1928 22.4 191 1958 41.5 447 1929 23.8 204 1959 43.4 476 1930 22.3 184 1960 45.0 488 1990 90.5 1170 1931 18.8 169 1961 45.6 497 1932 16.4 144 1962 47.6 530 1933 16.0 142 1963 49.6 551 1934 17.9 154 1964 51.5 583 1935 19.1 170 1965 54.6 618 1995 96.5 3275 1936 21.4 193 1966 57.4 657 1937 22.8 203 1967 59.7 673 1938 19.9 193 1968 63.0 707 1939 21.6 209 3969 66.5 725 1940 23.9 227 1970 69.5 720 2000 101.5 1385 1941 26.6 264 1971 70.2 742 1942 27.9 300 1972 72.7 790 1943 30.4 337 1973 75.9 832 1944 31.8 361 1974 73.8 803 1945 31.5 355 1975 72.3 790 1946 30.5 313 1976 75.8 838 1947 32.9 310 1977 78.3 879 1948 34.0 324 1978 79.7 935 1949 31.6 324 1979 79.1 936 1950 34.2 355 1980 79.5 920

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-19 TABLE 2 CONSUMPTION OF PRIMARY ENERGY IN THE U.S BY CONSUMING SECTOR (QBtu) Power Transpor- Raw MatI. & Total Year Residential Commercial Industrial Plant tation Military Miscellaneous 7.52 54.60 1965 7.42 3.03 12.08 11.12 12.47 0.96 9.11 69.51 1970 8.56 4.12 13.80 16.67 16.40 0.85 8.37 4.25 14.49 19.85 18.41 0.78 9.75 75.90 1973 9.22 73.80 1974 8.06 4.01 13.85 20.14 17.75 0.77 3.87 12.01 20.49 17.93 0.75 8.89 72.09 1975 8.15 75.80 8.49 4.09 12.79 21.53 18.91 0.71 9.28 1976 10.08 78.30 1977 8.22 3.90 13.09 22.65 19.63 0.73 3.95 12.98 23.51 20.46 0.73 9.83 79.71 1978 8.25 79.12 1979 7.94 3.78 12.93 24.17 19.69 0.71 9.90 3.84 12.24 24.35 20.35 0.72 9.98 79.50 1980 8.02 79.90 8.04 3.86 12.12 24.63 20.44 0.72 10.09 1981 10.16 81.40 1982 8.06 3.87 12.49 25.93 20.17 0.72 10.33 83.50 1985 8.13 3.91 12.36 27.44 20.61 0.72 10.30 90.50 1990 8.17 3.95 13.56 33.11 20.68 0.73 96.49 1995 8.22 3.99 14.13 37.72 21.05 0.73 10.65 101.50 2000 8.28 4.05 14.49 41.59 21.40 0.74 10.95

TABLE 3

U.S. ENERGY SUPPLY DATA (QBTU)

Solar & Domestic Imported Gas Total Year Lower 40 supplement Coal Hydro Other Nuclear Oil Oil 54.6 1965 15.9 0.5 11.4 2.1 0.6 -- 19.1 5.0 1966 17.2 0.5 11.8 2.1 0.6 -- 20.2 5.0 57.4 18.0 0.6 11.8 2.3 0.6 0.1 21.6 4.7 59.7 1967 63.0 1968 19.1 0.7 12.1 2.3 0.6 0.1 22.6 5.5 20.5 0.8 12.2 2.7 0.5 0.2 23.4 6.2 66.5 1969 69.5 1970 21.7 1.0 12.4 2.6 0.5 0.2 23;7 7.4 22.2 I.! 11.8 3.1 0.5 0.4 23.2 7.9 70.2 1971 72.7 1972 22.2 1.2 12.3 2.9 0.5 0.6 23.5 9.5 1.3 13.0 2.7 0.5 0.9 23.0 12.2 75.9 1973 22.3 73.8 1974 21.4 1.1 12.9 3.2 0.4 1.3 21.6 11.9 1.9 21.1 11.8 72.1 1975 19.9 1.1 12.8 3.1 0.4 21.2 14.5 75.8 1976 19.9 1.1 13.7 2.9 0.4 2.1 1.2 14.2 2.3 0.4 2.7 20.2 17.4 78.3 1977 19.9 79.7 19.6 1.3 14.1 2.8 0.5 2.8 22.4 16.2 1978 21.4 15.6 79.1 1979 19.7 1.4 14.8 3.0 0.5 2.7 1.5 14.9 3.2 0.5 3.0 21.1 15.9 79.5 1980 19.4 79.9 19.0 1.7 15.0 3.2 0.5 3.1 20.7 16.7 1981 16.9 81.4 1982 18.5 2.5 16.0 3.3 0.5 3.2 20.5 2.5 16.7 3.3 0.5 3.2 20.7 17.2 81.9 1983 17.8 82.5 17.1 2.7 17.5 3.4 0.5 3.5 20.9 16.9 1984 16.4 83.5 1985 16.9 2.9 18.2 3.4 0.5 3.7 - 21.5 22.7 14.2 90.5 1990 15.5 4.9 22.2 3.5 0.6 6.9 22.7 13.5 96.5 1995 12.8 7.6 27.6 3.5 0.8 8.0 22.7 13.5 101.5 2000 10.0 8.8 33.1 3.6 1.2 8.6

1-20 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 SHELL UPDATES ITS "NATIONAL ENERGY mately 8-9 MMB/D of crude oil and products OUTLOOK" ASSESSMENT FOR THE 1980-1990 throughout the decade. PERIOD • Gas from non-conventional sources such as Shell Oil Company recently published "The National tight sands and synthetic gas from coal will Energy Outlook: 1980-1990." This paper, which updates contribute about I MMB/D by 1990. previous Shell assessments of the national energy supply, supersedes "The National Energy Outlook,' which was • Domestic gas will be supplemented by published in June, 1978. imports from Canada, Mexico and liquefied natural gas from overseas. These imports The major assumptions used by Shell in compiling its new will peak at 1.4 MMB/D in 1985, declining to Energy Outlook include: slightly under I MMB/D by 1990. • The Gross National Product will increase • Demand for coal will grow almost 4 percent from $1,400 billion (1972 dollars) in 1980 to AAI (Average Annual Increase) in the 1980's, about $1,900 billion in 1990. reaching a level of 1.2 billion tons per year in 1990, with exports representing about 10 per- • Inflation is expected to be 8 to 10 percent in cent of total demand. the early 1980's and to moderate to a 6 to 8 percent range by the late 1980s. • Capacity to produce coal will continue to exceed demand. • The labor force will increase from 100 million On 1978) to 122 million in 1990. • Coal use is impeded primarily by the cost of conversion and the problems in meeting air • Regulation of industry will continue. Alloca- quality standards. tion will direct fuels to preferred end users, while tax incentives will encourage domestic • Demand for electricity continues to increase, production of energy. Access to energy but the 3 percent AAI growth rate in the resources on federal lands will change little, 1980's is less than half the rate of the '60s and air quality standards are not expected to and early 1 70s due to the effects of higher change greatly. prices and efficiency improvements. • Responsibly planned energy projects will • Nuclear plants will generate about 25 percent eventually go forward, despite delays which of electricity demand in 1990. Although well are to be expected. below the expectations of earlier forecasts, this still represents a 9.6 percent annual • World oil demand growth will moderate. growth rate.

The key findings of the Shell projection are: • In 1990, about 9 percent of our total energy needs will be supplied by nuclear power. • Total energy demand grows at 1.2 percent annually during the 180s, one-half the rate of • Renewable energy sources (solar, wind, bio- the '60s and early 170s. mass) are in the early development stages. Their contribution by 1990 is therefore small • Higher energy prices, greater conservation but should increase significantly in the efforts, and tower economic activity contri- following decade. bute to this slowdown. • Over half of this energy contribution will • Nuclear, coal, synthetics, and renewable come from wood and other waste material. energy supplies will increase, but domestic supplies of oil and gas will be insufficient to • There is a modest expansion in world oil meet U.S. needs. Imports of oil and gas show demand to 76 MMB/D by 1990. This is some a modest rise by the end of the decade. I? MMB/D greater than current levels.

I Total U.S. oil use will plateau at about 17 • In the 'SOs OPEC oil production should rise MMB/D early in the 1980's, bringing an end to modestly above current levels, but this incre- the historic trend of increasing consumption. mental supply will be needed for the increasing domestic demands of OPEC • Domestic oil supply will decline until the members. Consequently, exports of OPEC oil mid-180s, then begin to rise slightly with new will remain approximately level, in the range contributions from frontier areas, enhanced of 28-29 MMB/D. recovery production techniques, and the introduction of synthetic oils from coal and • Supplies of internationally traded oil will shale. remain tight throughout the period. • Domestic supplies remain inadequate and Shell concludes that there are three ways by which the must be supplemented by imports of approxi- United States may minimize its dependence on foreign oil:

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-21 Efficient, prudent use of energy—conserva- Author(s) Title Date tion. Roger Sant et al. The Least-Cost 1979 Vigorous development of domestic oil and Energy Strategy: gas. Minimizing Consumer Costs through Development of domestic energy forms that Competition supplement and/or replace oil and natural gas. These include coal, nuclear, synthetic The E235 Alter- Alternative Energy 1979 oil and gas from coal, shale oil and renewable native Energy Futures: An Assess- resources. Futures Study ment of U.S. Options Team to 2025 Concerning synfuels, Shell notes that the development of domestic synthetic and renewable fuels has begun, al- R. Stobaugh and Energy Future: 1979 though technical, environmental and economic problems D. Yergin Report of the Energy remain. These problems will be solved by the end of the Project at the Harvard decade and major energy contributions from these Business School sources should be realized in the 1990's. Vince Taylor The Easy Path 1979 Shell evaluated its projection in the light of other Energy Plan important resources--skilled manpower, materials, fabri- cation capabilities, and capital. No significant impedi- David Brooks Economic Impact of 1978 ment to the achievement of the projects was found. Low Energy Growth in Canada: An Initial • il///ill Analysis CEQ REVIEWS SELECTED STUDIES OF LOW ENERGY Gerald Leach A Low Energy 1979 FUTURES FOR THE UNITED STATES et al. Strategy for the United Kingdom In a June 1980 report (DOE/PE-0020) entitled "Low Energy Futures for the United States" the CEO presents If the efficiency improvement measures cited by the its review of ten studies selected to show that energy various report authors could be widely and rapidly improvements appear feasible, what their costs might adopted across all sectors of the economy, the combined be, and what policy suggestions have been made to and cumulative effects, CEQ believes, would result in improve energy efficiency. negative future growth in U.S. primary energy use. Each of the studies selected contend that future con- In Theory, Fuel Requirements for Buildings Can Be sumption of primary fuels in the U.S. can be maintained Greatly Reduced at or below current levels, even though Gross National Product (GNP) and population continue to increase. The CEQ reports that the ten studies agree that the fuel feasibility of this outcome, the reports contend, rests on needed for space heating may be reduced to very low numerous opportunities for improving the efficiency of levels by revising building standards and by preparing energy use in building, appliances, transportation, and standards for the efficiency of appliances on HVAC industry. equipment. Tax credits, loans, increased education, training, and various information programs would be The ten studies reviewed were: required. It appears that savings in fuel use could range from 30 to 80 percent. Author(s) Title Date Fuel Saving Possibilities for Industry Are Cited Demand and Conser- Alternative Energy 1979 vation Panel of the Demand Futures to CEQ finds that significant improvements in industrial Committee on 2010 fuel use are possible in waste heat recovery, cogenera- Nuclear and Alterna- tion of heat and electricity, load-matched electric tive Energy Systems motors, and increased materials recycling. Policies recommended include removal of regulations, loan pro- M. Christensen, Distributed Energy 1978 grams, and government support of R&D programs. P. Craig, et al. Systems in California's Future: Interim Report Improvements in Transportation Fuel Use May Be Intro- duced Quickly Leonard Rodberg Employment Impact 1979 of the Solar The comparatively rapid turn-over of the automobile Transition stock will permit advances in fuel efficiency to be introduced quickly. Policy recommendations of the M.H. Ross and Our Energy/Re- unpub- authors include steep fuel taxes, new standards well in R.l-L Williams gaining Control lished excess of those now mandated, increased load factor of cars and other vehicles, and deregulation of freight transport.

1-22 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 pPj!ctive of CEQ Review Was to Show That Energy Use U.S. policy will emphasize energy conserva- in U.S. May Be Reduced tion and oil substitution, but actual achieve- ments will fall short of announced goals, the Many estimates of future U.S. energy demand were latest of which is an oil import level of 4 to 5 based on an extrapolation of aggregate historical trends, million BID by 1990. according to CEQ. Therefore, technological innovations in energy efficiency, steeply escalating prices, and •. The required volume of oil imports in the decreasing supply allegedly were not examined. Thus, 1980's will be available. CEQ intentionally selected studies for review which concentrate on ways to meet increasing future energy In PIRINC's perspective, synthetic oil (shale oil and needs with primary energy inputs that decrease in the liquefied coal) will make only a very small contribution future to levels below current U.S. practice. However, to oil supplies by 1985, all of it from pilot plants, since such bias in data selection dictates that the CEQ study is the required construction time of at least seven years not based on representative data. We understand that for full scale plants makes it unlikely that any will be the CEQ advocates using less fuel, but we do not believe operating by then. By 1990 some 10-15 plants might that government policy should be based on selected, produce approximately 600,000 B/D of synthetic oil. A biased data, such as is used in this report. constraint in the period to 1990 could be availability of capital, given the estimated cost of $2.5-3.0 billion per I/I/I? II plant, in 1980 dollars, and the unproven technology of the first generation of these plants. The 1990 projection PETROLEUM INDUSTRY RESEARCH FOUNDATION, is about half the Administration's target for that year. INC REPORTS ON THE U.S. ENERGY PERSPECTIVE -To 1990 The historic data (1963-1979) and the projections (1985 and 1990) from the PIRINC study are summarized in The Petroleum Industry Research Foundation, . Inc. Tables I through 7, reproduced from this study. U. S. (PIRINC), independent, not-for-profit petroleum industry products imports are projected to decline from 1.9 economists, published a report of its recent study million B/D in 1979 to 1.6 million B/D in 1985 and 1.4 entitled "Oil in the U.S. Energy Perspective--A Forecast million BID in 1990. A major unknown in this forecast, to 1990." according to PIRINC, is what policy, if any, the U.S. government will adopt towards the domestic refining The study projects U.S. oil supply and demand, within the industry, following the scheduled phase-out of the crude framework of total U.S. requirements, from 1979 to oil entitlements program in September 1981. A highly 1985 and 1990. The principal assumptions on which the protective policy could reduce products imports by projections are based include: several hundred thousand BID below the forecast, while a policy of unrestricted imports could raise them by The U.S. GNP (in constant prices) will grow about that much above it. In either case crude oil at an average rate of 2.3 percent during the imports would move in the opposite direction so that 1980's. total oil imports would remain unchanged.

All U.S. oil prices, decontrolled, will follow // ft ft ii those of imported oil.

TABLE I

U.S. ENERGY DEMAND, AVERAGE ANNUAL GROWTH RATES BY SECTOR, 1963-1990

1963/1973 1973/1979 1979/1985 1985/1990 1979/1990 Real GNP(a) 4.0 2.5 2.2 2.4 2.3 Sectors Residential/Commercial 3.6 0.1 1.2 1.2 - 1.2 Industrial 3.3 -1.4 1.9 1.6 1.7 Transportation 4.7 1.4 -1.6 -0.3 -0.4 Net Energy (b) 3.7 070 0.9 079 0.9 Primary Energy (c) 4.2 0.6 1.3 1.5 1.4 Energy/GNP Ratios - Net (b)/(a) 0.9 0.0 04 0.4 0.4 Primary (0/(a) 1.1 0.2 0.6 0.6 0.6 Note: Electricity use has been distributed to each of the end-use sectors.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 . 1-23 TABLE 2

PRIMARY ENERGY CONSUMPTION PER DOLLAR OF GNP, 1963-1990 Energy Consumption GNP Energy/GNP (Quadrillion BTU's (Billion 1972 $'s) (BTU's Per $)

1963 49.31 830.7 59,400 1973 74.61 1,235.0 60,400 1979 77.39 1,431.6 54,100 1985 83.59 1,631.3 51,200 1990 90.10 1,836.7 49,100 Sources: Historical data are form the Department of Energy and Department of Commerce; forecasts are those of PIRINC.

TABLE 3

U.S. ENERGY DEMAND BY PRIMARY FUEL SOURCE, 1973-1990 (10 15 BTU) 1973 1979 1985 1990

Natural Gas 22.51 19.82 19.62 19.41 Petroleum 34.84 36.86 35.93 34.94 Coal 13.30 15.10 18.83 23.36 Nuclear 0.91 2.72 5.81 8.51 Hydro/Other 3.05 3.08 3.88 4.87 Total Primary Enegy Demand 74.61 77.39 83.59 90.10

AVERAGE ANNUAL GROWTH RATES (Percent Per Year)

1963/1973 1973/1979 1979/1985 198511990 1979/1990

Natural Gas 4.3 -2.1 -0.2 -0.2 -0.2 Petroleum 4.7 0.9 -0.4 -0.6 -0.5 Coal 2.2 2.1 3.7 4.4 4.0 Nuclear 38.6 20.0 13.6 7.9 10.9 Hydro/Other 5.6 0.2 3.9 4.7 4.3 Total 4.2 0.6 1.3 1.5 1.4 Note: Total primary energy demand is less than the sum of the individual fuels shown since it excludes the energy equivalent of the product made from the conversion of a primary fuel into another primary fuel as in the case of SNG production from petroleum and coal and also petroleum liquids production from coal. This is done to avoid double counting.

Source: 1973 data are from the Department of Energy, other years are PIRINC estimates.

1-24 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 4

U.S. ENERGY CONSUMPTION FOR ELECTRIC POWER GENERATION BY FUEL, 1973-1990

1973 1979 1985 1990 Total Electric Output (BKHR) 1,861 2,248 2,725 3,202

Nuclear: Capacity (000 MW) 18 54 97 137 Output (BKHR) 83 255 545 798

Coal: Use (MM Tons/Yr) 389 529 685 853 Output (BKHR) 848 1,075 1,400 1,714 Natural Gas: Use (TCF/Yr) 3.7 3.5 1.9 1.3 Output (BKHR) 341 330 190 127

Oil: Use (MM BID) 1.5 1.4 1.2 0.9 Output (BKHR) 314 304 249 177 Hydro & Other Output (BKHR) 274 284 341 386 Average Annual Growth Rate in Total Electricity Output (%) 1963/73 1973179 1979/85 1985/90 7.3 3.2 3.3 3.3 Note: The following abbreviations are used:

BKHR = Billion Kilowatt Hours MW = Megawatts MM = Millions TCF = Trillion Cubic Feet

Source: 1973 and 1979-Department of Energy, Monthly Energy Review, March 1980; 1985 and 1990- -PIRINC forecast.

S TABLE

OIL DEMAND BY CONSUMING SECTOR, 1973-1990 (Percent Distribution)

Sector 1973 1979 1985 1990

Residential/Commercial 19.2 15.4 15.8 15.5 (l) Industrial 17.4 19.9 21.0 22.4

Transportation 52.1 55.4 53.7 54.3

Electric Power 10.5 7.7 7.5 5.7

Synthetic Natural Gas Feedstocks --- 0.7 1.1 1.1

Miscellaneous 0.8 0.9 0.9 0.9

Total 100.0 100.0 100.0 100.0

(1) Includesindustrial fuel raw material and petrochemical feedstocks.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-25 TABLE 6

U.S. PETROLEUM PRODUCTS DEMAND, 1973-1990 (Million Barrels Daily)

1973 1979 1985 1990

Gasolines 0 6.72 7.07 6.30 5.65 (2) Distillates 3.09 3.30 3.41 3.61 Residual Fuel Oil 2.82 2.79 2.39 1.95 Jet Fuel 1.06 1.07 1.16, 1.26 Other 3.61 4.15 4.73 5.03 Total 17.30 18.38 17.99 17.50

AVERAGE ANNUAL GROWTH RATE (% Per Year)

1963/1973 1973/1979 1979/1985 198511990 1979/1990 Gasoline 4.2 0.8 -1.9 -2.2 -2.0 Distillates 4.2 1.1 0.5 1.1 0.8 Residual Fuel Oil 6.7 -0.2 -2.5 -4.0 -3.2 Jet Fuel 7.0 0.2 1.4 1.7 1.5 Other 5.1 2.4 2.2 1.2 1.8 Total 4.9 1.0 -0.4 -0.6 -0.5

(1)Includesaviation gasoline. (2)Excludespetrochemical feedstock use of gasoil which is included in "Other." Includes petrochemical and synthetic natural gas feedstocks, liquid petroleum gas, asphalt/road oil, still gas, lubes and waxes and miscellaneous oils. Source: Historical data are from the Department of Energy; forecasts are those of PIRINC.

1-26 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 7

U.S. OIL SUPPLY AND DEMAND, 1979-1990 (Million Barrels Daily)

1979 1985 1990 Production: Crude Oil Lower 48 States 7.3 6.3 5.9 Northern Alaska 1.3 1.6 i. Total 8.6 7.9 7.6 NGL's 1.7 1.5 1.4 Synthetic Oil -- 0.1 0.6 Processing Gain 0.5 0.6 0.6 Stock Changes -0.1 -- - Total Domestic Oil Supplies 10.7 10.1 10.2 Domestic Oil Demand Exports 0.5 0.3 0.3 Total Oil Demand 117 113 17.8 Required Oil Imports** 8.2 8.2 7.6 (of which: Products Imports) (1.9) (1.6) (1.4)

*Includes South Alaskan oil production which amounted to 0.1 million BID in 1979. **Excluding imports into Strategic Petroleum Reserve.

Source: 1979--Department of Energy, Monthly Energy Review, March 1980; 1985 and 1990---PIRINC forecast.

CEQ COMPLETES ITS GLOBAL 2000 REPORT TO THE PRESIDENT The principal conclusions of the study were that popula- tions must be controlled to prevent exceeding the President Carter, in his Environmental Message to the carrying capacities of the earth. Other steps, such as Congress of May 23, 1977, directed the Council on reforestation, energy conservation, family planning, and Environmental Quality and the Department of State to increasing crop yields must be taken. Nations must study the "probable changes in the world's population, improve their abilities to identify and convert problems natural resources, and environment through the end of and to cooperate. Long lead times will be required for the century." That study has been completed and the effective actions to correct most problems. report, entitled "The Global 2000 Report to the Presi- dent," has been published. Volume I of the report is the Concerning energy, the Global 2000 study shows no early Summary. Volume II is the Technical Report, and relief from the world's energy problems. A world Volume Ill consists of technical documentation on transition away from petroleum dependence is called for, various models. Ordering information for the three but it is acknowledged that much uncertainty exists as to volumes may be found in the Recent General Publica- how such atransition may occur. Per capita energy tions list. consumption is expected to increase everywhere. The expected global energy use to 1990 is presented as Table The principal findings of the study were that the world's I. Good projections past 1990 were not available. population will grow from 4 billion in 1975 to 6.35 billion in 2000. The large existing gap in the gross national TABLE 1 product per capita in the developed and less developed countries will widen. Most of the necessary increased GLOBAL PRIMARY ENERGY USE, 1975 and 1990 food production will have to come from increased yields. (Units = 10 15 BTU) World oil production will be at the estimated maximum capacity in the 1990's. Needs for fuelwood will exceed Energy Type 1975 1990 % Increase available supplies by 25 percent in 2000. Other fuel resources are not evenly distributed, but theoretically Oil 113 179 58 are sufficient for centuries to come. Non-fuel resources Coal 68 77 13 appear sufficient to meet projected demands through 2000. Regional water shortages will become severe. Natural Gas 46 66 43 The spread of desert-like conditions is anticipated. Nuclear & Hydro 19 62 226 Hundreds of thousands of plant and animal species will vanish. Solar ------Totals 246 384 56 ft ft f/ft

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-27 ECONOMICS

SYNFIJELS ARE A BARGAIN - IF ALL COSTS ARE Manganese 98 percent dependent CONSIDERED Cobalt 95 percent Chromium 90 percent Bernie Lee, President of the Institute of Gas Technology Columbium 100 percent (IGT), contends that if all costs are considered, synthetic Titanium 100 percent fuels are a bargain when compared with imported oil. Bauxite 93 percent Tin 81 percent Speaking before the 7th Annual International Conference Nickel 77 percent on Coal Gasification, Liquefaction, and Conversion to Mica 100 percent Electricity at the University of Pittsburgh, Lee pointed Tantalum 90 percent out that the posted price of imported oil does not truly reflect the actual cost of that oil to the United States. 5. 3097,The Critical Materials Act of 1980, Is Intro- Lee's paper was entitled, "Synthetic Fuels and the Cost duced by Senators Nelson and Jackson of Foreign Imports." During September, Senator Nelson introduced S. 3097, a A little over a year ago, personnel at the ICT started Sill cited as "The Critical Materials Act of 1980." As its considering the additional costs which are associated name implies, this Bill would authorize actions which with imported oil. At that time, others had placed very could alleviate our national problems relating to depen- generalized estimates of these "external' costs at from dence on foreign sources for many of our strategic $10 to $100 per barrel. IGT tried to quantify the mineral requirements. externalities more explicitly, in a study based on a reduction of oil imports into the U.S. by 500,000 barrels Similar bills have been introduced in Congress on many per day. Benefits which accrue from such a reduction occasions over the past 40 years with little effect. In include the price of the imported oil, an assumed related fact, the report by the National Commission on reduction in the price of oil (as the world oil demand Materials Policy, which issued during the administration decreases), added real output in the U.S. economy, of President Truman, remains as the tragic, accurate, improved national security, the cost of that portion of but unheeded forecast of our present sufficiency prob- the national defense budget allocated to protection of lems in both fuel minerals and non-fuel minerals. foreign oil supply, and various inflation and employment benefits. f/I/il 1/ After considering the external costs of oil imports, IGT then studied the size of the external costs associated with synthetic fuels production. While these studies are still going on, Lee disclosed that the total cost of SNG from coal will be about $30 per barrel of oil equivalent lower than imported oil with its external costs, and that synthetic fuels will be a bargain when compared with imported oil, as the external costs are already internal- ized for synthetic fuels. -

II 111/1/

CRITICAL MINERAL NEEDS OF THE UNITED STATES ARE NOT LIMITED To THE MINERAL FUELS At the end of 1978, the United States suffered an annual nonfuel mineral balance-of-trade deficit of $7 billion. One estimate projects that by the year 2000, America's non-fuel mineral deficit will attain $65 billion. The Nation's non-fuel analogy to its fuel sufficiency problem can be illustrated further by noting that the U.S. is now dependent on foreign sources in excess of 50 percent for 24 of the 32 minerals deemed essential to national survival. As discussed in Committee Print No. 8, a report prepared recently by the House Sub- committee on Mines and Mining, our dependency on foreign sources for critical non-fuel minerals includes:

1-28 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 U.S. GOVERNMENT SYNFUELS PROCUREMENT NOTICES AND PROGRAM SOLICITATIONS LISTED This listing of U.S. Government Synfuels Procurement Notices was excerpted from notices published in the Commerce Business Daily during the period from August 2, 1980 to November 3, 1980. U.S. Department of Energy

NOTICE OF PROGRAM INTEREST FE-NPI-81-001. Pursuant to DOE PR Para 9-4-950 the Office of Fossil Energy in the Department of Energy wishes to stimulate the flow of unsolicited proposals for preliminary studies and conceptual designs defining potential applications of coal-based combined cycles utilizing coal gsification and a gas turbine module of 75 MW minimum size. The studies are to include reliability, environmental, and economic analysis and are to be accomplished in a period not to exceed 9 months. Multiple awards are anticipated up to $3.0 million, with no single award to be made in excess of $1.5 million. Unsolicited proposals should be submitted as soon as possible but not later than 60 days from date of publication of this notice. Proposals should be submitted in 5 copies. Information on proposal preparation may be found in 'guide for the Submission of Unsolicited Proposals" (available from the Procurement and Contracts Management Directorate, Department of Energy, Washington, D.C. 02585). Department of Energy reserves the right to support or not support any or all proposals received and assumes no responsibility for any costs associated with preparation of proposals. It is anticipated that DOE will be soliciting competitive proposals next year for site specific demonstration applications of the combined cycle gasifier systems. Further details concerning this future planned procurement including the identification of the source for the solicitation package will be announced in the Commerce Business Daily. The awards for the development studies procured under this NPI shall not be considered unfair or competitively restrictive for purposes of participation in any future demonstration project(s).

• DOCUMENTATION OF WORLDWIDE COAL GASIFICATION FACILITIES. Negotiations are now being conducted with Radian Corp., 8500 Shoal Creek Blvd., Austin, Texas.

• REVIEW OF THE SRC-I DRAFT AND SRC-I[ FINAL EIS, to support preparation of and to review Chapter I, Purpose, Need, Status and Program Overview. Negotiations with Hittman Associates.

• ENVIRONMENTAL ASSESSMENT OF THE HYGAS PROCESS. Negotiations are now being conducted with Institute of Gas Technology, 3424 South State Street, Chicago, Illinois.

• HEAVY OIL PROCESS ENGINEERING REVIEW AND ASSESSMENT. The objective is to obtain engineering support to evaluate heavy oil upgrading/refining process designs generated by other contractors. The successful offeror will not work directly on process development, but background and knowledge in petroleum refining process design will be necessary to evaluate the results generated by the other contractors. The successful offerer must be willing to enter into a secrecy agreement if necessary. RFP DE-RPI9.808C10349 to be issued o/a Sept 5, 1980.

• HEAVY OIL PROCESSING. Advance the development of processes for upgrading/refining of heavy oils. The goal is to increase domestic capability in upgrading/refining heavy oils by providing technology for less complex refineries (e.g. topping or topping-plus-asphalt plants) and small field units. Prospective offerers must have capabilities in engineering and process design, background and expertise in the processing of crude oils, and an innovative state of the art process for the upgrading/refining of heavy crude oils which can be brought to the preliminary design stage within the required time frame of 8 months. Request for Proposal DE- RP-19-808C 10328.

• LOAN GUARANTEES FOR ALCOHOL FUELS, BIOMASS ENERGY AND MUNICIPAL WASTE ENERGY PROJECTS. Description: Provides additional information concerning the solicitation of applications for loan guarantees to assist alcohol fuels, biomass energy and municipal waste energy projects. Eligible projects must be capable of producing 15 million gallons or more of ethanol or its energy equivalent per year. The solicitation of applications and proposed rule were published in the August 14, 1980, issue of the Federal Register (45 FR 61347) and sets forth the following funding levels that may be made available to successful applicants in the initial competition cycle: Alcohol Fuels Up to $400,000,000; Biomass Energy Up to $15,000,000; and Municipal Waste Up to $25,000,000.

TESTING OF SHALE OIL BLENDS. Negotiations with General Electric Corp., Schenectady, NY. Continuation of work under current DOE contract DE-ACI9-79BC10110.

CONCENTRATING OIL SHALE BY FROTH FLOTATION. Negotiations are now being conducted with SRI International, 333 Ravenswood Avenue, Menlo Park, CA.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-29 • EVALUATION OF IMPROVED MATERIALS FOR STATIONARY DIESEL ENGINES OPERATING ON RESIDUAL AND COAL BASED FUELS. Negotiations conducted with Advanced Mechanical Technology, Inc., Newton, MA. Any resulting contract will be numbered DE-ACI9-80BC10362.

• MODIFICATIONS TO HYGAS FACILITY DURING TRANSITION PERIOD BETWEEN COAL & PEAT TESTING. Negotiations are being conducted with Institute of Gas Technology 3424 S. State St., Chicago, IL.

• CONCEPTS FOR PRODUCING TRANSPORTATION FUELS FROM UCG GASES. Negotiations are now being conducted with Pretchard Corporation, 4625 Roanoke Parkway, Kansas City, MO.

• CONCENTRATION SENSORS FOR COAL/WATER MIXTURES. Negotiations conducted with Science Applica- tions, Inc., 1200 Prospect Street, LajolIa, CA.

• MANAGEMENT OF STATE SIDE FUEL OIL CONSERVATION MARKETING DEMONSTRATION. Negotiations are now being conducted with: R.I. Governor's Energy Office, 80 Dean St., Providence, RI. • SUPPORT SERVICES FOR THE OFFICE OF THE DIRECTOR OF ADMINISTRATION. Overrun of option year estimated amount. Negotiations are now being conducted with: Booz, Allen & Hamilton, 4330 East West Highway, Bethesda, MD.

• CATALYTIC EVALUATION FOR H-COAL. Negotiations are being conducted on a sole source basis with Hydrocarbon Research Incorporated as modification to Contract ET-79-C-01-3161. • TECHNICAL & ADMINISTRATIVE ASSISTANCE for conducting a workshop on critical coal conversion equipment, I each REQ not available. Negotiations being conducted with TRW Energy Systems Group, McLean, VA.

• CONSULTANT SERVICES for coal/limestone variability effects on flue gas desulfurization study, I each RFQ DE-RQ2I-80MC 15952. • TECHNICAL SUPPORT SERVICES, National Environmental Policy Act (NEPA). The Department of Energy (DOE) is responsible for developing and coordinating the federal government's efforts regarding energy policy, regulation, research, development and demonstration. In carrying out its responsibilities, DOE is required by the National Environmental Policy Act of 1969 (NEPA), to give approximate weight to factors affecting human environment during all stages of its planning and decision-making process. In addition to NEPA, actions of the department are subject to the provisions of an array of environmental statutes, orders and regulations such as the clean air act, the clean water act, toxic substance control act, etc. The NEPA Affairs Division (NAD) within the office of environment provides assistance and oversight for all DOE activities to assure compliance with the requirements set forth in NEPA and other environmental statutes bearing on the NEPA review process. The purpose of this procurement is to provide technical and analytical support to NAD. This will require that the offerer possess capabilities to provide assistance with respect to: Generic and project specific environmental planning review and analysis, reflecting compliance with environmental statutes and orders, and; DOE actions involving specific technology areas specified in the RFP and others associated with energy production and utilization. Sol RPOI-8IEVI0398 RFP document will be available approximately Oct. I, 1980, and proposals will be due November 1, 1980. Document Control Specialist, Tel: 202/376-9290 (269).

• DENITRIFICATION OR DESULFURIZATION OF COMBUSTION GASES. Negotiations are being conducted on a sole source basis with the State University of New York, at Buffalo, Buffalo, NY.

• ANALYSIS OF REFUSE DERIVED FUEL (RDF) AND TEST BURN OF RDF. Negotiations are now being conducted with Vista Chemical & Fiber Products, Inc., 350 Fifth Ave., NY, NY.

• CO-COMBUSTION OF REFUSE DERIVED FUEL (RDF) AND COAL IN A CYCLONE. Negotiations are being conducted with Maryland Environmental Services, 60 West Street, Annaplis, MD. • EXPERIMENTAL PROGRAM TO CONDUCT CONTINUOUS PEAT WET CARBONIZATION TESTS AND DETERMINE THE EFFECT OF WET CARBONIZATION ON PEAT GASIFICATION ECONOMICS. Negotiations are now being conducted with Minnesota Gas Company, 733 Marquette Ave., Minneapolis, MN.

• PEAT RESOURCE ESTIMATION IN MAINE. Negotiations are now being conducted with State of Maine, Office of Energy Resources, State House Station 53, Augusta, ME.

• LOW ENERGY PROCESSES FOR SEPARATION OF METHANE FROM HYDROGEN. Unsolicited proposal. Negotiations to be conducted with the State of University of New York at Buffalo, Buffalo, NY.

I-30 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 • CONTROLLED FLASH PYROLYSIS. Negotiations on sole source basis with Occidental Research Corp. of Irvine, CA.

• PROGRAM TO DEVELOP and Evaluate the Combustion Processes of Coal-water Mixtures. Contract No. bE- AC22-80PC30 185. Negotiations conducted with Atlantic Research Corporation, 5390 Cherokee Avenue, Alexandria, VA.

• CONCENTRATION SENSORS FOR COAL/WATER MIXTURES. Negotiations are now being conducted with Science Applications, Inc., 1200 Prospect Street, LaJolla, CA.

• SUPPORT AND TECHNICAL ASSESSMENT OF COAL-OIL MIXTURE COMBUSTION TECHNOLOGY. Nego- tiations conducted with Mitre Corporation, 1820 DaIley Madison Boulevard, McLean, VA. Contract No. bE- AC22-80PC30071.

• COAL-LIQUID FUEL/DIESEL ENGINE OPERATING COMPATIBILITY. Negotiations with A. D. Little, Inc., Cambridge, MA. Continuation of work under current DOE Contract DE-ACI9-79BCI019.

• EVALUATION OF DATA GATHERED FROM UNMINEABLE COAL SEAMS. Continuation of previous Government contract with Intercomp. Negotiations on a sole source basis with Intercomp Resource Development and Engineering, Inc.

• ASSESSMENT OF OIL SHALE TECHNOLOGY IN BRAZIL. Negotiations are now being conducted with International Science & Technology Inst. Inc., Washington, D.C.

• CHARACTERIZATION OF INTEGRATED COAL GASIFICATION SUBSYSTEMS OPERATING UNDER DYNAMIC LOAD. Negotiations are now being conducted with: General Electric, Schenectady, NY.

• SERVICES RELATED TO DATA COLLECTION, DATA REDUCTION, OPERATION, MAINTENANCE, AND DOCUMENTATION OF ENERGY DATA. Solicitation RPOI-80EI10990.

• DEVELOPMENT OF LINEAR AND NON-LINEAR PROCESS EVALUATION/SIMULATION METIIOLDS WITH SELECTED APPLICATIONS TO HYDROGASIFICATION PROCESSES AND RISER REACTORS. An unsolicited proposal. Negotiations to be conducted with Environmental Research and Technology, Inc., Concord, MA.

• COMBUSTION CONTROL OF NOx IN THE PRESENCE OF FUEL SULFUR. Negotiations are being conducted on a sole source basis with the University of Washington, Seattle, WA.

• EVALUATION OF SULFUR AND ASH REDUCTION CAPABILITY OF A UNIQUE DRY COAL CLEANUP PROCESS. Contemplate the solicitation of Advance Energy Dynamics, Inc., Natick, Massachusetts, to perform work. Sot DU-80-A249. -

• CONCENTRATION SENSORS FOR COAL/WATER MIXTURES. Negotiations are now being conducted with Science Applications, Inc., 1200 Prospect Street, Laolla, CA.

• DIRECTED TECHNICAL REPORT, ACID RAIN: ROLE OF OIL vs. COAL COMBUSTION TECHNOLOGIES. Negotiations with Resource Technologies Group, Inc., Morgantown, WVA.

• MARKET ASSESSMENT OF FLUE GAS DESULFURIZATION SYSTEM in the Industrial Sector. Negotiations are being conducted on a sole source basis with Science Applications, Inc., McLean, VA.

• ASSESSMENT MANAGEMENT SYSTEM FOR ENERGY TECHNOLOGY BASE PROGRAM. Negotiations are now being conducted with R&D Associates, Marina Del Rey, CA. Sal. ACOI-80ER30005.

• COAL-FIRED COGENERATION DEMONSTRATION PLANT. Negotiations are now being conducted with Westinghouse Electric Co., Concordville, PA.

• Proposals for Feasibility Studies and Cooperative Agreements for the Direct Combustion of Urban Waste. Program Solicitation Numbers DE-PSOI-80RA50412 and DE-PSOI-80RA50413 were issued August I, 1980 and closed September 30, 1980. (Funded under P.L. 96-304).

• Final Solicitation for Proposals for Loan Guarantees and Price Guarantees for Development of Synthetic Fuels under the Defense Production Act (P.L. 960294) and the Federal Non-Nuclear Research and Development Act (P.L. 93-577). Program Solicitation Numbers are DE-P560-81RA50481 and DE-PS60-81RA50480, both issued on October 15 and closed on November 14, 1980.

• OPERATION OF THE SOLVENT REFINED COAL (SRC) PILOT PLANT at Wilsonville, AL, which plant tests various coals and evaluates improvement in the SRC process, equipment and operations. Extension of Contract EX-76-C-01-2270 with Southern Company Services, Inc., Birmingham, AL.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-31 CHEMICAL AND PHYSICAL CHARACTERIZATION OF LOW-RANK COAL WASTE MATERIALS. Character- ize Western low-rank coal waste materials produced by FGD wet scrubbers, fluidized bed combustion FGD spray dryers and FGD dry sorbent duct injection. Request RFP DE-RP-18-80FC10200 by writing to Attn: Contracting Officer, DOE, Grand Forks, N.D., P. 0. Box 8213. FEASIBILITY STUDIES AND COOPERATIVE AGREEMENTS FOR THE DIRECT COMBUSTION OF MINERALS AND ORGANIC MATERIALS--This synopsis is to advise you of a solicitation to be issued shortly by the Department of Energy providing a total of up to $30 million for feasibility studies and cooperative agreements for innovative systems for the direct combustion of minerals and organic materials other than petroleum and natural gas for energy production. Public Law 96-369, the Joint Resolution making continuing appropriations for fiscal year 1981, which was recently signed by the President expands the definition of alternative fuels for purposes of P.L. 96-126 and P.L. 96-304 to cover this technology area. The $30 million is directed to be taken from the $300 million appropriated under P.L. 96-304 for feasibility studies and cooperative agreements. Innovative direct combustion technologies are those which represent a better way to burn minerals and organic materials than do conventional combustion systems which are in widespread use today. Direct combustion of urban waste is not covered under this solicitation. The Program Solicitation for grant application for feasiblity studies, Number DE-PSOI-81RA50535, and the Program Solicitation for cooperative agreement proposals, Number DE-PSCA0I-81RA50536, will become available on or about November 5, 1980.

• RESEARCH RELATIVE TO POST-TEST ENVIRONMENTAL MONITORING OF THE PRICETOWN, WV UCG TEST SITE. Propose to negotiate on a sole-source basis with West Virginia University a new research task under Basic Agreement No. DE-AC2I-79MC11284. • STUDY OF POLLUTANTS EMISSION CONTROL in a design and operation of fluidized-bed combustion systems. Conducting negotiations on a sole-source basis with West Virginia University for a new task order under Basic Agreement No. DE-AT2I-79MC11284.

• SUPPORT SERVICE FOR THE DOE GASIFICATION RESEARCH PROGRAM. Negotiations are now being conducted with Pullman Kellogg, Houston, TX. Solicitation ACOI-78ET10324. • TECHNICAL SUPPORT SERVICES FOR THE OFFICE OF PROGRAM PLANNING AND ANALYSIS. Overrun for increased DPMH within 10 percent Level of Effort Threshold. Negotiations are now being conducted with TRW Energy Systems Group, 8301 Greensboro Drive, McLean, VA. • PROGRAM SOLICITATION (PS) - UNCONVENTIONAL GAS DE-PS44-80R410201. The Department of Energy, Region IV, desires to receive and consider for support proposals for exploratory drilling of wells in DOE, Region IV, to help determine the commercial feasibility of locally producing and utilizing unconventional gas resources. For the purposes of this PS, the definition of "unconventional gas" is limited to natural gas trapped in coalbeds and Devonian Shale. Funding of 4 to 6 projects in small towns or rural communities is anticipated.

• PEAT RESOURCE ESTIMATION IN MICHIGAN. Negotiations are now being conducted with: Michigan Energy and Resource Research Association, Detroit, Michigan 48226 Sol FG0I-79ET14691.

• COAL DESULFURIZATION PROCESSES. Negotiations are being conducted with General Electric Co., Philadelphia, PA. Contr. DE-AC22-80PC30142.

• TREATMENT OF COAL CONVERSION WASTEWATER FEASIBILITY STUDY. Negotiations conducted with Celanese Chemical Company, Dallas, TX. Contr. DE-AC22-80PC30189. • PRELIMINARY DESIGN AND ASSESSMENT OF A 50,000 BPD COAL-TO-METHANOL-TO-GASOLINE PLANT to be located at Baskett, KY. Cooperative Agreement DE-FCOI-80ET-I4759 for the preliminary design and related services for an indirect liquefaction coal-to-methanol-to-gasoline facility to produce 50,000 barrels per day of gasoline from coal utilizing the Texaco Coal Gasification Process and the Mobil Methanol-to- Gasoline Process. The A-E services required shall include process and mechanical design, preparation of capital and operating assessments, and preparation of required documents for permitting and planning documents for construction and operation of the facility. The A-E firm must be prepared to commence work approximately January 2, 1981, with completion of work 18 months thereafter.

U.S. Department of the Interior EXPERIMENTAL OPERATION OF THE SIMPLEX GASIFICATION PROCESS in the Wellman-Galusha Gasifier of the U.S. Bureau of Mines--Negotiations are being conducted with Dynecology, Inc., 611 Harrison Avenue, Harrison, New York in connection with that company's Unsolicited Proposal No. J0205070. BITUMINOUS COAL INVESTIGATION in Pennsylvania whereas data will be entered into the National Coal Resources Data System. Negotiations being conducted with the Pennsylvania Bureau of Topographic and Geologic Survey, P.O. Box 2357, Harrisburg, Pennsylvania.

1-32 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 INCREMENTAL COST ANALYSIS of Away From the Minemouth Location of Liquefaction Plants from Western Coal Regions. The objective of this study is to establish both the total social costs and benefits and the incremental cost per barrel of oil produced of locating a coal liquefaction plant from the minemouth under several different assumptions. The study will be used to help establish a basis for formulating Departmental policy regarding future siting of coal liquefaction plants in western States. RFP to be issued on or about August 8, 1980. .5. Department of Commerce

FIRST AND SECOND STAGE EVALUATION OF ENERGY RELATED INVENTIONS. The government expects to make multiple contract awards as a result of this solicitation. The government will provide the contractors with invention disclosures for evaluation.

STUDY OF FUTURE AVAILABILITY OF RESIDUAL FUELS. The objective of this study is to assess the future availability of residium type petroleum fuels produced in both domestic and foreign refineries and to determine whether or not the levels of residium production over the next 15 years (1980 through 1995) will be sufficient to satisfy the demand of maritime and non-maritime users. Solicitation RFP-SA-RSD-80-0201 TC. DEVELOP A SPECIALIZED ENERGY TAXONOMY FOR COAL TECHNOLOGIES to include assessment of user requirements, development of complex classification systems and indexing. Solicitation SB80NBS0089. .1.5. Army

CHEMISTRY OF NITROGEN COMPOUNDS IN COMBUSTION PROCESSES. Based upon an unsolicited proposal negotiations with SRI International, 333 Ravenswood Avenue, Menlo Park, California. S. Environmental Protection

FINALIZATION OF POLLUTION CONTROL GUIDANCE DOCUMENT FOR DIRECT COAL LIQUEFACTION. In support of EPA's Regional and Program Offices, a 3-volume Pollution Control Guidance Document (PCGD) is being prepared for direct coal liquefaction. The PCGD will identify best available control technology candidates, and assess the costs of alternative levels of control, for air, water, solid and toxic product emissions from the SRC-I, SRC-II, H-Coal and Exxon Donor Solvent processes. The first drafts have been completed under a separate contract by February 28, 1981. Contractor selected will prepare, by April 15, 1981, the first draft of Volume I (the summary volume) and prepare at a later date, a second draft; and prepare third and subsequent drafts of Volume I and second and subsequent drafts of Volumes II and III. REP DU-SO- A25. Argonne National Laboratory

DESIGN OF ADVANCED FOSSIL FUEL SYSTEMS -GASIFICATION/COMBINED CYCLE for Argonne National Laboratory (ANL) and the Department of Energy (DOE) Expression of Interest RH-20-E-03. Expression of Interest is being sought from companies knowledgeable in the studies or design of entrained bed and fixed bed integrated coal gasification combined cycle systems for power plant application. Argonne National Laboratory (ANL) intends to award a contract(s) for a preliminary design study of an integrated gasification-combined cycle commercial power plant. The design studies shall define the cycle arrangement plant heat rate, component requirements, estimated cost of components unique to the integrated gasification-combined cycle system, etc. After receipt of cost proposals, final selection will be made. Regarding submission of proposals on the following: (I.) Design of Advanced Fossil Fuel Systems - RH-20-E-01 (2.) Design of Advanced Fossil Fuel Systems - Pressurized Fluidized Bed Combustion - RH 20-E-02 (3.) Design of Advanced Fossil Fuel Systems -Gasification/Combined Cycle - RH 20-E-03; only one contract will be awarded to any one company.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-33 RESEARCH AND DEVELOPMENT SOURCES SOUGHT The following Research and Development Notices Sought announcement was published in the Commerce Business Daily on September 5, 1980: U.S. Air Force, Wright Aeropropulsion Lab: PROPERTIES OF AIRCRAFT FUELS AND RELATED MATERIALS. Exploratory Development Area PMRS 81- 27. The Air Force maintains an active interest in the analysis and characterization of conventional fuels and fuels produced synthetically or from alternate sources. Unforeseen fuel-related problems require immediate solutions. Prompt analysis of fuels and related materials is often required for fuel-related problems which need immediate solutions. The chemistry of future fuels must be thoroughly understood. This program addresses those needs. Both routine and non-routine laboratory tests will be used for characterizing fuels of interest, and for identifying and solving fuel-related problems such as contamination. Novel tests will be developed or existing methods modified to solve unique analytical problems. Synthetic fuels for specific missile systems will be evaluated.

1-34 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 U.S. GOVERNMENT CONTRACT AWARDS LISTED This listing of U.S. Government synfuels contract awards was excerpted from notices published in the Commerce Business Daily during the period from August 2, 1980 to November 3, 1980. - U.S. Department of Energy

• OIL SHALE AND TAR SAND STUDY - Contract DE-AC22-80PC 14189 awarded to Colorado School of Mines, Golden, Colorado $237,963.

• MODIFY THE HYGAS PILOT PLANT FOR PEAT GASIFICATION. $3,352,587, Contract ACOI-80ET14688, Institute of Gas Technology, 3424 South State Street, Chicago, Illinois.

• RESIDUAL SHALE OIL/DIESEL ENGINE OPERATING COMPATIBILITY, DE-ACI9-80BC10114 (19- 30BC10071), $319,990 awarded to Acurex Corp., 485 Clyde Avenue, Mountain View, CA.

• FULL SCALE PILOT FACILITY for the Dry Cooling of Coke Contract DE-FC07-80lDI2168 U.S. Steel Company, Monroeville, PA.

• HIGH MAGNETIC FIELD MHD GENERATOR PROGRAM. Unsolicited Proposal $2,300,000. Contract AC0I- 80ET1561 I Stanford University, Stanford, CA.

• DEVELOPMENT OF NEW BUSINESS OPPORTUNITIES FOR MINORITIES IN THE SYNTHETIC FUELS • PROGRAM. $198,483 contract ACOI-ZOM 101005 to Ronson Management Corp., Alexandria, VA.

• ENVIRONMENTAL ASSESSMENT OF THE HYGAS PROCESS. Unsolicited Proposal $254,546 contract EX-76- C-0l-2433 to Institute of Gas Technology, 3424 South State St., Chicago, IL.

• THERMOCHEMICAL CONVERSION OF BIOMASS TO SYNTHETIC FUELS USING A LARGE EXPERIMENTAL FACILITY, Modification No. A001 to Contract DE-ACO2-79ET23029, $150,000. University of Missouri, Columbia, MO.

• OIL SHALE DATA PLANNING COMMITTEE -- DE-ACO2-78EVO4708.A002__$49,277 Development Engineering, Inc., Rifle, CO.

• SEPARATION OF SELECTED CATIONS BY LIQUID MEMBRANES -- DE-ACO2-78ER05016.A002_$55,000 Brigham Young University, Provo, Utah.

• IDENTIFICATION OF SULFUR HETEROCYCLES IN COAL LIQUIDS AND SHALE OIL -- DE-ACO2- 79EV01237.A001--$126,000, Brigham Young University, Provo, Utah.

• COAL RESEARCH: Task orders August 29, 1980 to West Virginia University, Morgantown, VA under Contr. DE-AT2I-79MCI 1284 in the following research areas: Task order 8, Mod. 1, Effects of Effluents of Coal Combustion and Gasification on Lung Structure, $82,150; Task Order 25, in-Bed, Hydrocarbon Alkali, and Trace Metals in the Coal Conversion Processes, $31,403; Task Order 26, Magnetic Susceptibility and Particle Size Distribution, 26,909; Task Order 27, Coal Mineral Interactions in Gasification and Combustion Processes, $49,747; Task Order 28, Reactions of Alkali Metal Containing Species in Gasification, $40,000; Task Order 29, Study of Coal Conversion and Combustion Wastes for Production of Light Weight Cellular Concrete, $89,500.

• MATERIAL SURVEILLANCE PROGRAM FOR A 3/4 TON PER HOUR HYDROGASIFIER, Unsolicited Proposal, $139,828, Contr ACOI-78ET 10283, Awardee/Contractor: Rockwell International, 8900 Desoto Avenue, Canoga Park, CA.

• IN-DEPTH ANALYSIS OF COMMERCIALIZATION ACTIONS for Synthetic Alternate Fuels, New Inventions, Advanced Heat Engine (Turbine and Stirling), and Vehicle Systems for the Heat Engine System Program, Contr. DE-ACO2-73CS54394.A006, $266,760. ORI, Inc., Silver Spring, MD.

• DEVELOPMENT OF ENVIRONMENTAL ASSESSMENT SCREEN-CRITERIA FOR COAL CONVERSION SOLID WASTES, Contr. DE-80PC30098 awarded to Bioassay System Corporation, 225 Wildwood Woburn, MA, $94,684.

• SUPPORT SERVICES FOR THE OFFICE OF COAL UTILIZATION, REP DE-RPOI-79ET 15405. Dollar Amount: $150,000 (Letter Contract). Contr AC0I-80ET17036. Awardee/Contractor, Energy Resources Co., Inc., Cambridge, MA 02138.

• SECIJRITY REQUIREMENTS ANALYSIS FOR U.S. ENEGY RESOURCES. Solicitation RPOI-80DP3021Y Dollar Amount: $134,320. Contract AC0I-30DP30214 Awardee/contractor: Presearch, Arlington, VA 22202.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-35 • THEORETICAL STUDY OF PILOT SCALE PETC COAL LIQUEFACTION REACTOR, The University of Pittsburgh, for $31,069, Grant OE-FG22-80PC20075.

• COAL GASIFICATION PILOT PLANT STUDIES, Contr. DE-AC2I-80MC14706, August 7, 1980, $844,757 to Institute of Gas Technology, Chicago, IL.

• TECHNICAL SUPPORT SERVICES FOR THE OFFICE OF COAL UTILIZATION, (RIP RPOI-79-ET15405), $125,000, Letter Contr. ACOI-80ET17087, SMC Corporation, Washington, DC.

• CONTROL OF EMISSIONS FROM COAL with a Chemically Bound Sulfur Scavenger $50,000 Arnd. No. A004 to Task Agreement No. W-7405-Eng-92- lii Battelle Columbus Laboratories, 505 King Avenue, Columbus, OH. • HEALTH EFFECTS OF COMBUSTION GENERATED SOOT AND POLYCYCLIC AROMATIC HYDRO- CARBONS Contr. DE-ACO2-77EVO4267.A005 $320,000, Massachusetts Institute of Technology, Cambridge, MA. • SYNTHETIC FUEL AROMATICITY AND STAGED COMBUSTION Contract DE-AC22-80PC30302, Battelle Memorial Institute, Columbus Laboratories, 505 King Avenue, Columbus, Ohio, $246,249. • CONTINUATION OF "RESIDUAL SHALE OIL/DIESEL ENGINE OPERATING COMPATIBILITY," Contr. DE- AC I 9-8OBC 10113. Modification A00I, $341,412, awarded to Energy & Environmental Research Corporation, Santa Ana, CA. • PETROLEUM SUBSTITUTION BENEFITS OF ALCOHOL FUELS FROM VARIOUS RESOURCES, Solicitation RP0I-69CS50005, $126,290, Contr ACOI-80CS50005, Awardee/Contractor: Jack Faucett Assoc., Inc., 5454 Wisconsin Ave., Chevy Chase, MD. • STUDY OF LOW ENERGY PROCESS for Separating Hydrogen and Methane in Advanced Coal Gasification Processes. Contract DE-AC2I-80MC 14386. Research Foundation of the State University of New York. Cost rei,nburse;nent Contract $119,046, Sept. 1980. • STUDY OF POLLUTANTS EMISSION CONTROL in the Design and Operation of Fluidized-Bed Combustion System, to West Virginia University, Morgantown, WV 26505, 9-05-80, a Task Order 30 to Contr. DE-AT2I- 79MC11284. $56,000.

• SUPPORT TO SOLVENT REFINED COAL-SRC II DEMONSTRATION PLANT; WORK TO BE PERFORMED AT HAWARVILLE, PA. Unsolicited Proposal. Dollar amount: $1,316,359. Contr. ACOI-79ET10104, Awardee/Contractor: The Pittsburgh & Midway Coal Mining Co., 1720 E. Bellaire St., Denver, CO. • DEVELOP A DESULFURIZATION PROCESS OF OPERATING AT THE GASIFIER QUINELI EXIT TEMPERA- TURE. Unsolicited Proposal. Dollar amount: $345,950. Contr. ACOI-ET15288, Awardee/Contractor: General Electric Co (R&D) Bldg. 5, Rm 5, P.O. Box 425, Schenectady, NY. • RESEARCH EFFORT INVOLVING ANALYSIS OF SULFUR REMOVAL BY NATURAL SORBENTS IN WESTERN COAL ASH DURING FLUIDIZED BED COMBUSTION to University of Texas at Austin, P.O. Box 726, Austin, TX. (Est) $58,900. Contr. DE-AC 18-80FC 10222.

• TWO STAGE PROCESS FOR CONVERSION OF SYNTHESIS GAS TO HIGH OCTANE GASOLINE, to Mobil Research and Development Corp., Paulsboro, NJ, for $1,558,852.00. Contract DE-AC22-80PC30022.

• LIQUEFACTION SOLVENT STUDIES, Contr. DE-ACI8-80FC10205 (DE-RPI8-80FC10205), $71,400 for 3 year effort, Tennessee Technological University, Cookeville, TN. • ANALYSIS OF COAL BASED REFINERY FUEL SYSTEMS. Solicitation. No RIP. Dollar amount: $84,994. Contr. ACOI-77ET 10280, Awardee/Contractor: Mitre Corp.,/Metrek Division, 1820 DoIley Madison Blvd., McLean, VA.

• STUDIES OF THE COMBUSTION OF MODEL FUELS WITH LOW H CONTENT. Contract DE-ACO2- 80ER10661.A000, $55,000, Cornell University, P.O. Box DH, Ithaca, New York.

• STUDY OF NATURE OF THE WATER RETENTION PROPERTIES OF PEAT. Unsolicited proposal. Dollar amount: $235,901. Contract FGOI-80ET14731.

• MHD AIR HEATER DEVELOPMENT Sol. sole source. Dollar amount: $2,332,676. Contract AC0I- 80ET15602.A001. Awardee/Contractor: Fluidyne Engineering Corp., Minneapolis, MN.

• STUDY OF SOOT FORMATION IN SYNTHETIC FUEL DROPLETS to Energy and Environmental Research Corporation, Santa Ana, California, for $298,386, Contract DE-AT22-80PC30298.

1-36 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 • EFFECTS OF BY-PRODUCTS FROM COAL-GASIFICATION and Fluidized Bed Combustion Processes on Alveolar Macrophages of New-born Dogs to West Virginia University to Department of Physiology, Morgan- town, WV 26505, 8028-80, Task Order 9, Contr. DE-AT2I-79MC11284, $49,112. • SUPPORT TO SOLVENT REFINED COAL SRC II dernonstraton plant; work to be performed at Hawarville, Pennsylvania. $1,316,359. Contract No. ACOI-79ET10104. (Unsolicited proposal: Awardee/Contractor: The Pittsburg & Midway Coal Mining co., 1720 S. Bellaire St., Denver, CO.

• DIFFERENTIAL ECONOMIC AND TECHNICAL EVALUATION OF COAL LIQUEFACTION, City University of New York/City College Research Foundation, $100,000. Contr./Grant DE-FG22-8OPC 30276. • DEVELOPMENT OF SCREW FEEDER AND PISTON FEEDER SYSTEMS FOR COAL MATERIALS HANDLING. Contract DE-AC2I-80MC14600, $1,472,025, August 25, 1980, Ingersoll-Rand Research, Inc., Box 301, Princeton, New Jersey.

• OIL SHALE RISK ANALYSIS PROGRAM, Mod. A002, Contr. DE-ACO2-79EV10298, $733,983, University of Colorado, Boulder, CO.

• PREPARATION OF A SUITE OF ILLUSTRATED BROCHURES on Coal Gasification and Related Technology. Contract DE-AC2I-80MC14344. Awarded to Consumer Dynamics, Inc., Rockville, MD--Cost- Plus- Fixed- Fee $70,621--September 15, 1980.

• THE MECHANISM OF CATALYTIC GASIFICATION OF COAL CHAR. Contract DE-AC2I-80MC14593. Awarded to SRI International, Menlo Park, CA--Cost-Plus-Fixed-Fee--$331,731--September 23,1980. • STUDY OF LOW ENERGY PROCESS FOR SEPARATING HYDROGEN AND METHANE in Advanced Coal Gasification Processes. Contract DE-AC2I-80MC14386. Awarded to the Research Foundation of the State University of New York, Albany, NY--Cost Reimbursement--$l 19,046.

• EVALUATION OF TAR SAND MINING STUDY Contract DE-AC22-80PC30201 to Ketron, Inc., 530 East Swedesford Road, Wayne, PA for $202,052.

• HOT GAS CLEANUP-ELECTROCYCLONE DEVELOPMENT PROGRAM. Sol RAOI-79ET 15055. Dollar amount $1,268,568. Contract AC0I-80ET17091. Awardee/Contractor: General Electric Co., Schenectady, NY. • STUDIES ON ZEOLITE CATALYSTS. Contract DE-AC22-80PC30187, to Cleveland State University, Cleve- land, Ohio for $29,900.

• ADVANCED HYDROGEN PRODUCTION PROCESSES Interagency Agreement No. DE-A102-80ET260I9. $195,000--Jet Propulsion Laboratory, 4800 Oak Grove Dr., Pasadena, CA.

• ENVIRONMENTAL ASSESSMENT OF COAL GASIFICATION PROCESS. Sol Follow on to existing contract, sole source: Dollar amount: $1,393,891. Contract AC0I-80ET14176 Awardee/Contractor: Carnegie-Mellon University/Mellon Institute, Pittsburgh, PA.

• MODIFICATION AND CONTINUED DEVELOPMENT OF A FAST-FLUID BED COAL GASIFIER. Contract DE- ACO5-80ET10259, awarded September 30, 1980, $1,824,731. Hydrocarbon Research, Inc., 134 Franklin Corner Rd., Lawrenceville, NJ. U.S. Department of the Interior

SITE SPECIFIC INVESTIGATION OF ENVIRONMENTAL PROBLEMS ASSOCIATED WITH SURFACE MINING of heavy oils and tar sands. Modification One Contract 30295027, $217,526, Golder Associates, Kirland (Seattle), Washington. Environmental Protection Agency

ENVIRONMENTAL ASSESSMENT OF LOW AND MEDIUM BTU GASIFICATION. Contract No. 68-02-3137, RFP No. DU-80-A010, $51,500 awarded to Radian Corporation, 3500 Shoal Creek Boulevard, Austin, TX.

VALIDATION OF PROCEDURES FOR PCB'S IN OILS. Contract 68-03-3006 (RFP Cl 80-0500) $193,720 Versark Inc., 6621 Electronic Drive, Springfield, VA

National Aeronautical and Space Administration

ANALYTICAL SUPPORT TO MHD CRITICAL PHENOMENA (FB 165922+A) Contract DEN3-202, September 15, 1980, $4,325,119 STD Research, Arcadia, CA.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-37 ANALYSIS OF TRENDS IN AVIATION FUEL REFINING YIELDS--ENERGY CONSUMPTION & COSTS. (FB 871319) Contract NAS 3-22769, September 30, 1980, $388,709, Exxon Cord, Linden, N). APPLICATIONS STUDY OF ADVANCED POWER GENERATION SYSTEM UTILIZING COAL DERIVED FUELS, Contr. NAS8-33996, $115,644, September 29, 1980, United Technologies Research Center, Silver Lane, East Hartford, CT. Office of Technology Assessment REPORTS WHICH DEVELOP COAL SUPPLY FORECASTS FOR EXISTING FEDERAL LEASES AND ESTI- MATE DEVELOPMENT PROBABILITY FOR EACH LEASE TRACT. Contract 033-4580.0 September 2, 1980, $40,195, Resource Consulting Group, Inc., Washington, D.C. 20036. PREPARE REPORT SUMMARIZING AND ANALYZING CURRENT AND PLANNED MINING ACTIVITIES on, and production potential for, existing Federal coal leases in the states of Colorado, New Mexico, Utah, and OK. Modification to existing contract 033-3050.0. Contract 033-3050.2, September 17, 1980--$47,085--Dames and Moore, Inc., Golden, CO. I/Il I/Il

1-38 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 COMING EVENTS

DECEMBER 1-3, 1980, ARLINGTON, VIRGINIA, AT STOUFFER'S NATIONAL CENTER HOTEL -- "Peat as an Energy Alternative," a symposium sponsored by the Institute of Gas Technology. Registration fee will be $330 for IGT members and $390 for nonmembers. Topics will include: • Resources -. Harvesting and Dewatering • Direct Combustion and Co-Firing • Conversion to Synfuels • Impacts of Utilization • Utilization Plans

DECEMBER 1-3, 1980, WASHINGTON, D.C., AT THE HOTEL WASHINGTON -- The "Toxic Controls Seminar" to be held December 1-2, and the "Hazardous Wastes Disposal Seminar" to be held December 3, both sponsored by Government Institutes, Inc. Fees are $345 for the Toxic Controls Seminar and $185 for the Hazardous Wastes Disposal Seminar.

DECEMBER 1-5, 1980, LEXINGTON, KENTUCKY, AT THE HYATT-REGENCY -- "Symposium on Surface Mining Hydrology, Sedimentation and Reclamation." Resistration fee is $100. Topics will include: Surface and Groundwater Monitoring Groundwater Monitoring at Surface Coal Mines Reclamation of Western Coal Fields Design of Sediment Control Facilities

DECEMBER 2-3, 1980, WASHINGTON, D.C., AT THE WASHINGTON HILTON -- "Hazardous Waste Management Under RCRA and Consolidated Permits," a 2-day conference sponsored by The Energy Bureau, Inc. Fee is $550. DECEMBER 4, 1980, DENVER, COLORADO, AT THE REGENCY HOTEL -- "Designing for the Rocky Mountain Area's Energy Uncertainties," a I-day seminar sponsored by the Professional Engineers of Colorado. Program not available.

DECEMBER 4-6, 1980, SPOKANE, WASHINGTON, AT THE DAVENPORT HOTEL - The Northwest Mining Association's 86th Annual Convention. Program includes one session on energy resources.

DECEMBER 8-9, 1980, HOUSTON, TEXAS, AT THE GRAND HOTEL -- The "Synfuels Environmental Impact Seminar," sponsored by the Association of Energy Engineers and the University of Louisville. Registration fee is $440.

DECEMBER 8- 11, 1980, GOLDEN, COLORADO, AT THE COLORADO SCHOOL OF MINES -- A short course entitled, "Shale Oil" Its Production, Properties, and Utilization." Registration fee is $475. Contact Director of Continuing Education, CSM, Golden, Colorado 80401.

DECEMBER 8-9, 1980, ARLINGTON, VIRGINIA, AT STOUFFER's NATIONAL CENTER - "Synthetic Fuels: Working With New Legislation," a conference sponsored by The Energy Bureau, Inc. Registration fee is $550. Tdpics will include: Siting for Synthetic Fuels Facilities The Department of Defense and Synthetic Fuels Financing Synthetic Fuels in the Real World Government Contracting for Synthetic Fuels The EPA and Synthetic Fuels

DECEMBER 10, 1980, WASHINGTON, D.C., AT THE WASHINGTON HILTON HOTEL - -Cogeneration: The New Regulatory Environment," a workshop sponsored by The Energy Bureau, Inc. Registration fee is $495. Topics will include: Reducing Risk Cogeneration Legislation Constructing and Financing The Rules Case Studies

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-39 DECEMBER 10-12, 1980, NEW ORLEANS, LA., AT THE HYATT REGENCY -- The American Chemical Society's Southeast/Southwest Regional Meeting. Papers to be presented include:

• Calcium as a Steam-Gasification Catalyst--R.J. Land • Dual-Functional Coupling of Methanol and Hydrocarbons From Methanol—C.D. Chang • Model Compounds in Coal Chemistry--C.J. Collins • Spectroscopy of Coal Macerals--K.W. Zilm • Recovery of Energy From Oil Shale--J. H. Weber • Coal Gasification and Gas Cleaning--tIC. Ferrell • Control of Toxic Organic Materials From Coal Conversion Processes--iA. Klein • - Effects of Stainless Steel and Bronze Components on Hydrodissolution of Coal—D.C. Duffy • Solubility Parameter Spectroscopy of Coal—J.M. Sandy DECEMBER 12, 1980, WASHINGTON, D.C., AT STOUFFER'S NATIONAL CENTER -- "Acid Rain: The Problem That Won't Go Away," a forum sponsored by Inside EPA (a weekly report). Registration fee is $550. DECEMBER 11-13, 1980, PHOENIX, ARIZONA, AT THE PHOENIX CIVIC PLAZA -- The Western Mining Show. Program not available. DECEMBER 15, 1980, WASHINGTON, D.C., AT THE SHOREHAM HOTEL -- "Coal Exports: The Booming New Energy Market," a conference sponsored by The Energy Bureau, Inc. Registration fee is $550. DECEMBER 15, 1980, HOUSTON, TEXAS, AT THE WHITEHALL HOTEL -- The "Oil Daily Forum on Profitable Synthetic Fuels Development," sponsored by The Oil Daily. Registration fee is $395. Papers to be presented include: The Government's Synthetic Fuels Policy Fast-Start Programs Federal Policy for Synthetic Fuels Financing Securing Financing From Private Institutions Effective Contracting for Synthetic Fuels Projects Permitting of Synfuels Projects JANUARY 5-9, 1981, FT. COLLINS, COLORADO, AT COLORADO STATE UNIVERSITY— "Design and Construction of Tailings Impoundments," a short course. Registration fee is $495. Topics will include:

Soil Mechanics Compaction Flow Nets and Permeability Earth Pressures Instrumentation Seepage Slope Stability JANUARY 18-21, 1981, HOUSTON, TEXAS, AT THE ALBERT THOMAS CONVENTION CENTER - The "Energy Sources Technology Conference and Exhibition," sponsored by the A.S. Mech. E., Am. Assoc. for Metals, Instrument Society of America, and others. Registration fee is $50. Titles of papers to be presented include:

Sasol Design and Fabrication Problems Solved Anthracite vs. Bituminous Coal Gasification Coal-Oil Mixtures The Coal-Fired Producers Gas Engine Thermal Analysis of Oil Shale Subsidence and Strain Prediction for Multi-Cavity Underground Coal Gasification

JANUARY 26-30, 1981, LAKE BUENA VISTA, FLORIDA, AT THE ROYAL PLAZA HOTEL -- "Fifth Annual Meeting on Energy From Biomass and Wastes." IGT has called for papers to be submitted on the topics shown below: (IGT phone: 312/367-3650). Conversion processes (a) thermal (b) biological Analysis of integrated systems Biomass production Resource requirements Environmental factors Factors affecting commercialization Process economics Net Energetics Chemicals production from biomass Basic research activities Projection of energy use for biomass

1-40 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 FEBRUARY 2-3, 1981, HOUSTON, TEXAS -- "The 1981 Workshop on Instrumentation and Control for Fossil Energy Processes," sponsored by the Society for Control and Instrumentation of Energy Processes.

FEBRUARY 2-5, 1981, GOLDEN, COLORADO, AT THE GREEN CENTER ON THE CAMPUS OF THE COLORADO SCHOOL OF MINES-- "Coal Liquefaction," an intensive 4-day short course. Registration fee is $500. Contact Director of Continuing Education (phone: 303-279-0300). Course Outline: First Day

A. Origin of coal, coal reserves, and resource base teminology B. Coal classification systems C. Coal geology and petrography D. Basic physical, chemical, and geochemical properties of coal E. Inorganic constituents in coal F. Coal structure Second Day

A. Introduction to coal liquefaction--historical perspective B. Coal liquefaction chemistry and mechanisms C. Reactivity of coal towards hydrogenation D. Bergius, Farben, Pott-Broche, TTH, IG-New processes Third Day

A. SRC-I and SRC-11 processes B. H-Coal process C. Exxon donor solvent process D. Other direct hydrogenation processes (Dow, Lurnmus, Synthoil, Gulf CCL, etc.) E. Pyrolysis, flash pyrolysis, hydropyrolysis processes Fourth Day

A. Indirect coal liquefaction, Fischer-Tropsch chemistry and mechanisms B. SASOL I, II, and Ill

FEBRUARY 23-26, 1981, GOLDEN, COLORADO, AT THE COLORADO SCHOOL OF MINES - A short course entitled, "Shale Oil: Its Production, Properties, and Utilization." Registration fee is $475. Education, CSM, Golden, Colorado 80401. Contact Director of Continuing

FEBRUARY 24-28, 1981, CHICAGO, ILLINOIS-- The A.I.M.E. National Meeting. The program has not been announced

MARCH 9-11, 1981, WASHINGTON, D.C., AT THE SHERATON WASHINGTON HOTEL -- The "8th Energy Technology Conference" will carry the theme "New Fuels Era - the 80 1s." The call is out for papers to be submitted for review and possible presentation at ET-8. Conference offices are ET-8, P.O. box 5918, Washington, D.C., 20014 (phone: 301/656- 1090.

APRIL 5-9, 1981, HOUSTON, TEXAS, AT THE ASTROHALL -_ "The AIChE 90th National Meeting and 11th Petrochemical and Refining Exposition." The theme of this meeting is "Energy Expanding Domain of Chemical Engineering." The program includes sessions concerning the following subjects: Materials Considerations in Synfuels Production Project Facilitation and Planning Gasohol Phase Separation in Coal Conversion Systems Hydrogen - Fuel of Tomorrow - Today Olefins Bottom-of-the-Barrel Technology Catalytic Processes for Synfuels Production Solid-Liquid Separation in Coal Liquefaction Status of Synfuels Projects Gas Purification Synfuels Economics Underground Coal Gasification

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-41 APRIL 22-24, 1981, GOLDEN, COLORADO, AT THE GREEN CENTER ON THE CAMPUS OF THE COLORADO SCHOOL OF MINES - "The 13th Oil shale Symposium,' sponsored by the Colorado School of Mines. Program is not finalized. Papers are being reviewed until January 5, 1981. Contact Dr. J.A. Gary of the CSM (phone: 303-279-0300).

1-42 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT GENERAL PUBLICATIONS

"Accelerating Synfuels Development," staff article in EPRI Journal, July/August 1980 edition, Pp. 25-27.

"Acceptable Synfuels Development Seen,' staff article in the Oil and Gas Journal, September 15, 1980 issue, pp. 112-113. Akarca, A.T. and T.Y. Long, "On the Relationship Between Energy and GNP: A Reexamination," in the Journal of Energy and Development, published by the International Research Center for Energy and Economic Development, Spring, 1980, T326- 33 I.

Allen, D., "The EPA Energy Task Force," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980.

Allen, F.W., "How Synfuels Will be Used: An EPA Assessment," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C. on October 16-I8, 1980. 'American Petroleum Institute, "Two Energy Futures: A National Choice for the 80's," 1980, 166 pp.

Amiryafari, B., et.al ., "Alternative Concepts for Supplying CO for Enhanced Recovery Projects," final report (DOE/MC/8333- 1) by Science Applications, Inc., to DOE under Contract EW-78-C-21-8333, 1980.

Berry, R. L, "Treating Hydrogen Sulfide When Claus is Not Enough,' in Chemical Engineering, October 6, 1980, pp. 92-93. Boris, C.M. and J.V. Krutilla, "Water Rights and Energy Development in the Yellowstone River Basin," published for Resources for the Future, Inc., by the Johns Hopkins University Press, 1980.

Boston, C.R., "Synfuels and the N.E.P.A. Process," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980.

Bowden. J.N.."Stability of Alternate Fuels," in Hydrocarbon Processing, vol. 59(7), July, 1980, pp. 77-82. Clusen, Ruth, "DOE Environmental Programs and the Synthetic Fuels Industry," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980.

Coma, L.D.,"Research Programs Relevant to Fossil Energy Technology," report number FE-2468-81 by the Engineering Societies Commission on Energy, Inc., to the U.S. Department of Energy, August, 1980, 56 pp. Corned, H., and F. Heinzelmann, "Hydrogen for Future Refining,' in Hydrocarbon Processing, vol. 59(8), August, 1980, Pp. 85-90.

Cowles, 3.0., "The Use of Synfuels: What Are the Environmental Risks?" presented at the conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980.

Cowles, 3.0., et al, "Utilization of Synthetic Fuels; An Environmental Perspective," presented at EPA's 5th Symposium on Environmental Aspects of Fuel Conversion Technology, St. Louis, Missouri, September 1980.

Delaney, C.L., "The Air Force Prepares for Synthetic Jet Fuel," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980.

Despain, R., "Air-PSD Regulations (Relating to Energy)," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980.

Dreyfus, D.A.," A Senate Energy View," presented at the conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. - "Energy in the Developing Countries," the World Bank, 1818 H Streeet, N.W., Washington, D.C., August 1980.

"Energy Technology VII," the Proceedings of the 7th Energy, Technology Conference which was held in Washington, D.C., July, 1980.

Flowers, W.,"U.S. Synthetic Fuels Corporation Finanacial Incentives," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980. 'Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-43 RECENT PUBLICATIONS -GENERAL Fumich, C., "The DOE Program for Synthetic Fuels," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Gazda, L., "Hazardous Waste Regulations (Relating to Energy)," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980. Govan, Emilia, "A Department of Energy View of Synfuels Regulation," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. Gregg, D.W., et al., "Solar Gasification of Coal Activated Carbon, Coke and Coal and Biomass Mixtures," in Solar Technology, November 4, 1980, pp. 353-364. Hadaller, 0.3., and A.M. Momenthy, "Alternative Fuels for Aircraft," a pamphlet produced and published by the Boeing Commercial Airplane Company, Preliminary Design Department, P.O. Box 3707, Seattle, Washington 98124, 1980. Harsch, W.J., "Planning for the New Synthetic Fuels Corporation," presented at the Synfuels Industry Development Seminar of Government Institute, Inc., held at Washington, D.C., on November 6-7, 1980. Herschler, Ed., (Gov. of Wyoming), "Blueprint for the Responsible Development of Synthetic Fuels in the West," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980. Hill, Richard, "Comparative Review of Synfuels Technologies and Energy Resources," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980. Hinkle, 3., "Environmental Development Capacity for Siting Synfuels Industries," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. Hoffbuhr, 3., "Water/UIC (Relating to Energy)," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980. Hurtubese, R.J., "Separation and Determination of Polycyclic Aromatic Hydrocarbons and Nitrogen Heterocycles Pertaining to Coal Gasification, Tar Sands, Shale Oil, Coal Liquids, and Related Samples," final report to DOE of work done under contract by the University of Wyoming, report /IDOE/LC/01761-TI, 1980, 50 pages. "In Situ Minin--Moving Closer to Reality," published by Technical Insights, Inc., 158 Linwood Plaza, Fort Lee, N.J., 07024, price: $380. International Energy Agency, "Energy Policies and Programmes of lEA Countries," published by the Organization for Economic Cooperation and Development, 1980. OECD address is 2, Rue Andre Pascal, 75775 Paris, CEDEX 16, FRANCE. -International Energy Agency, "Energy Research, Development and Demonstration in the lEA Countries: 1979 Review of National Programmes," published by the Organization for Economic Co-Operation and Development, Paris, 1980.

Lee, Bernard S., "Synthetic Fuels and the Total Cost of Oil Imports," in IGT Gascope, Summer 1980, No. 50, pp. 2-6. Lukens, Larry, "Opportunities in the DOE Resource Applications Synfuels Program," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980. Metzger, H.P., "Government-Funded Activism: Hiding Behind the Public Interest," 1980. Copy available from the office of H. Peter Metzger, Mgr., Public Affairs, Planning Division, Public Service Company of Colorado, P.O. Box 840, Denver, Colorado 80201. Phone: (303) 571-7412. "Missouri River Basin Water Resources Management Plan and Draft Environmental Impact Statement," prepared by the Missouri River Basin Commission, May 1980. *"National Energy Outlook: 1980-1990," shell Oil Company, August 1980. This updates a previous Shell assessment of the national energy supply, and supercedes "The National Energy Outlook," published in June 1978. Copies are available from Shell Oil Company, Public Affairs, Room 1535, P.O. Box 2463, Houston, TX 77001. "National Energy Transportation Study," a report to the President by the Secretary of Transportation and the Secretary of Energy, July 1980, 285 pages.

Nulty, P., "The Tortuous Road to Synfuels," in Fortune, September 8, 1980, pp. 58-64. Reviewed in this issue

1-44 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT PUBLICATIONS -GENERAL Papay, L., "Synthetic Fuels in California," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Pasternak, Bruce, "Market Forecast: Where the Synfuels Industry is Headed," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980. -Petroleum Industry Research Foundation, Inc., "Oil in the U.S. Energy Perspective--A Forecast to 1990," published by PIRINC, 122 East 42nd Street, New York, 10168, May, 3980. Princiotta, Frank, "Report on EPA's Pollution Control Guidance Documents," presented at the conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. "Proceedings of the Alcohol Fuels Symposium," sponsored by the Center for Energy and Mineral Resources, Texas A&M University, College Station, Texas 77843, 1980, price $5.00. Redding, M.J., "Managing the Socioeconomic Challenge to Synfuels," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. Reid, R.R., "Air Quality Standards and Synfuels Costs," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-I8, 1980. Roach, C.R.,"How Environmental Regulation Will Affect Price and Supply (of Synfuels)," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. Satterfield, C.N.," Fischer-Tropsch Synthesis in a Slurry Reactor," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November 1980. Shackson, R.N. and N.J. Leach, "Using Fuel Economy and Synthetic Fuels to Compete With OPEC Oil," an interim report of the Energy Productivity Center of Mellon Institute, a division of Carnegie-Mellon University, 1980, 101 pp. Schwartz, B., "The Importance of Synthetic Fuels to Oil Burning Utilities," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Stoeger, H.G. and R. Holighaus, "The Federal Republic of Germany's Energy Program," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 3980. Sullivan, R.F., et al., "Upgrading of Synthetic Crudes to Distillate Fuels," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Sumpter, R., "Commercial U.S. Synfuels Output Seen by Late 1980's," in Oil and Gas Journal, October 27, 1980 issue, pp 27-31. "Synthetic Fuels: The Processes, Problems and Potential," in The Lamp, Exxon's quarterly report to stockholders, Summer 1980 issue, pp. 3-7, inclusive. "The Impact of Including Fugitive Emissions From Mining Operations on Contiguous Processing Facilities," a report to the EPA by Energy and Environmental Analysis, Inc., March, 1980. *'The Global 2000 Report to the President: Entering the Twenty-First Century," a report to the President by the Council on Environmental Quality and the Department of State, 1980, in three volumes: Vol. I, The Summary Report--SN 041- 01 1-00037-8, $3.50; Vol. 2, The Technical Report--SN 041-011-00038-6, $13.00; Vol. 3, The Government's Global Model, SN 041-011-00051-3, $8.00. Copies are available from the U.S. Government Printing Office. "The U.S. Synthetic Fuels Program," produced by the editors of Synfuels, published by McGraw-Hill, November 1980, 295 pages.

Thoem, T.L., "An EPA Regional View of Synfuels Regulation," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. Thoem, T.L.,"How Visibility Regulations Will Affect Energy Developments in the West," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. Thomas, A.K. and J.H. Bristol, "The Petroleum and Mining Industries of Colorado: A Fact Book," published by the Control Bank of Denver, 1515 Arapahoe Street, 80292, 1980, 34 pp. -Reviewed in this issue

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 1-45 RECENT PUBLICATIONS - GENERAL Tunderman, D,W., "How EPA is Organized for Synfuels Regulation," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-IS, 1980. U.S. Alcohol Fuels Commission, "AlcoholFuels and the Energy Security Act," a 44-page brochure, published in September, 1980 and available from the Commission's publication office at 412 First Street, S.E., Washington, D.C. 20003. -U.S.. Department of Energy, "Low Energy Futures for the United States," report number DOE/PE-0020 prepared by the DOE's Assistant Secretary for Policy and Evaluation, June, 1980, 75 pp. plus appendices. U.S. Department of Energy, "Technology Characterizations," an environmental information handbook, DOE/EV-0072, June, 1980. U.S. Department of the Interior, Water and Power Resources Service, "Upper Colorado Resource Study--Colorado and Utah," May, 1980, 156 pp U.S. Environmental Protection Agency, "A Guide to the Consolidated Permit Regulations," 30-page pamphlet available from Library Services MD-35, EPA, Research Triangle Park, N.C. 27711. U.S. Environmental Protection Agency, "Energy From the West: Summary Report," prepared for EPA by the Science and Policy Program, Univerity of Oklahoma, 1980, 38 pp. U.S. Environmental Protection Agency, "Protecting Visibility: An EPA Report to Congress," report number EPA-450/5- 79-008, October, 1979 (publishing date delayed to Sept. 1980). U.S. General Accounting Office, "Changes in Public Land Management Required to Achieve Congressional Expectations," a report (No. CED-80-82) by the Comptroller General to the Congress of the United States, July 16, 1980. U.S. General Accounting Office, "Federal-State Environmental Programs: The State Perspective," a report to the Congress of the United States by the Comptroller General, report number CEO-SO- 106, 1980. U.S. General Accounting Office, "Oil and Natural Gas From Alaska, Canada, and Mexico--Only Limited Help for U.S.," a report (EMD-80-72) to the Congress of the United States by the Comptroller General, September 1980. U.S. General Accounting Office, "Potential of Ethanol as a Motor Vehicle Fuel," a report to the United States Senate by the Comptroller General, report No. EMD-73, June 1980. Vinson, L., "Consolidated Permit Regulations and NPDES Regulations (Relating to Energy)," presented at the U.S. Environmental Protection Agency Energy Conference, held in Denver, October, 1980. "Western Water Resources: Coriing Policy and Problems," the Proceedings of the conference, published by the Westview, Press, Boulder, Colorado, September, 1980, 324 pp. White, D.C., 'Energy Choices for the 1980's," in Technology Review, August/September 1980 issue, pp. 30-40.

Reviewed in this issue

1-46 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Inc \ c1 JO. sJlhi.atJite

PROJECT ACTIVITIES

STATUS OF MAJOR PERMITS PRESENTED C-a PROPOSES SURFACE MINE FOR LIJRGI DEMONSTRATION In mid-October, we conducted a review of the status of major permits for oil shale projects. Table 1 is a Rio Blanco Oil Shale Company, a partnership between summary of major permits. Colony is the only commer- Gulf and Standard of Indiana for the development of cial oil shale project that has virtually all major per- Prototype Lease Tract C-a, has presented its plans to mits and approvals. Union Oil Company of California the State of Colorado for construction of a 4,400 TPD, has all of the approvals necessary to operate a nominal single screw Lurgi-Ruhrgas retort. Permits for the 9,000 BPD demonstration module for an estimated 20 project are being coordinated through the Colorado Joint years. Union has modified its plans upward to produce Review Process. Rio Blanco has executed a letter of 10,000 BPD from 12,500 TPD of oil shale. Union has understanding with the Colorado Department of Wildlife also applied for permits for a 10,000 BPD upgrading to acquire 457-acre tract of land adjacent to the north plant. Tract C-a is permitted for its "modular develop- of Tract C-a. This smaller tract will accomodate the ment phase," during which time it will operate modified Lurgi retort and spent shale disposal. in situ test retorts. Tract C-b, likewise, has permits for its pre-commercial 'ancillary' phase, which will last Oil shale for the Lurgi demonstration will be mined from until 1987. The permits held by Multi Mineral Corpora- a small, 20-acre open pit located near the northwest tion, Geokinetics, and Oxy (Logan Wash) are for corner of Tract C-a. Up to 9 million tons of overburden research and development operations only. Chevron, will be removed to permit the mining of 1.5 to 3 million Superior, Paraho, and Tracts U-a/U-b have not submit- tons of oil shale ranging in grade from 18 to 35 CPT. It ted applications for major permits. is estimated that 1.5 million tons would support the demonstration for 18 months. Development of the An EIS (Environmental Impact Statement) is being pre- modified in situ retorts does not offer the needed pared by DOE for single surface retort modules for production capacity (underground ore could be mined at Paraho and Superior; Tracts C-a and C-b will also be only about 2,000 TPD), and it would yield a limited included. The lath U.S. Circuit Court of Appeals has selection of grades. Some of the overburden will be used ruled that the 1973 EIS for the Prototype Leasing as fill for a mine haul road to the retort--the road will Program is adequate. Some private ventures, such as have a grade between 6 and 8 percent. Rio Blanco Union and Chevron, are proceeding in such a way to anticipates up to 2,500 GPM of water in the pit, compar- obviate the need for an E15 at this time. able to what they have encountered in their underground mine. The configuration of reinjection wells will be A DUP (Detailed Development Plan) is required for the modified as needed to accomodate this additional water. prototype oil shale leases only. White River Shale Project (U-a/U-b) has updated its DDP and hopes to The Lurgi retort will be a scale-up, by a factor of 176, of begin construction in one year. Both C-a and C-b a 25 TPD pilot plant in Frankfurt, West Germany. The submit modifications to their DDPs from time to time, structure will be about 250 feet high and have a stack with approval being granted by the Area Oil Shale about 280 feet high. Crushing and grinding facilities will Supervisor (USGS). C-a is preparing a revision for a be located in a building near the process unit. Lurgi-Ruhrgas demonstration module and surface mine. C-b is preparing a revision to enable surface retorting Rio Blanco cites the following advantages for the Lurgi: and to increase total production to 100,000 BPD. If Interior allows Multi Mineral Corporation to recover • In contrast with the MIS approach and most shale oil from its sodium leases, a DDP may be re- other aboveground retorts, it produces a high quired. Multi Mineral Corporation plans to submit its Btu gas product. mining plan for a nahcolite mine to USGS in January 1981. It is not known if an EIS will be required for the • It maximizes energy recovery mostly because nahcolite mine on the Federal sodium leases. it utilizes coke, carbon, and oil residue on the spent shale to provide energy for retorting. Most major rights-of-way are granted, not to the pro- ject, but to utilities for power lines or to counties for • The Lurgi is less sensitive to fines than some roads. BLM does environmental assessments before other processes. granting rights-of-way. • The environmental impact can be minimized The State of Colorado has not required the projects to because it cleans up the spent shale and apply for a hazardous waste disposal permit. Garfield - because conventional, proven equipment can County, Colorado, requires a solid waste permit, but be used to meet regulatory requirements. Rio Blanco County, to the north, includes solid waste in its land use permit. • The Lurgi design uses proven components which reduce or eliminate risk.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-I o a o I! z z j z z z t z z x z

mm C C &CC Co

< 1 a to Z — 2 2 S 2 - 2 2 2 2 Zft aza 0Z aaa aa C C C C C C C C

S WC t C5 C flCC CCC C1-c I C ,1, -& * 0 0 0 0 0 0 0 0 C z z z m z z - 0 ti

i z m Z 0 0 0 0 0 0., Z = X Z Z Z • Cc

t•t t I; - 2 I ! & !

1 -t t U C C ii C CCUUI C -- C £

tt ttt tt i: c5. Ca C 0 Caaa C C CEa c S

E:Ii jj j

2-2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Construction is scheduled to commence May I, 1981. Mississippian-Devonian black shale sequence. This con- Operation should begin early to mid 1983. The demon- tract was discussed in the June 1977 issue of Synthetic stration period is planned to last IS months, but it is Fuels on page 2-13. possible it will be extended to 36 months. In Situ Fracturing Methods Are Tested Overall contractor project management responsibility for satisfactory completion has been assigned to the CE During the period from May 1977 to May 1979, ten wells Luminus Co., which will be in charge of retort construc- were drilled, cored, and logged for a hydraulic/explosive tion and will design and construct support facilities. fracturing experiment. Attempts to induce horizontal Lurgi Corporation will provide the process design and fractures in the initial wells, 1/101 and 102, were unsuc- detailed engineering for the retort. H. B. Zachry Co., cessful; vertical fractures were induced instead. under CE Lummus' guidance, will assemble the plant and Hydraulic fracturing and sand propping further enlarged provide construction labor. The surface mine will be these and created new vertical fractures. Four more under the aegis of Morrison-Knudsen. Environmental wells were drilled near Well (/102, hydrofractured and Research Technology, Inc., has been hired to perform air propped. Explosives were detonated in all six of the 100 dispersion modelling, and Hazen Laboratories is doing series wells in late 1978, greatly improving the permea- analytical testing work. Spent shale research is being bility in the region. Post-explosive tests showed that air conducted by Gulf and Standard, as well as Colder, could be injected into Well 1/103 at a rate of 125 scfm at Naperville Research, and Nation Plants' Inc. 400 psig and into Well 1/105 at 110 scfm at 640 psig. Four more wells were completed in May 1979, for use in fall/f/li additional fracture evaluation. Air permeability tests, differential temperature logging, a spinner survey, and RIO BLANCO IGNITES FIRST MIS RETORT television camera logs were completed in addition to the more routine logs. Rio Blanco Oil Shale Company, a general partnership of Gulf Oil Corporation and Standard Oil Company (Indiana) Five wells were drilled, cored, and logged for a chemical and lessee of Federal Prototype Lease Tract C-a, have underreaming experiment. An acid underreaming experi- produced the first shale oil from a Federal lease. Retort ment in January 1978, with 28 percent hydrochloric acid 0, which is 30 x 30 x 166 feet high, was ignited on produced a much smaller cavity than had been antici- October 13, 1980. A downhole burner was lowered from pated. A number of laboratory experiments with core the surface through a 12-inch vertical casing 670 feet to samples were completed, and a narrow region of interest the retort. A mixture of natural gas and air was used for was identified. In November 1978, the central well was ignition. hydrofractured under conditions best suited to produce a horizontal fracture, but communication with the nearby The burn could take up to nine weeks, depending on the wells was not achieved. Subsequently it was concluded rate of the burn which is controlled by injection of air that this site would not be used for an extraction trial, and steam. The first oil was recovered within a month. and no further work was carried out on this experiment. Rio Blanco anticipates that from 1,000 to 2,000 barrels will be recovered. The oil will probably be used in Wells (/301-305 were drilled, cored, and logged early in various research and testing programs. Two additional 1978 for explosive underreauning experiments. Four MIS retorts will be burned by the end of 1981. Rio explosive shots were attempted in the central well, Blanco's MIS retort technology is described in the Sep- 1/301; three were successful. The well was cleaned after tember 1979 issue of the Cameron Synthetic Fuels each shot and logged. The cavity was enlarged by each Report on page 2-7. shot, and some casing damage occurred during the final shot. Wells (/306 and 307 were drilled early in 1979 near Ill/lI (I Well #301. Coring and flow logging of these wells showed that significant fracturing had been accom- DOW COMPLETES DOE ANTRIM SHALE CONTRACT plished by the shots in Well 1/301. In April 1979, an explosive charge was detonated in Well (/306 and in On September 30, 1980, Dow Chemical Company com- (/307. Permeability and interwell communication in the pleted a contract which began on October I, 1976. Dow 300 series were found to be comparable to that in the was to conduct shale characterization studies on Antrim 100 series wells. TV logs and an airflow/tracer gas shale, carry out and evaluate the results of three in situ survey helped to corroborate the extent and location of fracturing experiments, carry out an in situ extraction the fracturing. A good communication pattern connects trial in already existing wells and an extraction trial in Wells #301, 305, 306, and, to a lesser extent, 307. For the site of the most effective fracturing experiment and this and other reasons, the 300 series was chosen as the to monitor the environmental impact of these activities. site for the next extraction campaign. Although the final reports have not yet been published, In Situ Extraction Trials Are Performed most of the results of the study are found in the penultimate quarterly report to DOE: "Energy from In The extraction trials planned for the existing site were Situ Processing of Antrim Oil Shale, Quarterly Technical completed in 1978. Two trials using an electric heater Progress Report for April-June 1980," available from to initiate combustion were aborted after electrical NTIS as document number FE-2346-72. Site restoration short circuits occurred. After the heater was modified, and disposal of equipment continued for a short time into it operated for several days, and analysis of effluent fiscal year 1981. The experiments took place on Dow gases indicated that combustion had been sustained for property near Midland, Michigan, within the up to ten days.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-3 A coal- and charcoal-augmented combustion trial was and completion activities and the fracturing and assess- conducted in Well (/4 in February 1978, using a propane ment activities. No air or water quality problems due to burner for ignition. Combustion was maintained at a activities during this contract have been observed. high level for about one week, and CO and CO were present in the effluent gases for anoTher ten days. I/I/Il II Greater quantities of hydrocarbons, carbon monoxide and hydrogen were produced than during previous trials. PARAIIO'S PLANS ARE REVIEWED A charcoal-augmented combustion trial in Well //7 began As reported on page 2-1 of the June 1980 issue of the at the end of March 1978 and continued for 61 days, Cameron Synthetic Fuels Report and on page 1-22 of the while several continuous and cyclic production proce- September 1980 issue, Paraho Development Corporation dures were tested. Gas having energy values in the is involved in several programs leading to a commercial- target range (ISO Btu/scf) was produced at various sized 10,000 BPD module and ultimately to a 30,000 BPD times, although the flow rate at these times was minimal plant. and hence the energy production was low. There was no significant heat damage to the propane burner, whereas Under a cooperative agreement arising from in the previous run the burner was severely damaged. a surface retort PON (Program Opportunity Analysis of product gases showed a total energy content Notice), final design engineering is being 4.9 times that of the total solid and gaseous fuel put into undertaken for a 10,000 BPD module. the well for ignition. Paraho is negotiating with DOE to perform a In March 1979, in preparation for the extraction trial to feasibility study regarding a three-module be run on the new site, a downhole methane burner 30,000 BPD plant, as part of appropriations developed by Tejas Petroleum Engineers, Inc., and opera- from P.L. 96-126. ted by TOR Development, Inc., was tested in an existing well under realisitic operating conditions. The burner Paraho has submitted a proposal, under P.L. operated successfully for more than 80 hours and was 96-304, for a cooperative agreement with reignited several times without difficulty. This burner DOE for construction of the 10,000 BPD was modified for use in subsequent extraction trials. module.

Using redesigned equipment and modified operating pro- Paraho is applying for a loan guarantee from cedures, based on knowledge gained by the experiences DOE (until establishment of an operational in the extraction trials on the existing site, preparations Synthetic Fuels Corporation) of $975 million, for a new series of extraction trials were completed which is 75 percent of the total cost of $1.3 during the last quarter of Pt' 1 79. Extraction trial F80-I billion for construction and operation of a was initiated in October 1979, using an ignition service 30,000 BPD plant. provided by TOR Developments, Inc. A methane burner was installed in Well 1/301 which was then equipped with The first module is scheduled to be completed in mid- the necessary auxiliary piping and the explosion protec- 1984, the second and third in spring and fall of 1985, tion barrier. Burner ignition was readily obtained and respectively. Each module will be 138 feet long by 25 shale combustion occurred within two days. Combustion feet wide by 100 feet tall. We stimate that the in the wellbore was so intense that the burner was lost throughput will be about 434 lb/hr/ft if 18,000 TPD of and shale combustion decreased thereafter. Therefore, 23 GPT shale are processed. The retort module will have the trial was terminated. eight oscillating parallel bar discharge grate mechanisms and eight raw shale distribution assemblies. Chevron After modification to permit better air cooling, extrac- hydrotreating and wastewater treatment processes will tion trial P80-2 was begun late in November 1979. be used, as will Stretford technology. Upgraded shale oil During this trial, which continued until mid-February, will be sent to refineries. Paraho plans to send 10,000 combustion was maintained with intermittent use of BPD to the Plateau refinery in Roosevelt, Utah, and injected methane. However, recovery of injected gases 20,000 BPD to the Gary Western refinery near Fruita, during much of the run was quite low; near the end, Colorado. Twelve thousand BPD will be transported in recovery was down to about 6 percent. During depres- the existing pipeline which was built to slurry gilsonite surization after air injection had been stopped, signifi- from the mine in Bonanza, Utah, to the Gary Western cant amounts of low Btu gas were recovered, and it refinery. became apparent that much of the injected gas may have been lost through a break in the casing. The labor force is expected to peak in early 1985 at 1,500. After 1986, when construction is complete, the The final trial, F80-3, was carried out in March 1980, labor force should number around 800. using a fresh well for injection. Combustion was achieved readily and good material balances of injected I/I/fill oxygen were obtained. Again the limited quantities of low Btu gas were produced and resistance to flow through the formation increased significantly when the formation was hot. The only major environmental impact has been the surface disturbance to the site due to the well drilling

2-4 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 UNION DISCUSSES PROJECT PLANS IN SHAREHOLDERS' REPORT In its shareholders report for the quarter ending Septem- ber 30, 1980, Union Oil Company of California discusses its plans for its Long Ridge oil shale project. Herewith are excerpts.

"We are looking forward into the 80 1s. The company has just announced a very exciting project putting it into the synthetic fuel business. Union is proceeding with the installation of a 50,000 barrel per day shale oil complex in Colorado in the belief that adequate financial assis- tance can be negotiated with the federal government. "Our construction schedule calls for the building of a 12,500 ton per day mine and retort and a 10,000 barrel per day raw shale oil upgrading facility with a comple- tion date of 1983. 'Following along will be four more mines and retorts and two 20,000 barrel per day upgrading facilities. Full 50,000 barrel per day operation is expected by 1988. The entire cost of the project will be in the order of two billion 1980 dollars.

"The synthetic shale oil produced will be of higher quality than any known conventional crude oil. It will be essentially free of sulfur, nitrogen, and heavy residual fuel. A typical modern refinery could convert this synthetic crude into 100 percent transportation products II il//Il

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-5 LAND

50Mb, CLEVELAND-CLIFFS, SUPERIOR ANNOUNCE for oil shale development. IPAMS' position paper ignores JOINT RESOURCE HOLDINGS the efforts by the Department of the Interior to address this issue. As reported on page 2-22 of the September On November 10, 1980, The Cleveland-Cliffs Iron 1980 issue of the Cameron Synthetic Fuels Report, Company announced the sale of a portion of its interest Interior has established a Land Use Planning Review in fee oil shale lands to the Standard Oil Company (Ohio) Work Group which will inventory the characteristics of for $15 million. The sale triggered several land interest resources other than oil shale. The inventory is sche- exchanges that will enable Cliffs, Sohio, and Superior Oil duled for completion by August 15, 1981. Site specific to combine efforts in accelerating the development of a analysis and identification of resource conflicts will be commercial oil shale facility. completed by December 15, 1981. Superior's own commercial development efforts, under- IPAMS' Position Paper Reproduced way since 1969, have been frustrated by recent govern- ment decisions rejecting a proposed land exchange invol- Herewith is the complete IPAMS position paper: ving Federal lands that would have permitted develop- ment of Superior's 7,000-acre tract (TIN, R97W, 6 PM) "After a thorough study of the history and status of oil at the confluence of Piceance Creek and the White shale in the Rocky Mountains, the Independent Petro- River. leum Association of Mountain States, representing more than 1,200 oil and gas operators in the region has Agreement was reached to pool interest in a 13,000-acre reached the following conclusions: plot called the Pacific property (T6S, R98W, 6PM), that was 60-40 owned by Sohio and Cliffs, with Superior's 1. In the public interest the prompt determina- tract. The Pacific property is about 10 miles north of tion of the most economically feasible and DeBeque, Colorado, on the southwestern side of the environmentally acceptable means to achieve Piceance Creek basin. The joint venture processing large volume shale oil production is urgently facility will be sited on the Pacific property. needed. As shown on the map in Figure 1, the new ownership of 2. For the foreseeable future sufficient public these tracts is now: and private lands are presently committed and readily available for exploitation by all Superior Tract known extraction methods. - Superior 60 percent - Sohio 30 percent 3. Before any further leasing of federal lands - Cliffs 10 percent containing oil shale is undertaken, master Pacific Property resource use plans for these lands should be - Sohio 60 percent completed. - Superior 20 percent - Cliffs 20 percent 4. The resource use plans should include multiple use concepts wherein compatible These arrangements allow Superior, as operator of Phase arrangements are provided for the simultan- I for the three-company group, to pursue Superior's DOE eous extraction of natural gas and oil, and cost-sharing contract, which includes the engineering of shale oil. a commercial demonstration oil shale plant including mine auxiliaries and off-sites, detailed design of the "The IPAMS study also indicated that closer coordination Superior retorting process, and environmental com- of Federal oil shale activities by the numerous agencies pliance and permits on the Pacific property. Future now involved will be necessary if the needed near-future plans include construction of a 15,000 BPD demonstra- shale oil acceleration goal is to be achieved." tion module and subsequent expansion to 50,000 BPD. Due to the virtual absence of nahcolite and dawsonite on Tight Natural Gas Is the Issue the Pacific property, multi-mineral recovery will not be pursued. There are over 450 existing Federal oil and gas leases in the Piceance Creek basin region. A recent Federal #1111/I Energy Regulatory Commission decision provides for a special increased price on gas from tight formations. INDEPENDENTS OPPOSE NEAR-TERM OIL SHALE According to IPAMS president Kye Trout, "We can LEASING expect increased development of this valuable energy resource to begin in the immediate future in the same The Independent Petroleum Association of Mountain area being proposed for shale development." Additional States (IPAMS) issued a policy statement on September oil shale leases could be in conflict with existing oil and 21, 1980, calling for completion of multiple resource use gas production and leasing. plans on public lands before the government proceeds to lease additional lands in Colorado, Utah, and Wyoming

2-6 1CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RIOOW R99W R98W 1197W 1196W 1195W 1194W

IktCARI ER T 4^^a 11 SUPERIOR 60% SOHIO 20% CLIFFS 20% I

- ARcO j1EQUITY - ]_ ------RIO BLANCO COUNTY - 4 GrnFIELDCC Nfl

? 501410 60% SHEL &-' s iMPSUPERIORIO0% 3 GARFIELD C04NTY CLIFFS MESA10% OOUhr / FIGURE 1 SUPERIOR / SOHIO/CLEVELAND CLIFFS LAND HOLDINGS IN THE PICEANCE CREEK BASIN

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-7 "The proposed expanded priority on shale leasing and Most respondents indicated a need for additional Federal synthetic fuel development would be a conflicting lands to make more and better resources available and, impediment to development of these readily available in some cases, for sites for processing facilities and quantities of natural gas. And that gas could be spent shale disposal. Reasons cited included the lower delivered at a comparatively lower cost using established quality of non-Federal oil shale lands, the limited legal technology," Trout said. "Any exaggerated emphasis on maximum size of Federal leases which is presently set at developing synfuels without considering previous or 5,120 acres, and the difficulty of aggregating private simultaneous development of an established, clean fuel is lands to exhcange for Federal acreage which has resulted foolish, economically wasteful, and counter-productive in no major exchange proposals having been approved by to the goal of improving our nation's energy indepen- the Department under existing legal or regulatory pro- dence." cedures. No respondents indicated locations of preferred applica- tion of these technologies more specific than a township INTERIOR ANNOUNCES RESULTS OF in size, whether composed of whole townships or adjoin- OIL SHALE TECHNOLOGY NOMINATIONS ing sections of adjacent townships. The strongest areas of interest for in-situ and underground techniques were On October 31, 1980, Interior Under Secretary James A. the central Piceance Creek basin area in Colorado and Joseph announced results of a recent Interior Depart- nearby areas in Utah. Interest in surface mining was ment request for parties interested in oil shale leasing on strongest in the western Piceance Creek basin area. The Federal lands to suggest technologies they feel have the Department anticipates that a site-specific call for oil greatest promise for development. Responses came shale tract nominations will be issued at year-end or in from eight sources, Joseph said, and covered a wide early 1981 as part of the ongoing Prototype Oil Shale range of desires, ideas, and concerns. The responses will Leasing Program. be carefully reviewed as the oil shale process moves toward specific consideration of potential lease areas, he #1111// said. A related article appears on page 2-22 of the September 1980 issue of the Cameron Synthetic Fuels RUSSELL'S "HISTORY OF WESTERN OIL SHALE" Report. IS PUBLISHED The call for expressions of interest in technologies Paul L. Russell, retired Research Director of the U.S. closed on October 16, 1980. Responses were received Bureau of Mines, has compiled a "History of Western Oil from Amoco, Exxon USA, Friends of the Earth (FOE), Shale." The publisher is The Center for Professional Geokinetics, Gulf Mineral Resources, Multi Mineral Advancement, Box H, East Brunswick, NJ 08816. Corporation, Nielsen Resources, Occidential Oil Shale, and Tosco. The respondents indicated interest in (1) This 138-page, comprehensive history is divided into five surface mining; (2) room and pillar, high column, stoping parts: and blockcaving, all underground techniques generally in conjunction with surface retorting; (3) and (4) modified • Early History in-situ and true in-situ, both vertical and horizontal, • 1915-1930 utilizing subsurface retort combustion or hot • 1940-1969 water/steam injection; and (5) several multi-mineral • 1970-1979 extraction methods to be used in conjunction with in-situ • Summary and Epilogue or underground mining techniques. The work covers in detail serious projects and fly-by- Interior issued its invitation on August 18, 1980, asking night operations. There are excellent photographs, both interested parties to suggest technologies they would historical and contemporary, the latter showing ruins--in like to see used in developing tracts which will be many cases there are "then and now" comparisons. The offered in the next leasing round by the Prototype Oil book amply illustrates that there is nothing new or Shale Leasing Program. Parties also were asked to mysterious about oil shale. We highly recommend this indicate general areas--no smaller than a township-- excellent history. where these technologies would be best applied. The Department will use the information in developing plann- II 1/ 11 II ing and tract selection criteria in preparation for leasing up to four additional tracts for prototype oil shale INTERIOR FILES BRIEF IN OPPOSITION TO MINERAL development late in 1982. This date is an acceleration PATENT APPLICATIONS from the previous August 1983 target. On September 22, 1980, the United States filed a 130 The Department also received negative nominations page brief in its contests in opposition to the patent from FOE arguing that certain technologies would not be applications involved in case number 8680 before the appropriate for consideration in the prototype leasing U.S. District Court in Denver. At issue is the question program. These responses also indicated that certain of discovery of minerals. areas would be inappropriate and contained observations concerning the amount and type of leasing that may be As reported on page 2-41 of the September 1980 issue of preferable, pointing out that development may be antici- the Cameron Synthetic Fuels Rort,ep the Interior Board pated on non-Federal lands. of Land Appeals had previously ruled June 30, 1980, on the question of whether the annual assessment work has been performed on these claims.

2-8 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 The argument of the U.S. in this case is based on the The latter four criteria appear to be a new rendering of concept that discovery entails two findings: First, that a the economic feasibility test expressed in U.S. vs. Cole- mineral deposit physically exists within the limits of man. each claim, and second, that the mineral deposit found constitutes a valuable mineral deposit for minerals other The government seeks a determination of invalidity in than oil shale or a prospectively valuable oil shale the oil shale cases. In a reply brief of September 30, deposit. Further, there must be an actual finding of a 1980, the U.S. concludes: "Therefore, it is clear that the mineral that can be viewed as prospectively valuable (a) Contestees have not acquired any equitable claim on a on or before February 25, 1920, and (b) today. resource which since February 25, 1920, has been expli- citly declared by Congress to be one that should be The following points were made in argument; retained in federal ownership and only be developed through leasing. Oil shale is clearly a resource meant to • Some of the contested claims are invalid benefit the nation as a whole. The policy of leasing oil inasmuch as there was not an actual physical shale lands under the 1920 Act gave the United States a finding of a prospectively valuable mineral keen interest in recapturing those (claims) which had not deposit within the limits of each of the been 'maintained within the meaning of Section 37 of contested claims on or before February 25, that Act. The Supreme Court obviously would find the 1920. United States has the same 'keen interest' in recapturing oil shale claims that are invalid for any other reason, • Some of the contested claims are invalid including lack of discovery." since any mineral deposits actually located (or inferable) were not prospectively valuable as of February 25, 1920. SOUTHERN UINTA BASIN SHALE RESOURCES • Some of the contested claims are invalid CHARACTERIZED inasmuch as there was not an actual physical finding prior to February 25, 1920, of what DOE's Laramie Energy Technology Center has published might today be considered a prospectively a report of investigations number DOE/LETC/Rl-80/ II, valuable mineral deposit within the limits of "Shallow Oil Shale Resources of the Southern Uinta each of the contested claims. Basin, Utah." The authors are George F. Dana, John Ward Smith, and Laurence G. Trudell. The report is • Some of the contested claims are invalid available for $6.00 from the National Technical Informa- since any mineral deposits actually located tion Service, Springfield, Virginia 22161. (or inferable) are not prospectively valuable at present. The shallow Green River Formation oil shales in the southern part of Utah's Uinta Basin are potentially • Estoppel does not run against the contestant developable by strip mining or by subsurface techniques in this case. which take advantage of limited overburden. The resource of potential shale oil represented by the shallow • Portions of the Northwest and Southwest deposits is evaluated in detail from correlatable strati- claims must be excluded from any patent of graphic units selected to represent resources in the such claims because the lands are non-min- shallow shale. To define each unit, the thickness, eral in character. average oil yield, and oil resource of each unit in each core are calculated. Contour maps constructed from Much of the brief is devoted to a dissection of Freeman these data define the resource variation across the vs. Summers and a rearguing of the Andrus vs. Shell shallow resource. By measuring areas enclosed in each Supreme Court case. The U.S. contends that the evi- resource unit within the defined limit of 200 feet (61 dence clearly establishes that each one of the factual meters) of overburden, the resource represented by the premises of the Freeman vs. Summers decision is erron- shallow oil shale is evaluated. The total resource is eous, and it argues that Andrus vs. Shell only dispensed measured as 4.9 billion barrels (779.1 billion liters) of with a present marketability requirement. potential shale oil at depths less than 200 feet (61 meters). The rich zone incorporates the Mahogany bed, The brief states that in evaluating lands for prospective the best shallow oil-shale unit. This section, currently value there are two sets of criteria: Geological richness being exploited by Geokinetics, Inc., for in situ produc- of the oil shale and geographic location. The brief lists tion of shale oil by horizontal combustion, represents 2.2 the following criteria for the "reasonably prudent billion barrels (349.8 billion liters) of potential shale oil person" intent upon perfecting an oil shale claim: in place. Quality of the oil shale deposit. I/I/I," Quantity of the oil shale deposit. Water Supply. Railroads. Timber. Gravity disposal of shale. Land for housing, etc.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-9 STATUS OF OIL SHALE LEGAL PROCEEDINGS NOTED The U.S. Supreme Court has denied a writ of certiorari in South Dakota vs. Secretary of the Interior (docket number 79- 1635). Thus the lower courts' decisions stand--that issuance of a mineral patent is an administrative action which does not require an environmental imact statement. The status of various Bureau of Land Management administrative contests and of state and Federal court cases which concern oil shale in the intermountain region of Colorado, Utah, and Wyoming is summarized in Table 1. TABLE I

STATUS OF OIL SHALE LEGAL PROCEEDINGS

BUREAU OF LAND MANAGEMENT ADMINISTRATIVE CONTESTS:

Contest No. Cob. 359-360: USA vs. F.W. Winegar, et al. Contestant seeking to invalidate oil shale claims held by contestees on basis of no discovery. Recommended decision issued by BLM hearing examiner on 4/17/70 wherein three claims were declared invalid and six claims adjudged to be valid. BLM filed appeal brief on 6/12/70. Interior's Bureau of Land Appeals decision of 6/28/74 reversed 4/17/70 decision and all claims were ruled invalid. See September 1974 issue of Synthetic Fuels, page 2-I, for discussion.

As a result of the adverse decision, Shell Oil, one of the claimants, took the case to the U.S. District Court in Denver, under Civil Action 74F-739. In January of 1977, the District Court ruled that Shell's claims were valid. The case was appealed by the Department of the Interior in the U.S. Court of Appeals in Denver as pocket No. 77-1346. Decision affirmed in Shell's favor 1125/79. The case is now under appeal to the U.S. Supreme Court, Docket No. 78- IS IS.

Contest No. Cob. 193 & 260: USA vs. TOSCO These contests will be decided by the courts in Civil Action 8680, 8685, 8691, and 9202, all of which cases are before the U.S. District Court and the 10th U.S. Circuit Court of Appeals in Denver. See recent Development in Civil Actions 8680, 8685, and 9202 (combined). BEFORE THE U.S. DISTRICT COURT IN DENVER: vs. Secretary of the Interior Civil Actions 9252 H.H. Hugg 94583. Savage vs. Secretary of the Interior 9461 Union Oil vs. Secretary of the Interior 9462 Equity Oil vs. Secretary of the Interior

9464 Gabbs Exploration vs. Secretary of the Interior 9465 TOSCO vs. Secretary of the Interior Plaintiffs are contesting BLM administrative rejections of applications for patents on oil shale mining claims. Cases are pending until cases on related subject matter (see 8680-9202 below) are decided. In effect, these cases are closed and proceedings stayed, but with the right of any party to reopen. Civil Actions 8680 TOSCO vs. Secretary of the Interior 8685 J.B. Umpleby - vs. Secretary of the Interior 8691 B.T. Napier vs. Secretary of the Interior 9202 P.C. Brown vs. Secretary of the Interior 12/26/66 U.S. District Court in Denver ruled nonperformance of annual assessment work not a valid cause for refusal of patents. (SFR, 3/67, page I-I).

02/04/69 10th Circuit Court of Appeals upheld District Court Decision. (SFR, page I- 6).

12/08/70 Supreme Court reversed decision and remanded case to District Court. (SER, 3/71, page 1- 1).

03/15/74 District Court ruled DO! could not deny patents based on circa-I930 proceedings, directed DO! to reprocess patent applications. (SFR, 6/74, page 2-4).

2-10 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 09/22/75 10th Circuit Court of Appeals remands cases to District Court with instruc- tions to DO! to proceed on expedited basis with examination of any and all bases for invalidity of claims. (SFR, 12/75, page 2-20).

06/21/76 Supreme Court refused to intervene and remanded matter to District Court. (SF, 9/76, page 2-7).

01117177 District Court remanded case to DOl for further proceedings in expedited manner.

07101177 BLM served contest complaints on claims in the case alleging failure to discover a valuable mineral, failure to perform annual assessment work, as well as assertion of validity of earlier contest proceedings. TOSCO filed application for patents on many of its claims involved in this case. 02/03/78 Court directed all matters be expedited and required Interior to submit a status report on March I, 1978, showing exact timetable comtemplated on carrying out directions of the Court. (SFR, 3/78, page 2-20). 03/01/78 Status Report calls for hearings in Denver on BLM contests, to commence 7/18/78. 08/29/79 Status conference.

12/28/79 Court ordered parties to explain delay; blamed DOt.

6/30/80 IBLA ruled in favor of Savage claims (Contest 658) and against Exxon and Tosco (Contests 659,660). U.S. District Court retains jurisdiction. 9/22/80 Interior filed opposition brief (CSFR, 12/80). 11/5/80 IBLA supplemental decision filed.

Civil Action 4139 USA vs. Eaton Shale, et al. Complaint filed on 7111172 wherein Plaintiff seeks judgment to void a patent issued in 1951 for oil shale claims GEM Nos. 3-6, 9 and 10. Plaintiff cites a quit-claim deed dated 1/12/29 from the then owner of the claims, DeBeque Shale Oil Co., to the U.S. Claims are located in an area controlled by Standard Oil Company of California. For discussion of issues, see Synthetic Fuels, September 1972, page 2-I. Trial held 2/23/77. Order issued on 5125177 stating that no valid ground exists for cancellation of the patent. 7122177 USA filed notice of content to appeal. On 10/26/77 the Court of Appeals dismissed the appeal.

Civil Action 4361 Amerada Hess vs. Secretary of the Interior Complaint filed on 9/26/72 wherein Plaintiff asks court to reverse decision of General Land Office Commissioner in BLM Contest 12790 (dated 1931) to reverse Interior Board of Appeals ruling of 6/28/72 involving rejection of unpatented mining claim ownership, a pre-trial conference was vacated. On 6/3/74, it was ordered that the matter be held in abeyance until 60 days after all appeals are completed in Civil Actions 2680, 8625, 8691 and 9202 (combined). These are discussed under separate heading. On 2/17/77 Judge Finesilver remanded the case to DOI. DO! is to expeditiously process patent application affecting claims involved in the action. Any and all objections roust be presented in one proceeding. BEFORE U.S. DISTRICT COURT IN SALT LAKE CITY:

Civil Action C77-0165 Phillips Petroleum, et al. vs. Secretary of the Interior On 4/17/77 plaintiffs filed complaint seeking injunction against enforcement of the terms of the lease for Tracts U- a and U-b. Plaintiffs contend that existence of pre-1920 oil shale placer claims on lease tracts clouds the title to the land. Also, Penninsula Mining Inc. has claimed first right to lease the land as part of Utah's in lieu land selections. On 711177, Preliminary Injunction was granted to prevent enforcement of terms of the leases until questions concerning land title are resolved. The pertinent legal documents are contained in the Appendix of the September 1977 issue of Synthetic Fuels. A notice of appeal was filed 8/29/77. Justice Department dropped the appeal 4/11/78, leaving the preliminary injunction without contest.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-11

Civil Action C-80-0240A Sohio Shale Oil Co., et al. vs. Secretary of the Interior, et al.

Sohio, Phillips, and Sunedco, lessees of Tracts U-afU-b, filed complaint 4/30/80 seeking to ensure that lease monies paid for Tracts will revert to lessees if state and federal agencies fail to clear the title to the leased lands in a timely manner. Complaint also requests that the Court define "timely."

BEFORE THE U.S. SUPREME COURT

Docket No. 79-1635 South Dakota vs. Secretary of the Interior South Dakota seeks a reversal of an Eight Circuit U.S. Court of Appeals decision (Docket No. 79-1178) that an Environmental Impact Statement is not required prior to issuance of a mineral patent. Cert. denied 10/80.

2-12 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 ENVIRONMENT

OXY PETITIONS COLORADO FOR RELAXED SO or gas is heated outside the retort and heat transfer is STANDARD made to the shale, producing a high Btu gas. The Colony (TOSCO II) and Union processes utilize indirect mode Occidental Oil Shale has petitioned the Colorado Air retorting. Quality Control Commission to change the 502 standard, which limits emissions to 0.3 pounds of 502 per barrel of The Union PSD (prevention of significant deterioration) shale oil produced. Oxy's petition requests that existing permit application to EPA and Occidental's Logan Wash references to the standard be deleted and the following Retort 6 burn demonstrate that a number of sulfur language be substituted: species result from both types of retorting. These species include hydrogen sulfide, sulfur dioxide, carbonyl 'All shale oil production facilities shall employ sulfide, carbon disulfide, and rnercaptans. Previously, it best available control technology (BACT) for con- was thought that hydrogen sulfide was the only sulfur trol of sulfur dioxide (SO ) emissions from oil shale constituent in these gases. processing sources, as deermined by the Division subject to review by the Commission." Two sulfur emission control systems are applicable to indirect mode retorting: the Stretford fuel gas cleaning Public hearings were held in Meeker, Colorado, on Sep- system and amine absorbers with Claus and Wellman tember 12 and in Denver on October 16. The hearings Lord tail gas cleanup. For direct mode retorting, the were evidentiary in nature. Stretford system and flue gas desulfurization are appli- cable. Oxy's petition arose from a comparative study being done for EPA. According to testimony at the hearings The Stretford system potentially can obtain high removal by Dr. Andrew Jovanovich of Denver Research Institute of hydrogen sulfide, but its removal of the other sulfur and George Domahidy of Stone and Webster, who are compounds is minimal or none. Sulfur dioxide in the gas principle consultants to EPA in the preparation of a stream degrades the performance of the Stretford sys- pollution control guidance document for oil shale pro- tem and amine absorbers, cesses, emissions from Oxy's modified in situ (MIS) process can be expected to be 0.76 pounds of 502 per The Union application and PSD permit control level of barrel of oil produced. The following is a summary of 99.7 percent using Stretford does not represent an the testimony. attainable control level, since this figure can be arrived at only through an erroneous calculation which figures The DRI - Stone and Webster team is conducting six case total gas volumes, including volumes in the recycle studies for application of pollution control systems to system, rather than considering only the gas going into commercially sized shale oil plants: and out of the Stretford units, which is the proper way to figure control levels. • Colony Development with TOSCO II process; The Union PSD permit control efficiency figures do not • Paraho process - White River Project, Utah; consider all the different types of origins of sulfur emissions in the plant. For example, the stripper over- • Cathedral Bluffs (C-b) combined modified in head vapors do not go through the Stretford unit but situ - Lurgi surface retorting; nevertheless go into the boiler and are vented to the atmosphere. If done properly the efficiency levels would • Rio Blanco (C-a) Lurgi surface retorting with be 96.7 to 97 percent if everything is working properly open pit mining; under full operaflonal conditions. Realistically, it can be expected that overall average performance will be less • Union B process; than 96,7 percent control. Control equipment degreda- tion will occur with any device. The Stretford system is • Superior multi-mineral process. accompanied by a "very difficult treatment and disposal problem" and lots of maintenance problems. 502 in the The case study for C-b is for an operation of 100,000 gas stream going into a Stretford results in a lower level barrels of oil per day-68,000 MIS and 32,000 Lurgi. of control and higher operation costs. The study has found that there are "major and important Projecting levels of attainable control for an industry differences between the gases produced by different oil that heretofore has been non-existent is extremely diffi- shale processes, and so we are not finding that one cult. Putting redundant control devices on a shale oil approach is the answer to all of them." In direct mode plant, for example fuel gas cleaning before the boiler retorting, oil production is accomplished by a flame zone and flue gas desulfurization after the boiler, does not burning within the retort, producing a low Btu gas. make sense because an enormous amount of energy Examples of a direct mode retort are the C-b modified would be required to remove small amounts of pollu- in situ process, the Paraho surface process, and the tants, because of a lack of driving force, at the price of Superior surface process. In the indirect mode retort, great capital outlay and waste problems. there is no combustion within the retort; rather a solid

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-13 The Reactive Plume II model done for EPA shows no the necessity of importing power or burning another fuel violation of the national ambient air standard for sulfur on site. A per barrel emission standard does not account dioxide or the Class I federal increment for Dinosaur for production and use of a fuel source on site. Opera- National Monument and Flat Tops Wilderness area, tors of potential indirect mode retorts are talking about taking into account absolute worst case conditions and exporting the high Btu gas and importing coal-generated operation of a 900,000 barrel per thy industry. The electrical energy, causing additional air emissions else- study factored in sixteen full scale commercial plants. where. Only when Exxon's proposal of an eight million barrel per day industry was considered did there occur a violation Requiring application of the best control technology is of the applicable ambient air standards. Otherwise, the the only fair way to go with the first generation shale oil applicable increments "weren't close" to being exceeded plants. The modified in situ process involves less hand- by the projected commercial production levels. ling of shale on the surface and less particulate emis- sions. The most common disadvantage of an open pit is Though the projected Union process is for emissions at fugitive dust. Some people have strong aesthetic objec- 0.224 pounds of SO 2 per barrel of oil produced, rich shale tions to an open pit operation. Room and pillar mining was used in the test runs. To go commercial would results in "fairly poor resource recovery" and is avoided require utilizing a lower grade shale, with a possible by MIS retorting. resultant increase in 502 per barrel processed. Sulfur content in the shale varies from site to site and even can The MIS process, like other direct mode retorting, pro- vary considerably on the same site. duces a very large volume of low Btu gas. The Logan Wash data is as good as can be obtained for making According to Jovanovich, expressing a sulfur emission emission projections, but operational commercial retorts standard in pounds per barrel is unfair: are needed for a good analysis. "I've been stressing, wherever I can, that consi- The direct mode retorting gas is very dilute; thus, air deration in comparison of oil shale processes ought pollution control efficiencies drop. Only Stretford and not to be done on a per-barrel basis. The differ- flue gas desulfurization systems (lime or ammonia ence between the processes is too great; the scrubbing) are applicable to direct mode retorting. All difference between the products they produce is of these are projected for a 95.5 percent control effi- too great. ciency on an optimum basis. It looks as though flue gas desulfurization could be the best application of control "Our concern has more been in the area of cost. If technology to the C-b combined MIS-Lurgi process. you divide cost by the barrels of the production for Superior, for instance, where you're also costing The direct mode retorts, though they utilize the best plants for recovering nahcolite and dawsonite, it control equipment available, will not meet the 0.3 comes out just terrible. pounds of SO per barrel of oil standard set by the Air Quality Conti'bl Commission in 1977. Retention of the "If you look at Colony, they produce a product 0.3 emission limitation will prohibit the use of direct that's much different because it's upgraded than, mode retorting on all but the very richest shale, with a say, Paraho that produces an upgraded crude oil. substantial penalty to overall resource recovery. "The variation in the grade of shale that you are Controlled MIS emissions can be expected to be 0.76 retorting makes a great big difference. pounds of SO 2 per barrel of oil produced. The combined MIS-Lurgi system for C-b is expected to produce 0,54 "At the lease tracts in the center of the basin, like pounds of S0 per barrel of oil produced. These figures C-a and C-b, you have a very broad seam that you are higher than those projected by Cathedral Bluffs are retorting either on the surface or underground. because Jovanovich and Domahidy do not believe vendor That averages say, 24, 25, gallons per ton that puts guarantees of removal down to 50 PPM can actually be you at a disadvantage because you compare that to obtained or achieved; rather, 75 PPM is more realistic. someone who is averaging 35 gallons per ton in In addition, the EPA consultants did not factor in their retort, they're producing more oil per unit of naphtha recovery in calculating barrels produced. emissions. Yet the lease tracts that are in the center of the basin in their own way are very A 0.54 pound per barrel emission level is equivalent to attractive because, although the shale is of a lower 0.2 pounds of sulfur dioxide per million Btu on a heat grade, the seam is much thicker. input conversion basis. The Colorado standard for oil- fired boilers is 0.3 pounds of sulfur dioxide per million "So on a per-barrel basis, practically every direc- Btu, and the coal-fired standard is 0.4 pounds of sulfur tion you look, if you're looking at cost, if you're dioxide per million Btu. The C-b MIS..Lurgi process uses looking at emissions, anything else, you end up with the low-Btu gas as a boiler fuel. Setting a heat input a comparison that really is invalid. I've had great standard for sulfur emissions from the boiler to accomo- difficulty with this because everybody wants to do date combined MIS-Lurgi retorting would stilt result in these comparisons on a per-barrel basis. It's un- emissions half as much per million Btus than a coal-fired fair. It doesn't take into consideration most of power source placed on the same location to provide these things you should consider." energy. Direct mnodelretorts, such as MIS, produce a low Btu gas Just as a power plant uses coal for a fuel and exports which is quite suitable for use as a fuel on site, without electricity as a product, the C-b process uses the retort

2-14 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 gas for a fuel and exports oil as a product. The (NOSR) 3, to extend the existing lease, and to construct application of control equipment to a boiler emission and operate a full-size (4,700 bbl/day) retort on a 365- point is a standard application of gas cleaning devices. acre lease tract at the Anvil Points Oil Shale Facility, Colorado. The retort module would be developed by DEl Not using the MIS gas as a fuel would be wasting a and would use the Paraho direct-mode process techno- resource. The current Colorado per barrel standard does logy. Operating the module and its supporting facilities not give credit for the overall energy produced by the would require mining and crushing the oil shale, trans- process, since the energy value of the retort gas is not porting the raw shale to the retort, retorting, transport- figured in. Burning the low Btu gas as a fuel source on ing the shale oil to storage tanks, disposing fines and the C-b tract makes a lot of sense. A standard based on spent shale, and transporting the crude shale oil from the fuel burned in combustion processes makes straight- site. Presently, the existing Anvil Points semiworks and forward sense. pilot plants are operating independently on a part-time basis; the semiworks plant would supplement the full- The guidance document of the EPA consultants is to help size module as necessary. educate EPA and assure that regulations do not impede the development of the industry. It is intended that this The Anvil Points operation will have three phases: Phase type of guidance would then help to assure that the I is an eight-month program to plan the facility; Phase II regulations don't impede the development of the industry. is an 18-month period to develop the mine, detail the design plans, and construct the module; and Phase III is an IS-month module operation period which may be Statements in favor of the current standard and in extended, depending on start-up and operating perform- opposition to Oxy's proposal were submitted by: ance. DEl currently is working on preliminary plans for Phase I. Construction and finalized detailed design plans Exxon Company, U.S.A. will not start until completion of the NEPA (National ARCO Coal Company Environmental Policy Act) process. However, a supple- Union Oil Company of California mental EIS will be prepared to assess the potential Energy Development Consultants, Inc. impacts of spent shale disposal and the disposal of raw Various environmental groups shale fines after more design information is available. DEl expects to maintain its 44-month production sched- ARCO's statement sums up the concern expressed by the ule; however, Phase Ill would not be completed before oil companies: "ARCO believes an increase in allowable the existing DEl facility lease expires in July 1982. 502 emissions . . .will result in a reduced increment available for all future development. Since ARCO Coal The proposed action could contribute to the Congression- Company intends to develop its oil shale holdings in the ally mandated oil shale development program by demon- future, such increases in allowable emissions could strating the reliability, efficiency, and feasibility of oil directly damage those efforts. Unless and/or until a shale surface retorting in a commercial size retort, thus viable alternative is promulgated by this Commission, obtaining technical information which may aid in ARCO Coal Company would oppose any change in developing the oil shale retorting industry. An expanded emission standards." development program for the Paraho process will provide physical scale-up and cost data for evaluating commer- No action has been taken yet by the Commission. Dead- cial scale process economics. In addition, environmental tine for public comments was November 5. data will provide an opportunity to minimize potential adverse impacts of full-size operations. The proposed f/il f/fl Anvil Points module will be an experimental, not a commercial facility. A commercial oil shale facility DRAFT EIS ISSUED FOR PARAHO MODULE AT would contain 10 or more modules the size of the ANVIL POINTS i5roposed full-size module. The U.S. Department of Energy has issued a Draft The objective of the proposed action is to continue to Environmental Impact Statement (DEIS) entitled "encourage the use of the (Anvil Points Oil Shale) "Mining, Construction and Operation for a Full Size facility ... in research, development, test, evaluation, and Module at the Anvil Points Oil Shale Facility, Rifle, demonstration work," consistent with 10 U.S.C. 7438(b), Garfield County, Colorado." The DEIS was issued in as ordered by Congress. Development Engineering, Inc. August 1980 as document number DOE/EIS-0070. Copies (DEl), the lessee of the facility, has proposed to build a of the DEIS are available from Larry W. Harrington, full-sized oil shale retort for testing of economic, Laramie Energy Technology Center, P.O. Box 3395, environmental, and process parameters. In order to University Station, Laramie, Wyoming 82071. Paraho's conduct such a test, additional oil shale must be mined. proposal for Anvil Points is apparently independent of "The Secretary of the Interior (now the Secretary of the design Phase I in response to a PON (Program Energy) may, after consultation by the Secretary of the Opportunity Notice) for a commercial-sized surface re- Navy with the Committees on Armed Services of the tort module. The PON retort will be constructed on Senate and House of Representatives ... authorize the Paraho's Utah State lease northeast of Tract U-b. mining and removal, of any oil shale or products there from lands in the Naval Oil Shale Reserves that may be Development Engineering, Inc., (DEl), a subsidiary of needed for such experimentation." 10 U.S.C. 7438(b). Paraho Development Corporation, has requested approval from the Department of Energy (DOE) to mine On July 27, 1974, Development Engineering, Inc., pro- 11 million tons of oil shale from Naval Oil Shale Reserve posed to construct a full-size Paraho retort at Anvil

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-IS Points. Under the plan, a maximum of an additional II The Bureau of Mines gas combustion retort was million tons of oil shale would be mined from the Naval developed in 1951 at Anvil Points to overcome this Oil Shale Reserves. In a letter dated October 30, 1974, problem, reaching a 150 ton/day pilot plant capacity at the Acting Secretary of the Navy for Naval Petroleum the conclusion of the Synthetic Liquid Fuels Program in and Oil Shale Reserves, Mr. Jack L. Bowers, forwarded 1955. Between 1964 and 1966, Mobil Oil and its assoc- the DEl proposal to the Chairmen of the Senate and iates improved the process attaining a capacity of 350 House Armed Services Committees. in a letter dated tons/day at yields in excess of 85 percent of Fischer December 6, 1974, Congressman Hebert, the Chairman assay. However, difficulties were encountered with of the House Armed Services Committee, stated that the small shale sizes, high rates of gas and shale throughput, Committee had no objection to the raining of an addi- and bridging due to rich shales. The Paraho/DEI gas tional 11 million tons of oil shale. In a similar letter combustion retort was designed to overcome such limita- dated October 24, 1974, Senator Stennis stated that the tions. Senate Armed Service Committee had no objections to the mining of an additional II million tons of oil shale. The DEl kiln was invented by John B. Jones (U.S. Patent No. 3,736,247), and initially used for calcining limestone In May 1975, the Secretary of the Interior completed an where it has attained a capacity of 700 TPD in a 10.5 Environmental Impact Assessment on the proposed foot diameter design. In May 1972, DEl leased the action, authorization to mine I million tons of oil shale. federal facilities at Anvil Points and launched a project On November 4, 1975, the Energy Research and Develop- to apply the DEl kiln to oil shale retorting. A consort- ment Administrations Assistant Administrator for Fossil ium of 17 companies, known as the Paraho Oil Shale Energy notified DEl that authorization of the proposal Project, was formed, and activities at Anvil Points were and modification of the existing lease would require initiated in 1973. Some of the facilities originally preparation of an Environmental Impact Statement be- developed by the Bureau of Mines were utilized, includ- fore final action could be taken with respect to the ing the underground nine, crushing plant, retort struc- authorization. ture, various storage tanks, shale disposal area, and associated laboratories, maintenance shops, and water In 1972, the Anvil Points Oil Shale Facility was leased to supplies. The project was scheduled to run until August DEl. Prior to leasing the site, the Interior Department 1976 under funding to be supplied by its industrial issued a Final Environmental Statement (FES). The FES participants. was used in preparation of the lease's environmental stipulations, and they apply specifically to operation of Two retorts, a pilot plant retort and a larger semiworks the on site pilot plant and semiworks reactor. Since the reactor, were constructed and operated under the pro- lease agreement was predicated upon the 1972 FES, it grain. The pilot plant retort is 60 feet in height and with was ERDA's determination that additional authorization a 4.5 foot outside diameter; the semiworks reactor is 75 of the proposed construction and mining would be feet high and has a 10.5 foot outside diameter. The required, and the authorization would be reflected in an retorts were designed so that they could be operated in addendum to the lease. any one of three modes: direct heated, whereby heat is supplied by the combustion of carbon in the spent shale Site and Process History Discussed (similar to the Gas Combustion process); indirect-heated, in which heat is supplied by recycled gases heated The oil shale property which contains the present Paraho externally (similar to the Petrosix process); and a combi- project site at Anvil Points, Colorado, was purchased by nation of these two modes. As part of the Paraho the government as early as the 1920's for possible operations, approximately 10,000 bbl of raw shale oil development. Actual oil shale development efforts were were produced in 1975 for use in a Navy refining not conducted at the site until the Bureau of Mines Shale program. The shale oil was refined at the Gary Western Research Facility was established under the Synthetic Company Refinery in Fruita west of Grand Junction, Liquid Act of 1944. The plant and underground room- Colorado, to obtain NATO gasoline, JP-4 jet fuel, 3P-5 and-pillar mine resulting from the Bureau's pioneering jet fuel, and heavy fuel oil. The fuels were subsequentlly technology development efforts were operated by them tested in a variety of Navy and other military vehicles during the period from 1944 through 1956. Authority to and in the boilers of ore freighters on the Great Lakes. lease the facility was given to the Secretary of the Interior in 1962, and from 1964 through 1969 the facility In 1976, the lease on the Anvil Points facility was was leased to the Colorado School of Mines Research extended to 1982 by ERDA (lessor of the site at that Foundation for purposes of improving retorting techno- time) and a government-sponsored program to provide logy. During that period, Mobil Oil Company acted as 100,000 bbl of shale oil for subsequent refining and project manager for a consortium of six petroleum testing was initiated. This effort was completed in early companies (Mobil, Humble, Pan American, Sinclair, Con- 1978. (The Department of Energy became the overseer tinental, and Phillips) at the site. This group operated of the Anvil Points facility lease and DEl, lessee, in the Anvil Points mine until 1966. The facility was October 1977, when ERDA became part of DOE). essentially unoccupied until 1972. Having completed the program phases, the semiworks NTU retort technology was first used by the Bureau of plant was shutdown. Since that time, several runs of Mines at Anvil Points Research Center. Although the foreign oil shale have been made in the pilot plant. retort successfully recovered oil from shale through a direct combustion process, it utilized a batch-type DOE is pursuing a surface module demonstration plant operation which required that the retort vessel be loaded program as defined in PL 95-238. The objective of this before burning and dumped after completion of firing. program is to stimulate oil shale industry development

2-16 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 by demonstrating the engineering, economic, and The proposed demonstration project involves an experi- environmental feasibility of a surface retorting process mental scaleup of existing technology, defined to inves- at a unit scale considered necessary to prove commercial tigate options for the future development of oil shale, feasibility. The program is divided into two phases: not to foreclose them. As such, the project is not considered a key element of the Oil Shale Progam which Phase I includes the procurement of technical already contains efforts similar in nature. To place the designs, cost estimates, and environmental proposed action into such a key position would be to data for site specific construction and opera- jeopardize unnecessarily the orderly development pro- tion of one or more of the modern oil shale cess embodied in the program. surface retorting processes that have pre- viously shown feasibility at pilot scale. The Paraho retort has had a long developmental cycle. These designs will be for modular equipment Beginning in 1973, Paraho processes have gone from a configurations at a size that could be repli- conceptual stage through several levels of pilot retorts, cated in commercial practice. each of which have had measurable success. The pro- posed action is yet another stage. These stages have 2. Phase 11, if needed due to problems imple- been, and remain, independent of the schedule followed menting incentive approaches, will include by the DOE Oil Shale Program which was initiated well the actual construction and operation of a after the first Paraho retort had produced its initial retort process selected subsequent to Phase I, output for the Navy. The two programs, DOE's and leading to either commercial expansion or Paraho's, are following different schedules leading to abandonment. Operating data, operating different ends; DOE's program is based upon the techno- costs, and environmental information will be logy development and results of pioneering efforts such collected and evaluated to determine perfor- as that completed by Paraho heretofore. mance and acceptability. The government's commitment of funds in support of the In May 1979, DOE issued a Program Opportunity Notice proposed action will be confined to administrative pur- (PON) inviting prospective contractors to submit pro- poses only -- the monitoring of the Anvil Points lease posals to design and potentially construct a commercial and use of existing government equipment and facilities. scale oil shale surface retort module. (This PON has no The DOE has not proposed to fund the project beyond direct relationship with the subject action although both this level. Oil Shale RD&D funds are committed to actions address the same technology.) Phase 1 contract supporting a continuous development effort embodied talks were initiated in December 1979 with all three within the Oil Shale RD&D Program plan which does not firms that responded to the PON. These firms were include the proposed action. Government support monies Paraho, Superior, and Tosco. Following negotiations, beyond this possible source are limited. Each energy DOE entered into agreements with Paraho and Superior. program, oil shale being one, is confined to a specific Two other firms, Rio Blanco Oil Shale Corporation and budget authorized and approved at the Congressional Occidential Oil Shale, Inc., have signed letters of intent level. to apply for Phase II grants, based on plans and designs developed with private funding. The mining and processing of I million tons of oil shale, averaging approximately 25 gallons per ton, will yield as Phase I contracts are 18 month programs to prepare for much as 5.9 million bbl of shale oil. Extracting this possible future construction and operation of the demon- amount of shale by underground room-and-pillar methods stration facility. The facility would be one module of a with a 70 percent in place resource recovery will commit full-size commercial oil shale plant and could eventually 15.7 million tons of oil shale to the proposed action. cost about $200 million to build and operate. At full This amount of shale is only a fraction of one percent of production, it should produce roughly 10,000 bbl per day the 11.4 billion tons of shale on NOSR 1 and 3, and of shale oil, although both the production levels and approximately one percent of the 1.2 billion tons of exact costs vary among proposers. The initial phase, reserves in the Anvil Points lease. It should be noted, which includes design of the module as well as plans for however, that the present lease allows DEl to mine up to its construction and operation and the preparation of an 400,000 tons of oil shale through 1982. Thus far, they appropriate EIS, is financed by $15 million allotted by have only mined approximately 220,000 tons. Accept- Congress in 1979. ance or rejection of the proposed action, therefore, will not appreciably affect the Oil Shale Program by prohibi- Relationship Between the Proposed Action and Current ting access to minable oil shale deposits. DOE Oil Shale Development Programs The Anvil Points Oil Shale Facility has been made The DOE Oil Shale Program has been structured to available to industry to encourage the development of provide the technical, economic, and environmental in- surface retorting technology. Recently, the government formation base necessary to support commercial oil has offered to share the cost of building modules with shale development. In view of the comprehensivenature industry, and it is considering other incentives such as of the program, neither approval nor disapproval of the tax credits and price purchase guarantees. if Develop- proposed action will appreciably affect the schedule of ment Engineering, Inc., should proceed with its plans at planned program activities or impact the overall pro- Anvil Points, the economics, process, and environmental grain. Thus, approval of the proposed action may be aspects of a full-size Paraho module will be demonstra- given independent of any NEPA-related activity con- ted. However, the DOE financial incentive program and cerning the Oil Shale RD&D Program, in concert with cost sharing program, not the proposed action, are seen the intent of 40CFR 1506.1(c). as the incentive required to stimulate the commercial

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-17 industry. Approval of the proposed DEl program, there- Whether to promote development of oil shale fore, must be made on its merits alone. on Federal land (beyond that presently sub- ject to lease). II 111/1/ Whether to develop the 35,000-acre NOSR 11 NAVAL OIL SHALE RESERVE DRAFT EIS ISSUED if the decision is to develop additional Federal land. The Department of Energy has issued the Draft Pro- grammatic Environmental Impact Statement on the What institutional and financial mechanisms Development Policy Options for the Naval Oil Shale should be selected, if the decision is to Reserves (NOSR) in Garfield County, Colorado. The EIS develop NOSR I. was prepared by the Energy Systems Group of TRW, Inc., as part of the predevelopment program for Naval Oil Decisions will be made in light of the national goal to Shale Reserves I and 3. The predevelopment program produce 2.5 million barrels per day of synthetic fuels by was described in the September 1978 issue of Synthetic 1990, of which 400,000 barrels per day is to be obtained Fuels on page 2-19. In order to solicit general input, from oil shale. public scoping meetings were held on February 5, 1980 in Grand Junction, Colorado and on February 7, 1980 in Each fuel alternative is individually evaluated at a Denver, Colorado. Transcripts of the proceedings are potential production of 50,000 and 200,000 barrels per published as Appendix E in the Environmental Impact day, with an expected project life equivalent to 20 years Statement. An article in the March 1980 issue of following a four year investment and construction Cameron Synthetic Fuels Report (page 2-33) summarizes period. A comparison of resource usage and environ- the issues that were proposed for examination in the EIS. mental factors for each selected technology is given in Table 1. Process energy efficiency is determined by the In order to develop policy options, the objective of the direct energy usage required or Btu's expended to pro- programmatic EIS was to assess and compare the environ- duce 1 million Btu of fuel product. Conservation is mental impacts of eight liquid fuel alternatives under clearly the most advantageous option environmentally five different policy options which include I) lease to for reducing other fuel alternatives, the total air quality private entity, 2) quasi-utility venture, 3) separate impact rather than just emissions is a more significant ownership, 4) joint venture, and 5) government owned- impact indication. The impact of water requirements contractor operated projects. The liquid fuel alterna- depends greatly on the regional water availability. tives and the technologies selected to represent them Alcohol plants require the largest amount of water, are as follows: while OCS and coal liquefaction requirements are com- paratively small. Oil shale water requirements vary with the technology. For all the water used in EOR, at least Liquid Fuel Alternatives an equal amount of water is produced which may be recycled. Land use is greatest for EOR due to well spacing requirements, but the impact is low since most NOSR I Oil Shale of the land will retain the potential for such activities as Conservation grazing. Oil shale is notably the largest producer of Oil Shale Development on Other Land solid wate at 20 million TPY with coal liquefaction Enhanced Oil Recovery (EOR) waste estimated at 4.5 million TPY. Coal liquefaction is Outer Continental Shelf Oil Production (OCS) given the greatest potential for causing health and Tar Sands safety hazards while oil shale has a moderate potential. Coal Liquefaction The health/safety effects of the alternatives are either Biomass/ Alcohol minor or negligible. Effects of population increase depend entirely on the local community conditions, and Selected Technology are considered significant for all alternatives except EOR and OCS. The impact of each socioeconomic factor Underground mining, combination of surface retor- will have to be addressed in a site specific EIS for NOSR ting and upgrading development. Transportation sector The EIS determines that whether fully leased or jointly Underground Mining, TOSCO II retorting, Colony owned, the industry ROI is about 20 percent and the Project ventures pay for themselves from a government view- Steam Injection, Kern County, California point, where the present value of its cost is heavily outweighed by the discounted present value of benefits. Platforms, Gulf of Mexico In the quasi-utility case, in which the government guar- None Selected antees a fixed ROI (12 percent was used) to the industry owner, surplus revenue provides the greatest net benefits SRC II, Morgantown, West Virginia to the government including return from sales and/or Grain Fermentation, Central Illinois taxes as appropriate.

The tar sands option was deleted from the comparisons due to lack of adequate data. The inclusion of conserva- tion as a choice, emphasized the intent of the EIS, that being to aid DOE in answering the following questions:

2-I8 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 _tc E U- 0 0 oo4-cOL.O '.0 cc 0 0 00 0 0 .CX CN .X.X a -p a o OCO 0cc 0 N- • 0 to'U', -P-p 1- 2i 0 - a 0) 0) 0) Cj 2 - N Pr'. 0 - —o N- 0 0-'. 0 0 00 N- 00 N C' N00 00 0' • 0 0 Cd 0 — — — N- 0 o E g o H - N- Pd — -1 U' C, ZU' 0 - -u + 0 cr,O - o 0 d E "i 0' 0' -- 0 00 U UI 0 C, a) ' . C-- — a) — 0 t- 8 — - L PT, 0 o — — — 0. z — 0 N- o2oEv-2oo 0 N 0 0 0) C1 0.00...— ma, 0 0 0 0 0 CNC0Pf'. C N F O °° 0 0 - LLI U U £ 0 0 - u a) 00 -1 U I. co uJ -t -C - IU CC Ut) C' 0 0 0 00 0 0 C' 0 0 OJ LL E" N- 0 0 0 OPt'. 0 0 — 0 0 U' - o cc a-. Z N-- 0 I -C 0 PC t#' (3 Op ci a) - 0 00 •- 0 0 00 C, I 00 0 oo mo -o 8 > 00 Pr'. I I 0•'. C'JN U' t0 U' p I I I U' -- CI oi o 0 C4

* — * 2Z 0 0 0 00 0 0 0 0 0 C-C, 00 'o ° U'. '0'0 0 0 N 0 0 OnH Cp'. '00' 'ON 0 a'. U-' z 0W'. — Pt'. N--

go m c F '-P (' r0c)' E-- Ec Io4 0 Iu c > a)OtoC2 o.o. _. I pIn cd I- I- a 0 0 u'. -g u-I z I- u V IT, -Ca) *0

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-19

ENVIRONMENTAL CONTROL TECHNOLOGY TESTED AT LARAMIE An experimental test of environmental control techno- logy was conducted in September at the Laramie Energy Technology Center using the 150-ton batch-type retort. The overall objective was to challenge a Venturi scrubber with the oil shale retort off-gas and measure its performance for removing particles. Besides the Department of Energy, other participants included the Environmental Protection Agency, Monsanto Research Corporation, and Denver Research Institute. Related objectives included: • Developing operational familiarity of testing personnel with pilot-scale control technology adapted to oil shale retort processes.

• Engineering design data to upgrade process recovery configurations. • Scale-up tests from bench to pilot scale of water treatment concepts to obtain data on scrubber water cleaning. • On-line air and water characterization for before, during, and after treatment of con- trol media. Control of off-gas particles was successful and, with cleaning, the resultant scrubber water ammonia levels were improved to less than 200 ppm, according to preliminary data. Complete recycle of the treated scrubber water is being considered to study the perform- ance of both control technologies under conditions of very little residual production, which reduces the volume of materials for disposal and improves the utilization of water. f/ill/fl

2-20 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 GOVERNMENT

DOE INSPECTOR GENERAL INVESTIGATES Dissemination of Technical Information Investigated LARAMIE'S PROGRAMS The IG found that Occidental was quite cautious about The Office of the Inspector General of the U.S. Depart- releasing technical information related to its modified in ment of Energy has investigated LETC's (Laramie Energy situ process. The IC's report adds, however, that Oxy's Technology Center) handling of the PON (Program approach is entirely understandable since the technical Opportunity Notice) cooperative agreement with Occi- information is crucial to establishing a competitive posi- dental for research at the Logan Wash facility near tion in the future oil shale industry. DeBeque, Colorado. The IC issued three reports: LETC has not been sufficiently aggressive in promoting "Project Management in the Oil Shale Pro- the dissemination of technical information developed gram," Report No. IG-123, released Septem- under the cooperative agreement. In the opinion of the ber ID, 1980. IC, there has been a misreading of the cooperative agreement that concerns the government's right to use "Dissemination of Technical Information and disseminate technical information. The IC found from the Oil Shale Program," Report No. IC- that both Oxy and LETC were operating as though Oxy 124, released September 3, 1980. could rightfully withhold critical information. Oxy believed it could withhold such important information as "Financial Management in the Oil Shale Pro- material and energy balances even though the coopera- gram," Report No. IG-125, released August tive agreement explicitly requires such information to be 13, 1980. reported, and LETC's interpretation corresponds to the restrictive view of Occidental. The IC fears that failure Project Management Investigated to enforce the agreement more vigorously may render DOE vulnerable to the charge that it is subsidizing The first report deals with project management. One private research and development without insisting on major issue is whether DOE's oil shale projects should adequate benefits for the public. utilize project managers or technical project officers as project supervisors. The IC found that LETC was using There have also been delays in the publication of Oxy's technical project officers, who operate with a much technical reports. For example, the final report for the more limited scope of responsibilities than that normally project's Phase I activities had not been provided to accorded project managers. The responsibilities exer- DOE's Technical Information Center at Oak Ridge, cised by the TPO for the Oxy project, for example, did Tennessee, for publication as of the time of the inspec- not include specific responsibility for monitoring project tion in March 1980--Phase I had ended on May 31, 1979. costs and timeliness in meeting schedules. Also the project's annual report for the period ending October 31, 1978 had not been published as of March Another issue is the present $100,000 limit on Laramie's 1980. This report had been submitted to the Technical contract authority. In the IG's judgement, it would seem Information Center on July 5, 1979. to be difficult to develop the management systems and experienced personnel required for executing multi-mil- In general, the IC found what could be characterized as a lion dollar projects under the present contract authority passive, rather than an active, technology program on limit. the part of DOE. If information were requested and Occidental did not consider it to be proprietary, the The IC found that the present reporting requirements information would be provided. incorporated in oil shale cooperative agreements tend to detract from a strong sense of responsibility for project Financial Management Is Investigated management at Laramie. Specifically, at the time of the inspection in March 1980, the cooperative agree- The IC found that substantial improvements are needed ments required copies of all progress reports submitted in the financial management of DOE's Oil Shale Pro- by contractors to be sent to Headquarters personnel as gram. LETC did not have an adequate accounting well as to Laramie. These reporting requirements were system to provide accurate information on the financial the same as those specified in 1977 in the original status of the Oxy project. For example, LETC did not cooperative agreements; no changes had been made after even know how much money DOE had paid to Oxy in 1978 when LETC was assigned responsibility for manag- connection with this project. According to Oxy's ing the oil shale cooperative projects. records, DOE had, in fact, paid Oxy more than had been obligated in the contract. The IG felt that the number of individuals assigned to Laramie's Office of Project Management was inade- In addition to the fact that DOE had paid Oxy somewhat quate. Consideration should be given to such alterna- more than obligated, a serious problem existed with tives as using a certain percentage of a project's esti- regard to DOE's ability to pay bills properly submitted by mated cost to hire the manpower needed to support a Oxy. LETC was withholding payment on millions of limited number of LETC project personnel. A similar dollars in bills submitted by Oxy that had been approved approach is currently used in managing projects at the for payment by the Laramie technical staff because the Solar Energy Research Institute.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-21 Oil Shale Program did not have the funds to pay the bills. Kingdom of Morocco, the Agency for International Laramie has negotiated an agreement with Oxy that Development (U.S. State Department), and the U.S. should remove DOE from this position. Department of Energy. The primary objective of the colloquium was a presentation of U.S. oil shale techno- Reviews by LETC of financial information provided by logy to the Moroccan government - their technical staff Oxy need to be improved. In several instances the as well as the private sector. numbers could not be readily reconciled in the cost proposals, the monthly financial reports, and the Most of the world's leaders in oil shale technology vouchers submitted by Oxy. Although the IC's discus- attended this colloquium, held in Rabat, October 6-10, sions with Oxy led to reconciliations, LETC did not have 1980. U.S. industrialists included participants from information to explain the differences. Marathon Oil Company, Fluor, Union Oil, Bechtel, Exxon, Tosco, Stone and Webster, Chevron, Foster- The IG also learned that Oxy had decided not to credit Wheeler, C. F. Braun, Morrison-Knudson, AMAX, Ceo- the project with $98,314 in revenues from the sale of kinetics, Oxy, the Rocky Mountain Division of Pace, and shale oil even though such credit is required by the many others. European representatives included cooperative agreement. Corrective action has been Deutsche Babcock AG, Shell International Petroleum, taken in this matter. Nalco Italiana, Esso Europe, and Lurgi Kohle and Miner- aloeltech. The IG foundare not variance analyses of the financial information are not conducted by LETC. The IG believes The Kingdom of Morocco is planning to develop a 50,000 that an analysis of the cost variances in the October BPD oil shale industry and bring it on line as soon as 1979 financial report would have shown that the project possible. This colloquium presented current technology was behind schedule and in danger of possibly overrun- to the 100 Moroccan officials who attended and acquain- ning the budget. ted them with those U.S. companies interested in doing business in Morocco. Similarly, Oxy needs to make variance analyses a routine part of managing the project. The October reports from Israeli Plans Are Reviewed Oxy did not indicate any concerns regarding cost or schedule, yet the IC believes a variance analysis would From October Il to 15, Decora was in Jerusalem where have provided a basis for concern. A review of Oxy's he participated in DOE review of Israeli plans to build a Forecast Change Notices indicate that by October 1979, 20,000 - 50,000 BPD oil shale plant. U.S. - Israeli changes had been approved by Oxy's management which cooperation in oil shale technology matters goes back to had the net effect of increasing project costs by more 1977, when Decora was the U.S. representative to an oil than $4,500,000. LETC was scheduled to have an shale conference held there. This conference was dis- improved financial management system in place by cussed on page 2-14 of the September 1977 issue of October 1980. Synthetic Fuels. Subsequent developments included a presentation by LETC personnel to the 10th International It should be pointed out that the reports findings focus Congress on Sedimentology held in Jerusalem in 1978 and on the Oxy project and LETC. The problems identified a nine-month appointment in 1979 to LETC of Dr. V. 0. in the reports are therefore directly associated with Schachter, Head of the Chemistry Department of Bar- LETC and the Oxy project. However, the lG believes it Ilan University. would be unfair and inaccurate to suggest that LETC is solely responsible for the problems; other organizations Oil Shale occurrences are very widespread in Israel. within DOE, such as the Headquarters Oil Shale Pro- Reserves amounting to at least 600 million tons have gram, have played important roles in executing the been established with an average of 14 percent organic Occidental project. In addition, DOES policy has been to content. Israel plans to use oil shale for steam and keep Laramie and the other Energy Technology Centers power rather than for oil production because of their dependent on support from the Operations Offices. urgent needs for power as contrasted with a smaller demand for transportation fuels. II I/I/il U.N. Shale/Sands Panel Meets in Switzerland LETC PARTICIPATES IN OIL SHALE MEETINGS IN Decora also participated in the Second Oil Shale and Tar MOROCCO, ISRAEL, AND SWITZERLAND Sands Panel of the United Nations Conference on New October was a significant month for the Laramie Energy and Renewable Sources of Energy held in Geneva, Technology Center, marking increased activities by the October 20-24, 1980. The panel began its work as a Center in the international arena. LETC's Director, Dr. result of a resolution of the General Assembly of the Andrew W. Decora, represented the Center and the U.N., which commissioned several other panels as well. Department of Energy at technical meetings in Morocco, The General Assembly wants a report from the various Israel, and Europe. panels to be presented to their body in Nairobi in August of 1981. Oil Shale Colloquium Held in Morocco Decora was nominated by the U.S. and selected by the Decora was the General Chairman of an Oil Shale U.N. Secretary-General to be a member of the first Colloquium, along with Mohammed Sdiqui, Director of panel, which met in New York City in January of 1980. Energy, Ministry of Energy and Mines, for the Kingdom He was elected chairman of the panel, which has repre- of Morocco. This colloquium was cosponsored by the sentatives from France, Morocco, Canada, Brazil, the People's Republic of China, USSR, Iran, Egypt, and the U.S.

2-22 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Panel discussions focused their attention on the potential of oil shale and tar sands as a new source of energy, especially for developing countries. Priorities for the future exploration and resource evaluation of these resources were assessed. Also, the assessment of the economic viability of oil from tar sands and shale oil, the comparisons of proposed projects with projects based on heavy oils and liquids from coal, and other sources of petroleum alternatives were addressed. The panel is concerned over a number of different types of environ- mental impacts associated with tar sands and oil shale exploitation. I/I/f/f'

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-23 STATUS OF OIL SHALE PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name Amoco Rio Blanco Oil Shale Company (C-a) ...... 2-27 Atlantic Richfield Company Paraho Development Operation ...... 2-26 Braun, C.F., & Company Naval Oil Shale Reserve Development ...... 2-29 Central Pacific Minerals Rundle Project ...... 2-27 Chevron Shale Oil Company Chevron Shale Oil Company ...... 2-26 Paraho Development Corporation ...... 2-26 Cleveland-Cliffs Iron Company Paraho Development Corporation ...... 2-26 Conoco, Incorporated Paraho Development Corporation ...... 2-26 CSR Limited Julia Creek Project ...... 2-29 Davy McKee Corporation Paraho Development Corporation ...... 2-26 Equity Oil Company Equity Oil Company ...... 2-28 Esso Australia Ltd. Rundle Project ...... 2-27 Exxon Company USA Exxon Colorado Shale Project ...... 2-29 Colony Development Operation ...... 2-26 Geokinetics, Inc. Geokinetics, Inc ...... 2-29 Gulf Oil Corporation Rio Blanco Oil Shale Company (C-a) ...... 2-27 Gulf Research & Development Co. Naval Oil Shale Reserve Development ...... 2-29 Mobil Research & Development Corp. Paraho Development Corporation ...... 2-26 Mono Power Company Paraho Development Corporation ...... 2-26 Multi Mineral Corp. Multi Mineral Corporation ...... 2-29 Nahcolite Mine Ill ...... 2-29 Occidental Oil Shale, Inc. Cathedral Bluffs Shale Oil Company (C-b) ...... 2-26 Occidental Oil Shale, Inc ...... 2-26 Paraho Development Corporation Paraho Development Corporation ...... 2-26 Petrobras Petrosix ...... 2-27 Phillips Petroleum Company White River Shale Project (U-a/b) ...... 2-28 Paraho Development Corporation ...... 2-26 Rio Blanco Oil Shale Company Rio Blanco Oil Shale Company (C-a) ...... 2-27 Southern California Edison Paraho Development Corporation ...... 2-26 Southern Pacific Petroleum Rundle Project ...... 2-27 Standard Oil Company (California) Chevron Shale Oil Company ...... 2-26 Paraho Development Corporation ...... 2-26 Standard Oil Company (Indiana) Rio Blanco Oil Shale Company (C-a) ...... 2-27 Standard Oil Company (Ohio) White River Shale Project (U-a/b) ...... 2-28 Paraho Development Corporation ...... 2-26 Sunedco White River Shale Project (U-a/b) ...... 2-28 Paraho Development Corporation ...... 2-26 Superior Oil Company Superior Oil Company ...... 2-27 Tenneco Cathedral Bluffs Shale Oil Company (C-b) ...... 2-26 Texaco Incorporated Paraho Development Corporation ...... 2-26 Texas Eastern Synfuels, Incorporated Paraho Development Corporation ...... 2-26

2-24 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Company or Organization Project Name

Tosco Corporation Colony Development Operation 2-26 Naval Oil Shale Reserve Development 2-29 Tosco Sand Wash Project 2-28 TRW Naval Oil Shale Reserve Development 2-29 Union Oil Company of California Union Long Ridge Project * 2-28 U.S. Bureau of Mines Multi Mineral Corporation. 2-29 U.S. Department of Defense Naval Oil Shale Reserve Development 2-29 U.S. Department of Energy Equity Oil Company 2-28 Geokinetics, Inc ...... 2-29 Naval Oil Shale Reserve Development 2-29 Occidental Oil Shale, Inc ..... 2-26 Paraho Development Corporation 2-26

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-25 STATUS OF SYNFUELS PROJECTS (Underlining Denotes Changes Since September 1980) SYNTHETIC FUELS FROM OIL SHALE ******ww*w*****w*****n****w******** COMMERCIAL PRO3ECTS***ww.,*i*if******M*M***********-***1****

CATHEDRAL BLUFFS SHALE OIL CO. --Occidental & Tenneco MS, R96W, 6PM) Bonus bid of $117.8 million paid to acquire rights to Tract C-b in 1974. original partners, ARCO 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 I, 1977. DDP approved 8/30/77. EPA issued conditional PSD permit 12/16/77. Contracts have been awarded and work has begun. Primary contractor is Ralph M. Parsons Company. Three headframes, two of concrete and one of steel, have been erected. As of earlyDecember the shaft depths were: Ventilation /Escape 11,3021, Service - J59, Production - Designated gassy mine 1/2180. Project Cost: $187 million spent to date. Estimated to total $5.9 billion by 1990. CHEVRON SHALE OIL COMPANY - Standard Oil Company of California (Garfield County, Colorado). Chevron plans to have a semi-works 300 TPD plant in operation by late 1983 using Chevron's Staged Turbulent Bed (SIB) retort. The company has not chosen the processing technology it will use, and process evaluation by Foster Wheeler will continue while the SIB retort is developed. Prime contractor is Morrison-Knudsen. Construction is planned to begin early 1982 on a demonstration mine and 5,000 BPD retort. Construction of commercial plant scheduled to begin in 1985, and full capacity production by modular increases to 50,000 BPD would be achieved by late 1988. Continued modular increases to 100,000 BPD are expected in early 1990s.

Project Cost: $5 million in 1979 $20 million in 1980 COLONY DEVELOPMENT OPERATION -- Exxon (60%) and Tosco (40%) (T55, R95W, 6PM) Proposed 48,300 BPD project on Colony Dow West property near Grand Valley, Colorado. Underground room-and- pillar mining and TOSCO II retorting planned. Production would be 66,000 TPD of 35 GPT 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 PSD permit 7/11/79. Land exchange consummated 2/I/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. Supplemental EIS is planned. Work on Battlement Mesa community commenced summer 1980. Colorado Mined Land Reclamation permit approval October 1980. Site development is proceeding.

Project Cost: Estimated at $1.6 billion including $20 million for community development.

OCCIDENTAL OIL SHALE, INC., LOGAN WASH MS, R97W, 6PM) Oxy is developing its modified in situ retorting technology on its Logan Wash site near De Beque, Colorado. Field tests have been underway since 1972. Initial tests were conducted on three small retorts measuring 30 feet square by 70 feet high. Thirty thousand barrels of oil were produced from first commercial retort between December 75 and June 76. 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 3/25178. Retort 6 produced 55,000 bbls, of which 48,000 bbls were recovered and stored. PSD permit for Retorts 7 & S awarded 11/1/79. Retorts 7 and 8 which will measure 165 x 165 x246 feet high, are being developed. Burn scheduled for late 1981.

Project Cost: To date at least $45 million spent $60.5 million DOE cost-sharing contract PARAHO DEVELOPMENT CORPORATION -- Chevron, Conoco, Davy McKee, Mobil, Mono Power, Phillips, Sohio, Sunedco, Texas Eastern, Cleveland-Cliffs, Texaco, and ARCo. (T95, R25E, Sec. 32, SLM) Paraho has 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 is funding $4.4 million of the IS-month study, and the Paraho participants are providing $3.7 million. The plant would be sited on Paraho's Utah State lease 40 miles southeast of Vernal. An additional $3.2 million grant is being negotiated by Paraho and DOE for a feasibility study to expand the single module facility into a 30,000 BPD plant utilizing three retorts.

Project Cost: $8.1 million for Phase I module design.

2-26 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SHALE (underlining Denotes Changes Since September 1980) COMMERCIAL PROJECTS (Cont.)

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 near 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. A 36-foot inside diameter vertical retort is being designed for construction at the San Mateus plant site for cold-testing of shale feed and discharge devices. This is a scale-up factor of four over the existing IS-foot inside diameter retort. Part of commercialization project is underway, viz, mine expansion, engineering of the retort, and equipment procurement. Partial operation will begin in 1984, and full capacity will be reached in 1987. Cold flow tests have been completed on Il-meter kiln. Project Cost: Total expenditures in excess of $35 million Projected cost of 50,000 BPD plant is $1.3 billion RIO BLANCO OIL SHALE COMPANY - Gulf & Standard (Indiana) (125, 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. Revised DDP calling for use of LLL Rubblized In Situ Extraction (RISE) of shale oil submitted to Interior 5177. Combination of modified in situ retorts and surface retorts (TOSCO II) will be used to produce 76,000 BPD. Five-year process development project will be conducted to prove in situ technology. Commercial facility scheduled to get underway in 1987. DDP approved 9/22/77. American Mine Services Inc. of Denver was awarded a $4 million contract 11/21/77 to sink a IS-foot wide, 971-foot deep shaft. EPA awarded PSD permit on 12/16/77. Primary contractor is Morrison-Knudsen Company with a $38.8 million contract. Tests are underway to determine underground water quantities. Agreement ($6 million) reached 3/79 with Oxy for exchange of modified in situ technical data. On 8/31/79 approval was granted to modify in situ retorts using RBOSC design. On 7/16/79 announced 1-year design and cost study ($4 million) that could lead to $100 million construction and operation of Lurgi-Ruhrgas surface retort demonstration plant. Shaft completed at 979' in 10/79, and outfitting is complete. Surface processing facilities complete. Designated gassy mine 11/30/79. Rubbling begun May 8, 1980, completed June 27, 1980, on 30' x 30' x 170' test Retort 0. Burn, begun October 31, 1980, expected to last up to 9 weeks and produce 1.000 - 2.000 barrels. First oil nrndiirecl earl y NJnvenhpr I Q%fl n,.v1 K,, .l.. loon

CQIUCUCII5SulCVtiI% dilu cui,strucuon contract br construction of 4,400 TPD Lurgi-Ruhrgas retort and design, engineering, procurement, and construction management of support facilities. Lurgi will supply the technology and engineering for the retort section.

Project Cost: Four-year process development phase budgeted at $93 million No cost estimate available for commercial facility.

RUNDLE PROJECT-- Central Pacific Minerals, Southern Pacific Petroleum, Esso Australia Development of the Rundle deposit in Queensland, Australia. Construction will begin in 1980 on two commercial demonstration modules using Superior and Lurgi-Ruhrgas processes. Production projected to be 20,000 BPD by 1982. By 1986, production would grow to 250,000 BPD from 40 retorts.

Project Cost: $316 million (US) for 20,000 BPD $2.16 billion (US) for 250,000 BPD. SUPERIOR OIL CO. (TIN, R97W, 6PM) Proposed project involving production of shale oil, nahcolite, alumina, and soda ash from a 6,500-acre privately owned tract in Piceance Creek basin near Meeker, Colorado. Underground mining and aboveground processing to yield shale oil, nahcolite, aluminum trihydrate, and soda ash. Facilities proposed to be constructed in modules of 11,586 BOPD from 26,176 TPD shale feed. Co-products would be 4 1 878 TPD of 80 percent nahcolite, 580 TPD alumina, and 1,005 TPD soda ash. Land exchange request to block up economically viable property filed with Interior 12/73. Draft EIS issued by BLM 7/17/79. USGS recommended against exchange 2/5/80. DOE awarded 19-month contract design single nodule demonstration retort June 1980. On November 10, 1980, agreement was reached whereby the Suoerior tract ownershin is Siinerinr - fl nerrnt cnh;n - in .,',-,t-..,A rl,..,I....4 rI:z€. .n ______

Project Cost: $300 million for one multi-mineral module $473,459 for EIS Phase I surface retort demonstration plant design; DOE-- $5.6 million, Superior -- $1.9 million.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-27 STATUS OF SYNFUELS PROJECTS/OIL SHALE (Underlining Denotes Changes Since September 1980)

COMMERCIAL PROJECTS (Cont.) TOSCO SAND WASH PROJECT - Tosco Corp. (T9S, R2IE, SLM) Proposed 50,000 BPD project on 14,688 acres of state leases in Sand Wash area of Uinta basin near Vernal, Utah. State-approved unitization of 29 non-contiguous leases requires $8 million tract evaluation by 1985. Minimum royalty of $5 per acre begins in 1984 and increases to $50 per acre in 1993. Preliminary feasibility study completed for TOSCO II surface retorting. Process and engineering work underway. Environmental assessment underway on site, but no other field work being conducted. Tosco has drilled a core hole on the Sand Wash site as a preliminary step to shaft sinking and establishment of a test mine. The test mine would confirm economics and mining feasibility plans for the commercial project. Permits for this new work have been received from the state.

Project Cost: Approximately $1 billion UNION LONG RIDGE PROJECT-- Union Oil Company of California (T55, R95W, 6PM) In 1974, Union announced plans for a commercial project ranging in size from 50,000 BPD to as much as 150,000 BPD on some 22,000 acres of fee land near Grand Valley, Colorado. Land, shale and water resources are adequate. Underground room-and-pillar mining and Union "B" retorting would be employed. Union's "B" retort is a modification of their direct-heated, rock pump retort first tested in the late 1950's. Current plans are to proceed with a 10,000 BPD (12,500 TPD) prototype facility in April 1981 before expanding to commercial production. Environmental and engineering studies are substantially completed for prototype facility. EPA issued conditional PSD permit 7/31/79. Colorado Mined Land Reclamation Board issued permit 8/2/79. Mine road improvements and bench enlargement scheduled for completion by end of 1980. Application for permits for an upgrading plant, oioeline. and rail line are being prepared. Production of 50,000 BPD is scheduled for 1988. Fluor is contractor for

Project Cost: Approximately $100 million for 10,000 BPD module Approximately $2 billion for 50,000 BPD module WHITE RIVER SHALE PROJECT-- Phillips, Sohio & Sunedco (TI, R94E, SLM) Proposed joint development of federal lease Tracts U-a and U-b in the Uinta Basin near Bonanza, Utah. Bonus bid for Tract U-a was $76.6 million by Sun (now Sunedco) and Phillips. Bonus bid for Tract U-b was $45.1 million by White River Shale Oil Corporation (jointly owned by Phillips, Sohio and Sunedco). Rights to Tract U-b subsequently assigned to Sohio. Both leases issued 6/1/74. Detailed Development Plan (DOP) filed with Interior 6/76 proposes modular development with ultimate expansion to 100,000 BPD. 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. WRSP's leases U-a and U-b are in jeopardy due to the existence of unpatented pre-1920 oil shale placer mining claims and by an, as yet unresolved, application for a state lease to the same property by Peninsula Mining associated with Utah's in-lieu land selection procedure. The injunction order suspending the U-a and U-b federal lease terms is uncontested and is in full force and effect. On May 19, 1980, U.S. Supreme Court ruled against Utah by reversing lower court's decisions in the in-lieu case. The final Environmental Baseline Study report was issued on 11115177 by WRSP. Utah approved White River Dam and Reservoir funding 2/78. On April 30, 1980, WRSP filed suit in U.S. District Court (Salt Lake) to preserve its investment beyond statute of limitations date. Updated draft DDP submitted to Interior November 1980. Final flflP due to be submitted for aooroval Februar y I. 1980. Prime contractor is Bechtel.

Project Cost: Estimated at $1.61 billion for 100,000 BPD project (1975 dollars) R&D PROJECTS**************************************

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 have reduced operations temporarily. Small amounts of shale "tar" produced November 1980.

Project Cost: DOE cost-sharing contract for $6.5 million.

2-28 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SHALE (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

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. GEOKINETICS, INC. Geokinetics has been conducting field tests to develop horizontal in situ retorting technology since 1973. Obtained ERDA contract 7/77 to develop technology in thin horizontal beds of oil shale in Uintah County, Utah. Porosity is established in formation by raising the shallow overburden during explosive fracturing of the shale formation. Total production to end of 1978 was 5,437 barrels. Total production for 1979 was 5,170 barrels. Retort 24 ignited early December 1980.

Project Cost: DOE cost-sharing contract valued at $9.2 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. Project Cost: A$2,000 million.

MULTI MINERAL CORPORATION - U.S. Bureau Of Mines Shaft (T15, R97W, Sec.30, 6PM) USBM began drilling IC-foot diameter, 2,400-foot deep shaft i/fl. Objective is to mine samples of oil shale, nahcolite, 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. Multi Mineral Corp. (MMC) is performing experimental mining. Draft EIS issued August 1980, withdrawn September 1980. Construction is

Project Cost: Over $8 million for shaft sinking.

*NAHCOLITE MINE I/I - Multi Mineral Corporation (TIS, R98W, 6PM) Multi Mineral Corporation plans to develop a one million TPY nahcolite mine on Federal sodium leases acquired from Industrial Resources, Inc. A mining plan is in preparation for submittal to USGS (Denver) January 1981. Permitting is via the Colorado Joint Review Process. NAVY OIL SHALE RESERVE DEVELOPMENT-- TRW Inc. Navy issued RFP 6177, calling for preparation of Master Development Plan for Naval Oil Shale Reserves I,?, 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 I and eight other Piceance Creek basin properties has been completed. Draft EIS issued September 1980. Project Cost: $2.16 million through 10/1/79 $60 million in 4 annual options

*New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-29 RECENT OIL SHALE PUBLICATIONS

Amy, Gary L., et at., "Groundwater Leaching of Organic Pollutants From In Situ Retorted Oil Shale. A Mass Transfer Analysis," Environmental Science & Technology, Vol. 14: No. 7, page 831, July 1980. Barron, Lance S. and Frank R. Ettensohn, "A Bibliography of the Paleontology and Paleoecology of the Devonian- Mississippian Black-Shale Sequence in North America," prepared for U.S. Department of Energy, Report No. DOE/METC- /5202-13, June 1980. Brown, Hon. C. (R-Ohio), "The Future of Synfuels," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980. •Bunger, J.W. and H.M. Wells, "Economic Evaluation of Oil Shale and Tar Sands Located in the State of Utah," prepared by the State College of Mines & Mineral Industries, University of Utah, for the Division of State Lands, State of Utah, September 1980. Butler, R. fl., et al, "The Extractocracking Process," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980. Chong, Ken P. et at., "Ultimate Tensile Strengths of Colorado and Utah Oil Shales," presented at the 15th Intersociety Energy Conversion Engineering Conference, Seattle, WN, August 18-22, 1980. Chong, Shuang-Ling, et at., "AJkanes Obtained by Thermal Conversion of Green River Oil-Shale Kerogen Using CO and Hp at Elevated Pressure," Israel —Journal of Technology, Vol. 17:pp. 36-50, 1979 Conley, E.M., et al., "An HO Extraction Process," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980. Coppola, Lt. E.N., et at., "The UOP Modified Flow Hydrocracking Process," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980. Cummins, 3.3., et at., "Conversion of Oil-Shale Kerogen in Co-Steam at Low Pressure: A Preliminary Report," Energy Communications, Vol. 6(2): pp. 117-135, 1980. *Dana, George F., et at., "Report of Investigations Shallow Oil Shale Resources of the Southern Uinta Basin, Utah," Report No. LETC/Rl-80/1 I, September 1980. "Details of Rundle Oil Shale Project Development Firmed Up by Partners," in E &MJ, August, 1980 issue, pp. 43 and 47.

Donnell, John R., "Potential Contribution of Oil Shale to U.S., World Energy Needs," Oil & Gas Journal, page 218, October 13, 1980. Fruchter, Jonathan S., "Elemental Partitioning in an Aboveground Oil Shale Retort Pilot Plant," Environmental Science & Technology, Vol. 14:11, page 1374, November 1980. Fryback, Melbourne G., "Economics and Commercial Prospects," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, Utah, September 10, 1980. Harris, R.K .,"Coal and Oil Shale: Expanded Use, Expanded Environmental Risk," presented at the conference on Synfuels and the Environment, sponsored by the Energy Bureau, Inc., and held in Washington, D.C. on October 16-18, 1980. Howatson, John, et at., "Reaction of Nahcolite with Sulfur Dioxide," Journal of the Air Pollution Association, Vol. 30:11, page 1229, November 1980. Jacobson, Irven A., Jr., "Oil Shale Oxidation at Subretorting Temperatures," June 1980, DOE/LETC, Laramie, Wyoming. Jackson, T., "Summary of Fuel Combustion Evaluation Test by GE and Pratt & Whitney," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980, *Reviewed in this issue.

2-30 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT PUBLICATIONS - OIL SHALE

Kim, Kunsoo and Abdul Mubeen, "Fracture Toughness of Antrim Shale," Topical Report prepared for the Dow Chemical Company, No. FE-2346-68, May 1980.

Latimer, D. A., "Air Quality Impacts of Oil Shale," presented at the conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C. on October 16-18, 1980,

Libicki, S.B. and J. H. Campbell, "Evaluation of Retort Performance Via Offgas and Product Oil Analysis: Geokinetics True In Situ Oil Shale Retort," Experiment 17, LLL No. UC-18810.

Lovell, Paul F., "Retorting Processing Principles," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, Utah, September 10, 1980.

Lovell, Paul F., "Shale Derived Liquid Processing-Process Principles," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, Utah, September 10, 1980.

Lovell, Paul F. "Environmental Concerns," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, Utah, September 10, 1980.

Mallon, Richard C., "Economics of Shale Oil Production by Radio Frequency Heating," Lawrence Livermore Laboratory, May 7, 1980, NTIS, l/UCRL-52942.

McDonald, J. William, "The Availability of Water for Oil Shale Development in the Upper Colorado River Basin." This paper was presented at the 55th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME, Dallas, TX, September 21-24, 1980.

Miller, G.A., "Water Availability and Requirements for Oil Shale Development," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980.

Moore, Colonel, "USAF Shale Oil Validation Program," presented at the Energy Symposium sponsored by the Air Force Systems Command Aero-Propulsion Lab and the San Antonio Air Logistics Center, San Antonio, Texas, October 21-23, 1980.

Morris, R., et al., "Developing Nitrogen-Tolerant Catalysts," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980.

"Oil Shale Activity Heats Up in the U.S.," in E & MJ, August, 1980 issue, pp. 39 and 43. "Oil Shale in the United States, 1981," prepared by Energy Development Consultants, Inc., Golden, Colorado, September 1980.

Pell, C.A. and G.A. Cochran, "Energy from True In Situ Processing of Antrim Shale," Preparation of a Cavity by Chemical Underreaming, Topical Report prepared for U.S. Department of Energy, No. FE-2346-43, April 1980. Peil, C.A., "Energy From True In Situ Processing of Antrim Shale," Preparation of an In Situ Retort Bed by Hydraulic Fracturing, Topical Report prepared for the U.S. Department of Energy, No. FE-2346-65, May 1980.

Petzrick, Paul, "Projects Status Report: Synfuels From Oil Shale," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C. on November 6-7, 1980.

Redente, E., "Impacts of Oil Shale on (a) Native Vegetation, (b) Wildlife," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980.

Robinson, W. E., "The Origin, Deposition, and Alteration of the Organic Material in Green River Shale," Organic Geochemistry, Vol. I: Pages 205-218, January 19, 1979,

Roen, John B., et al., "The Chattanooga Shale (Devonian and Mississippian) from the Tennessee Division of Geology-U.S. Department of Energy Cored Drill Holes Number 4 and 5, Hawkins County, Tennessee," prepared for the U.S. Department of Energy, No. DOE/METC/10866/18, 1980.

Rothman, A.)., "Lawrence Livermore Laboratory Oil Shale Project Quarterly Report, April-June 1980," LLL, published August, 1980, 43 pp. Russell, Paul L., "History of Western Oil Shale," 1980.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 2-31 RECENT PUBLICATIONS - OIL SHALE Schneider, A., "Production of jet Fuel for Air Force Test Programs," presented at meeting entitled Jet Fuel Looks to Shale Oil: 1980 Technology Review, sponsored by the AIChE and Air Force Wright Aeronautical Laboratories, Cincinnati, Ohio, November, 1980. Scrimgeour, Donald P., "Coping with the Oil Shale Boom," Planning, Vol. 46(8): pp. 19-21, August, 1980. Sinor, Jerry E., "Overview & Outlook: Oil Shale," Colorado Miner, Vol. 2:4, page 19, September 1980. Sladek, T.A.,"Overview of Oil Shale Development," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. U.S. Department of Energy, "Environmental Research on a Modified In Situ Oil Shale Process," A Progress Report from the Oil Shale Task Force, Report No. DOE/EV-0078, May 1980. U.S. Department of Energy, "Report on Financial Management in the Oil Shale Program," Report No. IG-125, August 13, 1980. -U.S. Department of Energy, "Report on Project Management in the Oil Shale Program," Report No. lG-123, September 10, 1980. *U.S. Department of Energy, "Report on the Dissemination of Technical Information from the Oil Shile Program," Report No. IG-124, September 3, 1980. Utter, S., "Stabilization of Oil Shale Waste Piles," presented at the 7th Annual UMR-DNR Conference on Energy, University of Missouri, Rolla, October 1980. Wakamiya, W., "Shale Oil Wastewater Treatment by Evaporation," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November 1980. Wallace, W.D., et al., 'Ultrasonic Velocity and Elastic Constants of Antrim Oil Shale," NTIS OFE-2346-37. Wernette, D.R., "Estimation and Mitigation of Socioeconomic Impacts of Western Oil Shale Development," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. *Young, David C., "Energy from In Situ Processing of Antrim Oil Shale," Quarterly Technical Progress Report for April- June 1980, prepared for the U.S. Department of Energy, No. FE-2346-72, July 1980.

OIL SHALE - PATENTS Atlantic Richfield Company, Ralph E. Styring, Jr., - Inventor, U.S. Patent 4,218,304, August 19, 1980, "Retorting Hydrocarbonaceous Solids." Mined, crushed hydrocarbonaceous solids are pyrolyzed in a retort with a gas containing hydrocarbons. The gas is heated to a suitable temperature of at least 600°F. Thereafter, a relatively small amount of oxygen is added to the heated gas outside the retort. The resulting mixture is then flowed into the retort. The amount of oxygen is theoretically sufficient to react with all of the hydrocarbons in the heated gas. The process is applicable to any type of retort to provide a source of heat for pyrolizing hydrocarbonaceous solids in the retort. The advantages of this modified indirect heated retorting method depends on the type of retort. This method provided added control over carbonate decomposition, coking or carbonization of the gas during heating, total gas flow, process variations, and the heat requirements and thermal efficiency of the process. Occidental Research Corporation, Leslie E. Compton - Inventor, U.S. Patent 4,218,309, August 19, 1980, "Removal of Sulfur from Shale Oil." Crude shale oil produced by in situ retorting of oil shale can contain from about I to 2 percent sulfur by weight, the sulfur being distributed widely through the lower and higher boiling fractions of the shale 'oil. Substantially non-condensible sulfur containing gas such as hydrogen sulfide is evolved from such crude shale oil by maintaining such shale oil at an elevated temperature in the substantial absence of added reagent, with the maximum temperature below thermal decomposition temperatures of such shale oil for sufficient time to lower the sulfur content of the shale oil. The United States of America as represented by the United States Department of Energy, Clyde J. Sisemore - Inventor, U.S. Patent 4,219,237, August 26, 1980, "Method for Maximizing Shale Oil Recovery from an Underground Formation." A method for maximizing shale oil recovery from an underground oil shale formation which has previously been processed by in situ retorting such that there is provided in the formation a column of substantially intact oil shale intervening between adjacent spent retorts, which method includes the steps of back filling the spent retorts with an aqueous slurry of spent shale. The slurry is permitted to harden into a cement-like substance which stabilizes the spent retorts. Shale oil is then recovered from the intervening column of intact oil shale by retorting the column in situ, the stabilized spent retorts providing support for the newly developed retorts. *Reviewed in this issue.

2-32 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 In ci4tJlI iL)fl1itS PROJECT ACTIVITIES

CONTROVERSY ARISES OVER SYNCRUDE'S S02 2 tions. Two union drives to canvass a majority of the Syncrude employees were begun in August.

With most attention focused on the federal-provincial oil 1/111111 pricing war in Canada, Syncrude Canada, Ltd. is em- broiled in its own controversy over air emissions. The CAT CANYON STEAM FLOOD UPDATED Alberta legislature was told in October that the Syn- crude plant had repeatedly exceeded sulphur dioxide The performance history of the steamflood demonstra- emission standards since the plant started operations in tion project in the Cat Canyon Field, as performed by 1978. The statistics were released in a report by the Getty Oil Company for the U.S. Department of Energy, Alberta Department of Environment and made public was updated recently with the publication of the Third along with the findings of a joint federal-provincial Progress Report on the Cat Canyon project plus a environment committee. The committee found that the contractor presentation in July, 1980. Details of the kind of control equipment chosen for Syncrude was "a project can be found in the June 1980 issue of the political, rather than a purely technical decision". Cameron Synthetic Fuels The Third Progress Report of the Williams Holding Lease Steamflood The Environment Department report shows that on 29 Demonstration Project, Cat Canyon Oil Field, covers the separate occasions the Syncrude plant exceeded the 0.2 period of July 1978 through December 1979. The perfor- ppm standard for a half-hour period. On four occasions mance of the displacement steam generator, the status limits for a one-hour period were exceeded and on two of the sulfur dioxide scrubbing system, well workovers occasions limits were exceeded for a 24-hour period. and the results of drilling four thermal observation wells One of the worst violations came on February Il, 1980 are examined, along with additional computer thermal when emissions were 1.56 ppm for a half-hour period. simulation studies and new performance projections. The plant, however, operates under a license based on its compliance with standards on a 30-day mean. The plant The Williams Holding lease of Cat Canyon Field is is not in violation of its license if it can counterbalance located in Santa Barbara County, California. The first emissions with ones below the standard. four years of operation of this project are summarized in the June 1980 issue of the Cameron Synthetic Fuels Publicity over the readings have embroiled the plant in a Report. Figure I illustrates the pilot configuration. In political controversy. New Democratic Party Leader in March of 1978, packer and liner failure problems were Alberta, Grant Notley, has suggested that the plant solved and continuous steam injection was again estab- improve pollution control equipment so that standards lished. Cyclic steam stimulation of the pilot producers, can be consistently met. He stated that this would cost excluding wu 205 and WH/RF 204 was performed from approximately 23 cents for each $38 barrel of oil pro- May through July, 1978. From mid-June, 1978 through duced. Alberta Environment Minister Jack Cookson said January 1979, WH/RF 204 was shut-in, in an attempt to that the government tries to work co-operatively with divert steam towards nearby pilot producers WH 25 and the companies to reduce emissions and prefers not to WH 35. By October 1978, WH 25 was showing an shut down any plant. Concern has been expressed that increasing temperature response to the displacement the excess sulfur dioxide will contribute to a potential phase and a higher production rate. acid rain problem. Soon after WH 25 began showing heat response, all four Trucks Are Purchased responding producers were shut-in. This was done in hopes of diverting steam to other non-responding pilot In another development affecting the Syncrude plant, the producers, thus distributing heat more evenly within the company announced in September that it has ordered ten reservoir and lowering artificial lifting requirements. 170-ton Terex trucks for use in the mining operations. The wells remained shut-in for eight months in 1979 with The trucks will be used together with shovels, supple- no apparent success in diverting steam to other areas of menting the operation of the dragline at Syncrude. The the pilot. These four idle producers were returned to trucks will be powered by 1,600 hp Detroit Diesel production in December 1979. engines which will be built at the Terex Diesel Divisions main plant in London, Ontario. The cost will be approxi- Oil production from this test was disappointing in that mately $8 million (CdnJ. total pilot oil production response did not match the gross production response to steam displacement. Union Is Opposed Response to steam injection was first evident in August 1978 at a rate of 291 BOPD which declined to 106 BOPD A company newsletter released in late August has stated in March 1979. This was due to the fact that production that the company is opposed to the organizing of unions response was seen in only four of the producing wells and at the facility. The newsletter stated that the company it became impossible to keep these wells pumped off. prefers to operate without a union and that Syncrude is The responding producers where shut-in in April 1979, to seeking direct communication links between employees encourage heat response in the remaining five producers. and management. The company believes that this can be After shut-in the oil production from the remaining five more easily achieved without third-party representa- producers increased from 50 BOPO in April 1979, to an

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-I

/ 'RECRUIT FEE/ -5 / 204

/ /25

S 105e\ (( 4/A ,).3o5 95 A,935a S / A3\ p826 ft 35 /i S\ ,t

/ S PRODUCING WELLS .0 INJECTION WELLS A THERMAL OBSERVATION / A WELLS "WILLIAMS HOLDING CO '.L...L. .J- C' - -

FIGURE I WILLIAMS HOLDING STEAMFLOOD PILOT CONFIGURATION

average of 89 BOPD for the next four months. In Crude increased from $8.68/bbl in April 1977, to September 1979, oil production dropped to a low of 47 $15.33/bbl in November with a subsequent increase to an BOPD with the loss of sand control in WH 105. Oil effective price of about $20fbbl in December 1979. As production recovered somewhat in October 1979, to 75 oil production improves and generator fuel is switched to BOPD. Cat Canyon Crude, economics should substantially improve. Four thermal wells were drilled within the pilot to monitor area! and vertical response to steam displace- In conjunction with the pilot test, Getty Oil Company is ment. Each thermal observation well was located also testing a stack gas scrubber for the removal of between one of the four injectors and the central sulfur dioxide from emissions resulting from burning high producer, WH 205. Thermal observation well I (TO 1) sulfur (4.5 percent) crude oil as steam generator fuel in a was drilled and completed in June 1979. wells TO 2, TO 22 MM Btu/hr generator. Details of this project are 3, and TO 4 were drilled and completed in October 1979. contained in the June 1980 issue of the Cameron Syn- When TO I was drilled a totally "grey" sand was found thetic Fuels Report. After a major re-design of the below the injection interval with near virgin oil satura- scrubbers to improve gas-liquid contact, a series of tion throughout the SI-B Zone. This prompted the certification tests were performed for the Environ- further investigation of a possible wet thief zone below mental Protection Agency and the Santa Barbara County the injection interval. After drilling the other three Air Pollution Control District. A schematic of the re- thermal wells, and, after a computer simulation study, it designed system is illustrated in Figure 2. The scrubber was shown that the "grey' zone was not acting as a wet was able to meet the emissions limits while operating in thief. Instead, overinjection, channeling within the 51-B the desired pH range of 6.8.7.0 during the testing. Table Zone and low sandf ace steam quality were determined to 2 summarizes testing results. The scrubber reduced be factors causing the high water production and low oil emissions of sulfur dioxide from 83 -97 percent and 73 - production. 86 percent of particulates. A small reduction of nitrous oxides was also noted. Project economics have been generally unfavorable with operating costs per barrel of oil produced running very high. Recently, project economics have been adversely /111 II It affected by declining oil production and inflation, with the cost of low sulfur fuel oil burned in the steam generator a major factor. Table I summarizes project economics. The price currently received for Cat Canyon

3-2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 1

WILLIAMS HOLDING STEAMFLOOD PILOT SUMMARY OF ACTUAL OPERATING COSTS TO DATE ($/BBL OIL PRODUCED) Period; June 25, 1976 to December I, 1979

Cost Displacement Generator 1.28 (exluding fuel) $

Displacement Fuel 5.51 Contract Services 2.49 Company Services 0.71 Materials and Supplies 1.17 Utilities 0.46 Central Plants 0.50 Cyclic Stimulation 0.82 Engineering and Supervision 0.45 Computer and Deliverables 0.08 General and Administrative 0.46 Total Operating Costs $13.93 Major Well Workovers I (1.28) Operating Costs Excluding Major Well Workovers $12.65 The major well workover costs only include the liner replacements that were required on WH 205, WH 36, and the four pilot steam injection wells.

TABLE 2 SCRUBBER PERFORMANCE Emissions Permit Scrubber Scrubber Percent Pollutant Limit Inlet Outlet Reduction 502 (lb/hr) 11.0 49.4-79.7 1.2-10.3 83-97 NO 2 ON) 11.2 6.0-7.7 5.5-7.4 2-7 Particulates 0.3 0.27-6.4 0.07-0.10 73-86 (gr/scf)

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-3 S TO AG C SATISFY CLEAN FLUE 053 FUEL PUWF EXHAUST SUET

PETWOTHEAU

GCSCflTOI OEMI,tc.

-;,7; MUNUSS I C iCTACA FILL

o -- SLOW CS w,OSOCTCLONE

00%CAUSTIC SO DA

AND SOLIDS TO WASTE

F.ES WTCWHA ASIAF

0 CAUSTIC PQMP IDEA

FIGURE 2 SCHEMATIC OF SULFUR DIOXIDE REMOVAL SYSTEM

SUNCOR HURT BY NEW ENERGY POLICY Alberta. The facility will be built on the oil sand plant site near Fort McMurray. The 76,000 square-foot struc- The new budget proposed by Prime Minister Trudeau in ture will house the oil sands division management, pro- November has severely cut the Suncor plant's cash flow. fessional and technical staff. The workforce will be (See article on Energy Policy in the Government Section, expanded and the 120 employees currently residing in this issue). Under the terms of the new budget, Suncor Edmonton will be transferred to the new facility upon will receive only the conventional domestic oil price for completion. its first 45,000 barrels per day of production, beginning January I, 1981. The new price will be approximately Sulfur Shipped Overseas $16.75/bbl. Suncor had been receiving world price of $38 per barrel for its production. The Syncrude plant will In August, the first sulfur production from both the continue to receive this price. Once the 15,000 barrel Suncor and Syncrude plants was shipped to overseas per day expansion is completed, the Suncor plant will markets. The sulfur is formed by a new granulation receive world price for this portion of its production. process known as the Procor GX process by Procon Ltd. The move is expected to cut the company's cash flow by and Sulmar Canada Ltd. The two plants produce 400 $1.5 billion over the next five years. tons/day, which is moved by mini-unit trains. Production is expected to double in late November, after expansion Canadian federal officials justified their stand by noting is completed. that the Suncor plant was built in 1967 for a cost of $235 million compared to the billions required for a new plant. 1/1/111/ Officials stated that allowing the Suncor plant to receive world price for its oil was "like a license to print ALSANDS AND ESSO COLD LAKE PROJECTS money". There has been some speculation that Suncor PUT ON HOLD could become a prime takeover target by the Canadian national oil company, Petro-Canada. Suncor would be in In September, the Alsands Project in Alberta was put on a weakened position with the value of its prime asset cut indefinite hold by the Alsands Consortium (Shell Canada, in half. Shell Explorer, Amoco Canada, Petro-Canada, Chevron Standard, Gulf Canada, Hudson's Bay Oil and Gas, Petro- Office Expansion Contract Awarded fina, and Dome Petroleum). A decision was made to cancel a $200 million (Cdn.) site preparation program In late July, Suncor awarded a contract for the construc- slated for this winter, due to the federal-provincial tion of a new $9- 10 million office expansion program to impasse on oil pricing agreements. In aneffort to break A. V. Carlson Construction Corporation of Edmonton, the deadlock, the Alsands consortium presented its own

3-4 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 plan for synthetic crude pricing which was called a Esso Resources Canada, and the Japan Canada Oil Sands margin-sharing concept. The concept is a variation on Ltd. Under the first phase of the project, Japan Canada the U.S. windfall profits tax concept, in which synthetic Oil Sands Ltd., (JACOS) a consortium of the Japan crude would receive world oil price, but any excessive National Oil Corporation and sixty-seven private profits would be plowed into the federal govenment's companies, must complete the required expenditures crude oil compensation fund as an indirect rebate to the negotiated under a 1978 paramount agreement. JACOS consumer. This proposal was considered by both Alberta contributed the required $30.8 million by September 15. and Canadian federal governments when oil pricing talks Under the farmout agreement, JACOS obtained the right resumed in October. However, the talk ended in stale- mate. to earn a 25 percent working interest in 1,236 million acres of oil sands leases, in three phases, over a 15-year period, as well as rights to an in situ recovery process With the release of the Canadian federal energy plan and owned by the PCE group. If JACOS exercises its options budget in October, Alberta was provoked into retaliatory for the second and third phase, it will spend $74.8 million action which affected the Alsands project (see Energy by the end of the project. Policy article, this issue). Premier Loughheed announced in October that the two large pending oil sands projects, During the Phase I operations, Petro-Canada, the Esso Cold Lake and Alsands would be put on hold until operator for the group, completed sixty-two coreholes to the oil pricing dispute is resolved. In the new energy obtain an evaluation of in-place reserves. Petro-Canada policy, Ottawa had proposed a price of $38 per barrel for also directed design and construction of a field pilot the new oil sands production. However, spokesman for consisting of four electrode wells, eight observation both projects have remained cool to the offer because of wells, and associated surface facilities designed to test a number of problems. They include: an electric preheat/steam drive process. Although the process is divided into two stages of electrical preheat- The offer stated that the price will be esca- ing and conventional steam drive, JACOS has joined the lated at the rate of the Consumer Price Index group to conduct a two-well steam stimulation test and construction costs are rising faster than simultaneously with the test of the electric pre- average inflation. heat/steam drive process. This simultaneous test was proposed by Esso, since the surface facilities of the The offer does not address the revenue- second stage steam simulation test will be in place sharing arrangements between the project during the electric preheat stage. The aim of the sponsors and the two levels of government. simultaneous test is to determine cost effectiveness of the operation and provide information for design of other The federal energy policy includes other pilot schemes. measures that could cut the sponsor's cash flow and therefore impair their ability to The pilot project, located at Stoney Mountain, approxi- finance the projects. mately 35 km south of Fort McMurray, Alberta, will continue to be operated by Petro-Canada, with research Ottawa had hoped that the project sponsors and possibly and development activities in support of the field project the community of Cold Lake would put pressure on the conducted by Petro-Canada's newly opened research provincial government to give approval for the projects. center in Calgary. The electric preheat phase of the project was started in October. The Alsands project group will meet on December ID to vote on next year's planned budget. It is expected that a 'log/I decision will be made at that time to either mothball or dismantle the project. The members of the nine- ESSO APPLIES FOR COLD LAKE FUEL CHANGE company consortium can exercise an option to back out of the project on December 31. In September, Esso Resources Canada Ltd. asked the Alberta Energy Resources Conservation Board (ERCB) to In a related development, Canadian Federal Energy reconsider the make-up fuel to be used in the proposed Minister Mer y Leitch reported in September that govern- Cold Lake in situ project. In its decision issued in ment oil sands researchers are considering a test project October, 1979, the Board had required Esso to utilize to see if small oil sands plants can be economic. The coal as a primary make-up fuel, in the approximate plants would be capable of producing approximately amount of 1,300,000 tonnes per year. In the present 25,000 barrels per day instead of the 140,000 - 160,000 application, Esso asked that it be allowed to use barrels per day planned by the larger projects. Because 435,000,000 cubic meters of natural gas as make-up fuel. of the impasse on approval of the Alsands and EssoCold The application addressed not only a change in the fuel Lake projects, it is thought that smaller plants may balance but also necessary changes in the resulting proceed in place of the "mega-buck" projects. facilities and the incorporation of new design data for some facilities. 11111111 In the proposal, Esso states that although improvements PCE PLOT PR03ECT PROGRESSES in design and energy conservation measures have reduced the amount of coal needed for make-up fuel, the cost of The first phase of the PCE Tar Sands pilot project, which coal transportation, unloading and boiler equipment has uses an electric preheat and steam drive process, was increased significantly. Assessment of the operating completed in September. The PCE group includes Petro- costs of both coal and natural gas shows coal to be more Canada Exploration, Inc., Canada-cities Service, Ltd., expensive. Increases in costs have escalated the total

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-5 project cost from the original $4.6 billion to $9.1 billion feasibility of injecting steam to mobilize the bitumen in using coal as a make-up fuel. This figure reflects only a Utah tar sand, (2) evaluate various injection and the initial investment required to achieve fuel produc- production well completions, and (3) determine feasi- tion. Esso asks that the Board reconsider use of natural bility of recycling produced water and utilization of gas as a make-up fuel and, failing that, to defer the produced bitumen as fuel. All objectives were accomp- requirement until the project achieves production capa- lished, within the planned scope of the experiment. city when the fuel requirements can be clearly estab- lished. The ERCB held hearings on the proposal in Data generated by the experiment are currently being October and a decision is expected shortly. evaluated, but the following preliminary data were avail- able at press time: In the meantime, Esso Resources is expected to make a re-assessment of the Cold Lake Project's viability in TABLE 1 light of the new Canadian Federal energy policy. (See articles on Energy Policy and Alsands in this issue for AVERAGE RESERVOIR AND OIL PROPERTIES further details). The project is now entering a critical phase where monthly expenditures on it increased from Depth to top of test zone, feet 487 $6 million (Cdn.) to $10 million (Cdn.) in October and $12 Test zone thickness, feet 45 to $14 million (Cdn.) in December. Although Esso has expressed the opinion that it would rather gear down the Formation dip, degrees 28 project progress in hopes for the problems to be resolved Porosity, percent 29.5 than to cancel it altogether, the company is prepared to "pull the plug" on the project. Permeability, saturated, md 120 Permeability, extracted, md 2,175 Ii I/il/I Initial reservoir temperature, OF < 100 BP CANADA ANNOUNCES NEW PILOT PROJECT Oil Saturation, percent of pore space 78.9 BP Canada announced a plan for a new $100 million Oil in place, 0.25 acre, 45 feet thick, (Cdn.) pilot plant in the Cold Lake area of northern barrels 20,300 Alberta in August. The plant is located near the Water saturation, percent of pore space 3.2 Alberta-Saskatchewan border, and will produce between 5,000 and 10,000 barrels of oil per day. It will be the Oil viscosity, @60°F, cp > 10.6 largest pilot plant in the area with the exception of @200°F,cp 20,000 Esso's five facilities. The pilot plant is another step Oil gravity, *API 14 toward construction of a commercial scale heavy oil plant in the 1990's. TABLE 2 The current schedule calls for up to 30 wells to be drilled on the 75,000 acre site this winter to determine the best LETC TS-IS DATA location for the plant. An application of the Alberta Energy Conservation Board is to be submitted in 1981 Steam Injection and the pilot plant will be completed in 1983. The project will use an in situ combustion technique to Initiated 4/23/80 recover heavy oil at depths which will range up to 2,640 Terminated 9/29/80 feet. BP Canada's heavy oil manager Ralph Capeling Pressure PSIG 410-500 warned that the energy pricing dispute between the Temperature, O F 450-470 Canada federal government and the provincial govern- Cumulative, water equivalent, ments must be resolved before actual construction is barrels 54,000 started on the project. Pan-Canadian Petroleums Ltd. Production and Hudson's Bay Oil and Gas., Ltd. each have options to earn interest in BP's Cold Lake holdings. Oil, barrels 990 Water, barrels 6,000+ Maximum reservoir temperature recorded, O F 465 DOE TAR SAND FIELD EXPERIMENT IS COMPLETED Figures 1 and 2 are a photograph and a schematic The U.S. Department of Energy's Laramie Energy Tech- diagram of LETC TS-IS, respectively, provided to the nology Center (LETC) has recently completed their first Cameron Synthetic Fuels Report by Mr. Lee Marchant of field experiment to test the technical feasibility of in LETC, along with the preceding information. situ steam drive for production of oil from U.S. tar sand. The experiment was conducted on Sohio Natural I/I/fill Resources Company property in the Northwest Asphalt Ridge tar sand deposit near Vernal, Utah. Original reservoir and oil properties are listed in Table L The field experiment (LETC TS-IS) was conducted to accomplish several objectives: (I) determine technical

3-6 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 -6 c* £ -: r

- •

J1 - ! W4ij Ø

-

-

FIGURE 1 LETC TS-IS SITE

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-7

tin Pwr, tin. • HiC ompr.nnor Bldg

• lank Form Production I-.- W.I., Pit Spare Tank .:—QJ,Q -1.7 T-6 Pump Haute Td•0t5t Offir. Bid, L.ii_YLjr'Clean Oil F.nc.

Boiler Production House Troil.r 'n Bldg LPGon C -4,0 Sal ten•r M in LEIC 1.10 Hard H2O olfic. Bldg LP Go, I-Il Salt H,0 C omptter Bldg • 1-9 - Fuel Tank, l° Btu/Hr -- j_VSt.amG--

Production £ Test Linen / kZM4\

Innulated £ Steam er?P /

• Production Well lrace Healed "*34*2 y'3M1 O Injection Well I"'er' -4 31`1 • Monitor Well 0 50 190 Feet -314

Wool FIGURE 2 SCHEMATIC OF THE FIELD EXPERIMENT

3-8 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

TECHNOLOGY

PAPERS PRESENTED ON HYDROTHERMAL STUDIES have been used to study several areas of concern which include: Two papers on hydrothermal studies of in situ oil sands operations were presented in July during the Symposium • Low permeability and poor flow characteris- on Water-Rock Interaction, sponsored by the Interna- tics of fine-grained sand; tional Association of Geochemistry and Cosmochemistry and the Alberta Research Council in Edmonton, Alberta. • High residual oil saturations in flow experi- The first paper, entitled "An Experimental-Statistical ments; Study of Mineral Transformation During In Situ Recovery of Bitumen from Various Oil Sand Deposits in Alberta, • Mineralogical immaturity and high degree of Canada," is by J. A. Boon of the Oil Sands Research hydrothermal reactivity for sands; Center, Alberta Research Council. • Generation of montmorillonite and 2:1 In this study, core material from the Peace River, mixed-layer, surface-active, high cation ex- Wabasca, Cold Lake, and Athabasca formations in the change capacity, swelling clays; presence of crude bitumen was subjected to hydro- thermal treatment with aqueous fluids of varying pH and • Formation damage through deposition of salinity at two different temperatures for 26 days. The other minerals, resulting in reduced porosity; fluids used were deionized water or pH 9.1 borax buffer and no NaCI or 0.1 M NaCl at 2000 and 250°C. The • Possible fines dispersion during flow, resul- aqueous fluids were then analyzed for anions and cations ting in pore blockage, and and the less than 45 mm fraction of the sand was subjected to standard X-ray diffraction procedures • Possible clay organic interactions. (XRD). The relative amounts of the clay minerals were calculated from the intensities of their basal reflections. Laboratory studies have been conducted on core material The XRD intensities of analcime, calcite, dolomite, and over a range of temperatures and pressures corre- feldspar were expressed relative to that of quartz. A sponding to field conditions plus both state and flow computer program was also used to calculate the differ- tests have been conducted. ence in Gibbs free energy between the actual state of the solution and its equilibrium state with respect to the The dominant physical and chemical effects resulting mineral being considered. from the hydrothermal treatment of the Primrose sands are: Conclusions gained from the study are as follows: Post-steam increase in *40 (<425 urn) size • At certain levels of the other independent fraction, variables, bitumen has a significant effect on the reactions involving analcime, chlorite, or Gas production is observed in all hydro- kaolinite. thermal experiments with the most commonly produced species being CO 2, C 1- • At 200°C, in the absence of borax, bitumen C41 H 25, and H2. appears to retard reaction. Mineral reactivity increases with decreasing • In regard to fluid consumption, the partial initial grain size, duration of experiment, consumption of added Na was noted, especi- increasing temperature and increase in pH. ally at high pH and salinity. The minerals that typically disappear for the pre-run assemblage are dolomite, siderite, • The bicarbonate content increased with tem- calcic plagioclase and anhydrous ferro- perature and pH and its relation to carbonate magnesian minerals. mineral content of the cores, and Copies of these papers may be obtained by purchasing • In many cases, it appeared that solution- the proceedings of the conference which are available mineral equilibrium was not achieved. for $20.00 Canadian from: The second paper is entitled, "Primrose Pilot Hydro- Dr. Brian Hitchon thermal Studies Program," by T. S. Hamilton also of the Secretary General, WRI-3 Oil Sands Research Department of the Alberta Research Alberta Research Council Council. This paper details the hydrothermal research 11315- 87th Avenue done in support of the Norcen Energy Resources Prim- Edmonton, Alberta rose Pilot which is located near Cold Lake, Alberta for CANADA T6G 2C2 the recovery of heavy oil from the Lower Cretaceous Clearwater Formation of the Upper Mannville Group I/I//HI using in situ steam stimulation. Hydrothermal studies

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-9 DOE HEAVY OIL CONTRACTORS MAKE PROJECT "DEEP STEAM" PRESENTATIONS by R. Fox Sandia Laboratories The Department of Energy, Fossil Energy Division, has recently published its 1980 heavy oil, enhanced oil re- POTENTIAL SOLAR APPLICATION TO EOR STEAM covery project presentations. The presentations were GENERATION made in July 1980 in San Francisco, California. They by G. Elzinga summarize the progress made in each project- dealing EXXON Resource and Engineering Company with thermal recovery, chemical flooding, and carbon dioxide. The papers were published under the title, One project of interest not previously reviewed in the "1980 Annual Heavy Oil/EOR Contractor Presentations- Cameron Synthetic Fuels Report is the Lynch Canyon Proceedings," September 1980, CONF-800750, and are Thermal Drive Oil Recovery Project. This project was available from the National Technical Information started in September of 1978 under an agreement nego- Service. Presentations made on steam drive processes tiated with Mobil-GC Corporation (formerly General are as follows: Crude Oil Company) and the U.S. Department of Energy. The objective was to demonstrate and evaluate the THE LYNCH CANYON THERMAL DRIVE OIL recovery of a very viscous crude oil using the Combina- RECOVERY PROJECT tion Thermal Drive Process aided by cyclic steam injec- by J. R. Stair tion in a large-scale field operation. Included with the Mobil Oil Corporation project was the demonstration of an automatic data accumulation system for optimum project operation and STEAMFLOOD DEMONSTRATION PILOT control. Williams Holding Lease, Cat Canyon Field, Santa Barbara County, California The area selected for the project was the Lynch Canyon by Gary R. Adamson and Edward J. Hanzlik Oil Field, located in Section 23 and 24 of T22S, RIOE, Getty Oil Company Monterey County, California on approximately 60 acres. The oil bearing horizon was the Lanigan sand, a 9° API THE "200" SAND STEAMFLOOD DEMONSTRA- oil with a reported viscosity of 9,000 centipoise at a TION PROJECT reservoir temperature of 104°F. The Lanigan sand is at by Willie 0. Alford a depth of 1,800 feet, and has an estimated oil-bearing Santa Fe Energy Company-Chanslor Division area of 500 acres and a net oil sand volume of 8,230 acre-feet. Oil-in-place is estimated at 14.6 million FIELD DEMONSTRATION OF THE CONVEN- barrels. TIONAL STEAM DRIVE PROCESS WITH AN- CILLARY MATERIALS-1 General Crude acquired the property in 1972 after by R. Eson previous owners had failed to produce economic quan- Petro Lewis Corporation/CORCO tities of oil. In 1977, a proposal was submitted to ERDA to use the Combination Thermal Drive process, which FIELD DEMONSTRATION OF THE CONVEN- features the simultaneous injection of air and water. In TIONAL STEAM DRIVE PROCESS WITH 1978, the contract with the Department of Energy was ANCILLARY MATERIAL-11 signed and the demonstration project was begun. The by CLD Group, Inc. project consisted of tour phases: SCREENING OF FOAMING AGENTS FOR USE IN • Phase I was designed to evaluate the geology STEAM INJECTION PROCESSES and reservoir characteristics by drilling four by O.S. Owete, A. AI-Khafaji, F. Wang, L. M. wells and coring three, Castanier, S. K. Sanyal, and W. E. Brigham SUPRI • Phase II was to consist of an inverted five- spot well pattern, air injection test, labora- FOAM AS A MOBILITY-CONTROL AGENT IN tory work and ignition of the first well, STEAM INJECTION PROCESSES by In C. Chiang, Subir K. Sanyal, Louis M. • Phase lIlA and IIIB would have involved faci- Castanier, William E. Brigham and Arshad lity installation, well drilling and operation of Sufi the project. Phase lilA would have been a SUPRI period of dry combustion without water in- jection and Phase IIIB was to provide for the SCALED PHYSICAL MODELS OF STEAM DRIVE injection of both air and water, OPERATIONS by T. M. Doscher and 0. Omoregie • Phase IV would have provided for a continua- USC tion of the heat scavenging in the first row of producers. In addition, the final evaluation AN ENGINEERING ECONOMIC MODEL FOR and report preparation would have been com- APPRAISAL OF THERMAL RECOVERY pleted. METHODS by R. L. Williams (Getty Oil Company), S. L. Phase I operations were completed as scheduled. In Brown, and H. J. Ramey, Jr. addition, one of the four wells drilled was placed on SUPRI production and was steam stimulated. The Lanigan sand

3-10 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 was characterized by these cores and tests as having a 5' produced oil is very similar to the original tar sand - 10' interval of high water saturation and relatively low bitumen. permeability immediately above the oil sand. The oil sand itself is divided into two members, a top section "Aboveground Processing of Utah's Tar Sands and with 70 percent oil saturation and 3000 - 6000 md Characterization of Synthetic Liquids Derived from the permeability and a lower section from 0' - 20' of 60 Bitumen", by Francis V. Hanson and Alex G. Oblad, percent oil saturation and 1000- 3000 md permeability. University of Utah, Salt Lake City, Utah. After performing both laboratory studies and drilling Studies of "Aboveground Processing of Utah's Tar Sand operations, several points of concern became evident. and Characterization of Synthetic Liquids Derived From These points included: the Bitumen", at the University of Utah was discussed • for Sunnyside tar sand (some tests were also made on A decrease in oil sand volumes compared sand from the Tar Sand Triangle deposit). The Sunnyside with previous estimates, sand was stripped of bitumen by a Mobil Oil Co. method that utilizes hot H 2 • An increase in drilling costs due to the over- O and a heated bed fluidized by nitrogen. This treatment for 20 minutes at 650 -798°F lying high pressure water sands, yielded 60 percent oil, 20 percent coke, and IS percent • gas (gas yield increased with increase in temperature). An increase in investment due to environ- Residence time could be decreased by the use of larger mental considerations, and equipment. The product varied with treatment times, but it may contain 19 percent saturates (only about 3 • -5 Substantially higher than anticipated oil vis- percent aromatics), 2 - 5 percent polar compounds, 25 cosities. percent asphaltenes, and 5 percent resins. The crude contained 0.56 - 1.26 percent nitrogen and 0.4 percent, Due to these adverse conditions and unfavorable project or less, sulfur. The crude was analyzed by a Mobil economics, Mobil Oil decided to terminate the project method based on the use of solvents followed by chroma- after the first phase, during 1979. tographic analysis. The tar and crude were better than are obtained by the H-Coal process, and can be pro- 1/1/111/ cessed by usual refinery techniques, although some diffi- culty might be encountered with nitrogen. A laboratory CONFAB 'SO HELD IN LARAMIE catalytic cracking unit is being built.

Confab 180 was held during July at the Laramie Energy "Hydropyrolysis Processing of Residual Materials," by Technology Center, U.S. Department of Energy, Lara- J.W. Bunger and D. E. Cogswell, University of Utah, Salt mie, Wyoming. The purpose of the conference was a Lake City, Utah. technology exchange between industry and academia on the results of studies on petroleum and fossil fuel liquids. The University of Utah study of Asphalt Ridge bitumen No formal papers or reprints were prepared, therefore is predicated on the reactions of free radicals at temper- only titles of presentations and abstracts from these atures of 500 - 650 0 F., pressures of 1500 - 2000 psi, and presentations on papers relating to oil sands are pre- reaction times of 18 seconds. The object of the hydro- sented below. pyrolysis is to inhibit aromatic formation (and coking) and promote formation of naphthenic compounds by use "Separation of Asphaltenes and Resins from Alberta of small amounts of hydrogen (of hydrocarbon gases Bitumens and the ESR Properties of the Fractions", by containing hydrogen) in the absence of a catalyst, rather M. L. Selucky, University of Alberta, Edmonton, Alta., than catalytic hydroforming which is more expensive. Canada. The reaction consumes about 1 percent hydrogen and yields a product with an atomic H/C ratio of 1.5. No Abstract Available Always, some of the charged resid is not vaporized in the treatment. "The LETC Tar Sand In Situ Steam Recovery Field Experiment - A Progress Report", by R. V. Barbour, "Thermal Cracking of Bitumen with Mineral Interaction", Laramie Energy Technology Center, Laramie, Wyoming. by Leo Vorndran, D. W. Bennion, J. K. Donnelly, and R. G. Moore, University of Calgary, Calgary, Alberta, R. V. Barbour of LETC discussed The LETC Tar Sand In Canada. Situ Steam Recovery Field Experiment - Test TS-1S - that is also described on pages 36 and 37 of the LETC Studies on the thermal cracking of bitumen with mineral Annual Report for 1979. objectives of this test for interaction at the University of Calgary were discussed. enhanced recovery of bitumen by the use of steam are: Athabasca bitumen was treated for periods of 4 to 36 (a) to evaluate the tar sand resource, (b) determine the hours at temperatures of 300 to a maximum below characteristics of the specific site, (c) develop an effec- 500°C., in a 65 ml quartz tube. The tube was flushed tive in situ method, and (d) evaluate the environmental with helium at an atmospheric pressure and it was considerations. The steam injection was started April surrounded by a steel furnace. Interacting minerals (wet 23. On day 5, water appeared in the production wells, on or dry) such as quartz, chert, chalcedony, pyrite and day 27 steam broke into the production well, and on day clays to simulate in situ oxidative and thermal cracking 45 an oil-water emulsion (containing about 25 percent conditions were tested. The gas product was measured water) was produced. This product is now 500 bpd. and the liquid product was evaluated by vacuum distilla- Although there is some variation between wells, the tion, simulated distillation (chromatigraphic analysis)

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-11 then analyzed for asphaltenes, maltenes, resins and blocks surrounded by water in the fracture network. heavy oil. Imbibition was the production mechanism before steam injection. "Diesel Fuel Prepared from Athabasca Tar Sand", by J. Cooley, B. J. Fuhr, J. K. Liu, R. Schutte, and F. 0. Tan, A research program on fractured petrophysical models Syncrude Canada, Ltd., Edmonton, Alberta, Canada. predicted a good steam drive efficiency.

Diesel fuel is an important product from some 270,000 The pilot pattern (35 acres) has an irregular configu- tons of tar sand per day. The syncrude is hydrotreated in ration delineated by six old producing wells; only the a fluidized bed in the presence of a catalyst. Three injection well was specially drilled. A stable steam catalyts have been used, but a Shell Oil Co., catalyst was injection rate (160 T/Day) has been maintained since the best as it was only slightly deactivated with use (from 95 pilot start (October 1977). Oil production increased very percent to only 90 percent activity). Control of hydro- early and now oil steam ratio is about 0.2. A gas-oil gen is important. The diesel fuel has a pour point of less ratio evolution induced by an increasing CO content that -50° and a gravity of 37° API. The pilot unit was noted on several wells. To date, only a small operated at 260 - 410° but operated best at 370°C. On temperature evolution has been observed at one produc- the average, the diesel fuel contained 25 percent paraf- ing well. fins, 73 percent naçMhenes, and only 0.8 percent aroma- tics. Capacity of the commercial plant in 1980 is This test shows that the fracturation of a reservoir, at estimated at 200,000 bpd. least when it is intensive, does not prevent an efficient steam drive.

"M-6 Steam Drive Project. Preliminary Results of a STEAM DRIVE PAPERS PRESENTED Large Scale Field Test," (SPR 9452), Willem Van Der AT AIME MEETING Knapp, Maraven, S. A.

Several papers on steam drive were presented at the The M-6 steam drive is being carried out in a fully Annual Fall Technical Conference and Exhibition of the depleted, heavy oil reservoir of the Tia Juana field, Society of Petroleum Engineers of AIME held in Dallas, Bolivar Coast, Venezuela. The test comprises 151 wells, Texas in September. Abstracts of these papers are of which 19 are injectors, forming a semi-open hexagonal reprinted below. Papers may be ordered from Society of injection pattern. Petroleum Engineers, 6200 N, Central Expressway, Dallas, Texas 75206, 214-361-6601. Prior to full scale injection at the start of 1978, three pilot hexagons were advanced, one in November 1975 and "Simulation and Design of Steam Drive in A Vertical two in July and August 1976. Performance data of these Reservoir," (SPE 9451), J. M. Moughaniian, Chevron hexagons and of the whole project over a period of 4 and U.S.A., Inc; P. T. Woo, Chevron Oil Field Research Co; 3-1/2 years, respectively, indicate that there is a re- B. A. Dakessian and J. G. Fitzgerald, Chevron U.S.A., markable uniformity in the behaviour of this steam drive Inc. if compared to a small scale test in the northern part of the giant oil field carried out in 1961, at a distance of 12 A 3-dimensional simulation model was used to design km of the M-6 project. steam drive in a steeply dipping (53 0) heavy oil reservoir in California and to select the optimum well pattern The present test, though on a commercial scale, is still from 8 alternatives. Sensitivity runs were made to study considered of an exploratory nature and is meant to selected reservoir and operating parameters. The results advance the existing knowledge in thermal recovery. show that upstructure injection using a modified stag- For that reason, a large amount of data have been gered pattern results in increased recovery. Injection assembled on steam generation and distribution, fuel rate, steam quality, and formation dip are important consumption, petrophysical and geological studies, tracer parameters. Permeability normal to the bedding plane tests, etc. In evaluating the performance, use is made of has little effect. Grid orientation affects oil recovery empirical, analytical and numerical models. Partial efficiency but does not change the optimum well pattern studies, carried out in the context of the project, merit that was selected. special contributions to conferences like SPE. The purpose of this paper is to review the activities two "Steam Drive Pilot in a Fractured Carbonated Reservoir, interdisciplinary project teams are carrying out. Lacq Superieur Field," (SPE 9453), Bernard Sahuquet and Jerome J. Ferrier, Society Nationale Elf Aquitane (Pro- f/ill/fl duction).

In 1977, a steam drive pilot was initiated in the Lacq Superieur Field located in the southwest of France. The Particular aspects of this pilot test lie in the reservoir characteristics which is carbonated, dolomitized and high fractured in the pilot zone.

Since the beginning of the exploitation, in 1950, this zone was progressively swept by the strong underlying aquifer. Oil (22 degrees API) is now trapped in Matrix

3-12 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 CANADA-CITIES SERVICE TO PERFORM PILOT TEST IN OIL SANDS NEAR COLD LAKE Initially, overburden was used to build a dike between the river bank and the escarpment. Now over 80 percent Canada-Cities Service announced in October that it had of the overburden is used to build in-pit dikes in the farmed in on a 41,000 acre block of oil sands leases mined out areas to contain current and future tailings. owned by West Coast Petroleum, Ltd. The properties These structures are engineered to serve as dams and are about 300 feet high with surface slopes of 3.5 to I with are located in the Manatokan area of east-central impervious clay cores. Alberta, about 25 miles southwest of Esño Resources Canada's Cold Lake project. Twelve evaluation wells were drilled on the leases in the past five years. Outside The oil sand is removed by two bucketwheel excavators consultants have indicated that estimated oil-in-place is operating on two separate benches, one bench leading 4.2 billion barrels. The Sparky sands account for 2.6 the other. The wheels transfer material from the face billion barrels with an average pay thickness of approxi- to belt wagons and onto the face conveyors which in turn mately 50 feet. discharge the oil sand onto first one feed conveyor, then onto another feed conveyor and finally onto a truck Under the agreement, Canada-Cities Service will spend conveyor and into the extraction bins. During the more than $15 million on a pilot project on the site. A summer, the large machines may sink as much as five minimum of twelve wells will be drilled into the Sparky feet into the ground. However, during this time the oil sand in the face is minable by the bucketwheel without sands and a series of cyclic steam injection tests on at prior preparation. least one well will be performed. The company will have the option, to October 1, 1983 to elect to install a 25- well pilot project using cyclic steam stimulation The bucketwheels selected at Suncor weigh 1800 tons and travel on six large tracks at the rate of 26 feet per followed by steam flooding by November I, 1984. Cities Service will have earned 50 percent in the 20,000 acres minute. The wheels are electrically powered by two 270 surrounding the pilot after a minimum pilot test of 48 horsepower motors and produce an average output of 5,000 tons per hour. They are capable of slewing 3600 months. During this time, Cities-Service will receive while operating, and cut in a terrace form, approxi- 100 percent of the revenues from production with West mately 120 feet wide and 70 feet thick. Coast retaining a 10 percent gross overriding royalty. West Coast will also retain 100 percent interest in the other 21,000 acres. Two types of digging heads are used in the bucketwheels for the purpose of comparing normal bucket configura- tion with a straight bucket configuration. The top bench wheel has a 33-foot diameter digging head and is MINING AT SUNCOR DISCUSSED equipped with 10 buckets and ten precutters. each bucket having a capacity of I cubic yard. The bottom A review of Suncor's experience with bucketwheel bench excavator has the same diameter digging head but is equiped with 16 buckets with a 1 cubic yard capacity excavators was presented by J. Camp and M. Supple of and no precutters. Suncor at the International Mining Exhibition and Con- ference in Calgary in August. The paper, entitled "Oil Sands Mining by Bucketwheels" gives an overview of the Major repairs or component change outs for the wheels overburden removal and mining operations, with are projected on a five year basis with some of the emphasis on the bucketwheels plus support equipment. smaller repairs being projected 18 months in advance. Others are dealt with on an on-going basis. During the The thickness of the oil sands and the overburden varies early operations at Suncor, bucketwheel teeth, weighing considerably at Suncor, with the oil sand averaging about about 100 pounds and requiring 120 teeth per wheel, 130 feet in thickness, but varying from 0 to 235 feet. were wearing out in approximately four hours of digging The mining operation is begun by the removal of the time. Today, due to better metallurgy and deep blasting muskeg, after draining. The muskeg is removed with a of the oil sand in the summer, the average weight of a 15 cubic yard front-end loader and a fleet of ISO and bucketwheel tooth is approximately 50 pounds and the life expectancy is 200 to 350 hours in the summer and 170-ton trucks. Overburden is then removed by the use 175 hours in the winter. of a large bucketwheel of German manufacture. The forty-foot diameter digging head consists of fourteen 3.5 cubic yard buckets. The wheel has achieved a consistent When a wheel is down for maintenance or repair, a average of 7,500 tons per hour under normal conditions. system of overburden trucks hauling supplemental A smaller bucketwheel is substituted when the larger one material to the shuttle conveyor or a trench reclaimer is goes down for repair or maintenance. This wheel is used. The trench reclaimer is specially designed and was assisted by the front-end loader and trucks. Contractors completed in 1979. The reclaimer has a 28-foot dia- are used in the overburden area to remove muskeg and meter wheel equipped with 7 three cubic yard buckets. the more solid material. It reclaims truck-dumped material from a two hundred foot long trench at the rate of 4,000 tons per hour, depositing the material onto a 72-inch belt. Recently, Suncor acquired an H-241 Demag Shovel with a 19 cubic yard capacity bucket for use in overburden All conveyors at Suncor operate at a speed of 1080 feet removal. A test fleet of six smaller mechanical trucks also accompany the shovel. This has increased produc- per minute. Most of the conveyors are 60 inches wide, tion greatly in the overburden removal department. and all are electrically driven. One truck conveyor accomodates both mining systems. More conveyor sys- tems are in the planning state as well as are "walking" head stations.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-13 A great deal of support equipment is also used at Suncor. The project is aimed at intersecting the Middle Lakota Fines are screened out and loaded into 75 ton haulage Sandstone formation. The Middle Lakota exhibits reser- trucks to be dumped. Rubber-tired dozers are used to voir rock and fluid properties necessary for gravity clear up the backspill from the bucketwheels and large drainage. The sand has an average porosity of 18.9% and track-type tractors are needed to move conveyors and a horizontal permeability to air ranging from 45 to 3000 large tar sand blocks. Loaders, graders and scrapers are md. The pay zone averages 21 feet thick with porosity also used. Another fleet of equipment is used to control greater than 10 percent. Saturation averages 40-50 tailings sand and build dikes. This consists of a fleet of percent at 28° API gravity and viscosity is 19 cp at wide-track tractors, a large front-end loader equipped 70°F. Oil-in-place has been estimated at 773 bbl/ac-ft. with forks to carry pipe, and large side-boom tractors to construct the pipelines. Standard mining techniques were used to drive the 8 by 9-foot decline to intersect the Lakota Sand. For the Expansion of the Suncor plant should be completed first 550 feet the adit was driven through weathered during shut-down in May and June of 1981. At that time sections of the Fuson Shale. Instability of the shale capacity of the plant will be increased by approximately required timber supports, with steel beams used in place 17,000 more barrels per day of final product. of timber during wet periods. At 720 feet, the adit entered the competent Upper Lakota Sand and timbering II (I II If was replaced with roof bolting, using split sets. At 985 feet the adit intersected Well No. 48, which was drilled CONOCO PRESENTS DETAILS OF OIL MINING previously to verify oil saturation. At this point, a 22- PROJECT inch combination ventilation and escape shaft was drilled. A chamber was excavated and a steel production Details of the Conoco North Tisdale, Wyoming oil mining sump tank was installed. Figure I shows a cross-section project were presented in two papers at Society of the completed project. meetings and in an article in the August issue of the Western Oil Reporter. The papers, entitled, "Mining Specialized drilling equipment was used to drill six Technology Assists Oil Recovery From Wyoming Field' horizontal holes from the chamber. This drilling equip- and "Horizontal Drilling-A Tool for Improved Producti- ment was developed by Conoco Mining Research for use vity" were presented at the fall meetings of the Society in coal seam degasification in underground mines. The of Petroleum Engineers and the Society of Mining Engi- drilling system consists of three subsystems: the drilling neers, respectively. The project has combined aspects of rig, the drill bit guidance system, and the borehole both mining and petroleum engineering to increase pro- surveying instruments. Figure 2 shows the mobile duction from the North Tisdale field. The project drilling rig. The rig can drill 75 to 100 mm diameter involves driving an adit 985 feet into the side of Tisdale boreholes to depths of more than 600 m. It also features Mountain, located about 70 miles north of Casper, a patented closed-loop separation system for drill cut- Wyoming. At the end of the adit, a chamber is exca- tings and gas. Figure 3 shows the down-hole motor with vated and horizontal drainholes are drilled into the the patented drill bit guidance system which can deflect production area from the chamber. Oil is produced by the bit left, right, up, or down at a pre-selected rate. gravity drainage. The borehole surveying instruments measure the pitch, roll and azimuth of the borehole assembly and consist of a surveying probe and a microprocessor.

FIGURE 1 ACTUAL ADIT CROSS-SECTION

3-14 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 FIGURE 2 MOBILE DRILL SYSTEM

STEEL DRILL ROD COPPER BERYLLIUM COLLAR COPPER BERYLLIUM PIPE

STABILIZER ORIENTING SUB VALVE IIIIIIIIII CH:cK STABILIZING PAD DEFLECTION SHOE TRI-CONE ROLLER BIT

FIGURE 3 DOWN-HOLE MOTOR AND ACCESSORIES

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-15 In the North Tisdale project six horizontal drill holes Mining for petroleum will become more eco- were completed, using a 2-7/8 inch hole. Each hole had nomically attractive as oil prices continue to an initial 10-foot segment of 7-7/8 inch hole lined by a 5 rise. 1/2 inch pipe to serve as a conductor pipe during drilling and to provide a means of controlling flow during pro- duction. The average footage drilled during an 8-hour shift was 125 feet. Table I shows the holes with TWO TAR SAND MINING METHODS PATENTED corresponding lengths. Holes No. 21 3, and 5 were terminated when clay was encountered. Three major Two patents were recently issued on tar sands mining problems were encountered while drilling the holes. techniques. Patent Number 4,216,999 was issued to These were: Lester Hanson of Salt Lake City, Utah, and is entitled, "Machine for Mining Tar Sands Having Rearwardly Drill pipe failure due to the abrasive sand- Directed Exhaust Related to Conveyor Trough". U. S. stone. Failures were later reduced by the Patent Number 4,212,353 was issued to Texaco, Inc. and addition of a polymer in the fresh water mud is entitled, "Hydraulic Mining Technique for Recovering system. Bitumen from Tar Sand Deposit. Bit problems, also due to the abrasive sand- Patent Number 4,216,999 was issued on August 12, 1980 stone. A specially-designed diamond bit was and presents an improved mining machine suitable for eventually selected as a better performer mining tar sands and other soft materials such as soft than the carbide insert bit or the cone bit. coal, oil shale, etc. underground. Unique features of the equipment include a provision for a series of air jets for Fine-powered sand was carried through the ejecting tar sand cuttings, a variable platform control mud system causing damage to the pump. for controlling the orientation of the cutting face of the This problem was solved by installing a pro- machine, and the cutting face itself composed of a series gressing cavity pump with a flexible rubber of inter-meshed cutting heads. Figure 1 illustrates a stator. side view of the mining machine. The machine is driven by a pair of endless track drives which are driven by reversible, variable-speed electric TABLE I motors. The machine is therefore capable of advancing HOLE LENGTHS and retreating. The cutting face is adjustable and may be tilted so as to keep the face in vertical alignment //1 1498 It (456.6m) //4 1700 It (518.2M) 1/2 248 It ( 75.6m) //5 970 It (2953M) //3 420 It (128.0m) /16 1070 ft ( (326-IM)

After the oil drains into the sump, it is pumped to the surface through Well No. 48. A total of 34,312 barrels of oil and 12,544 barrels of water were produced from the project between August 3, 1979 and April I, 1980. The average first year production was 68 BOPD and 28 BWPD with an initial decline of 56 percent per year due to gas cap expansion. It is projected that production will level out at approximately 40 BOPD and decline at a rate of 6 percent per year. Final cost of the project was about $1,650,000. Conoco plans in the future to experiment with various stimulation treatments such as chemical wash treat- ments, a carbon dioxide flush, and possibly to experiment with steam injection. Reservoir repressuring with air injection in an effort to maximize recovery is also being considered. Although costs were high, it is hoped information gained may be used in other projects in the area. In summary, the North Tisdale project illustrated that: Mining for petroleum is a technically feasible concept in a shallow, low pressure sandstone reservoir; FIGURE 1 TAR SAND MINING MACHINE Improvements in horizontal drilling equip- ment will increase operational efficiency and reduce costs; and -

3-16 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 with the machine. Cutting tools are composed of tungsten carbide, with embedded synthetic diamonds, and are similar to the cutting head designed by General Electric and identified by the tradename STRATAPAX. Cut material from the mined face is collected by the scoop located at the bottom of the machine and impelled to the rear of the machine by air nozzles, through a trough located under the machine. The trough then empties onto a conveyor system. The author states that the machine can be used in both underground and surface applications, but that underground applications are pre- ferable because problems encountered when the tar sand freezes in the winter do not hinder the machine.

Patent Number 4,212,353 was issued on July 15, 1980 and presents an in situ hydraulic mining scheme. The techni- que consists of drilling a combination injection-produc- tion well to the bottom of the tar sand deposit and setting a casing to the top of the formation. A separate injection string is then run inside the casing to the top of the tar sand deposit. The injection string is equipped with nozzles new the bottom. A pump injects the aqueous hydraulic mining fluid down the injection string with sufficient pressure to form high velocity jets to dislodge bitumen and sand. This method is illustrated in Figure 2. Bitumen is then pumped to the surface by means of a jet pump. At the surface it is discharged into a settling tank.

This method is not unusual in itself and has been the subject of research in the past. The unique application of this hydraulic mining method is in the hydraulic mining fluid composition. The fluid is composed of hot water or steam and an amine having the following formula:

R1R2NR3

where R 1and R 2 are each hydrogen or a C1 to C6 and preferably a C 2 to C alkyl, linear or brancNed, and R FIGURE 2 is an alkyl, linear or granched, having from 3 to 20 an2 preferably 4 to 12, or R 3 is-R 4NF-I 2where R is a C 2 to HYDRAULIC MINING TECHNIQUE C 13 alkyl, linear or branched, and preferably) to 11, the sum of carbon atoms in R 1 , and R,, and R 3 being from 3 In a variation, a small amount of solvent may be added to 20 and preferably from 7 to l3 The temperature of to the hydraulic mining fluid. Monocyclic aromatic the aqueous hydraulic fluid may be from 180°F to solvents such as benzene toluene, or xylene, as well as 220°F. An example of a preferred amine within this formula is a C 10-C saturated hydrocarbons solvents having from four to 13 sec alkyl primary amine. This eight carbon atoms, naptha or other mixtures may be compound is commercially available from Texaco Petro- injected with the hot aqueous fluid. The presence of a chemical Sales under the designation of PT-9108. small amount of solvent increases the effectiveness of the process substantially. The preferred ratio of solvent Noncondensible gas such as nitrogen, carbon dioxide, to aqueous hydraulic mining fluid is from about 0.01 to methane, or ethane is injected into the formation simul- about 0.50. taneously with the hydraulic mining fluid. This main- tains a positive pressure which aids in supporting the II 1/ II II overburden and helps the pumping action. By keeping the cavity filled with gas, the jets of fluid travel further away from the injection string. Also, some gas is dissolved and/or entrained in the pulp of bitumen and aqueous fluid and this gas forms small bubbles during the surface separation to aid in separating bitumen and aqueous fluid. The volume ratio of noncondensible gas to aqueous hydraulic mining fluid may be from about 1/10 to about 10.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-17

THREE PAPERS PRESENTED ON SHELL PEACE TABLE I RIVER PROJECT PEACE RIVER PROJECT BASIC RESERVOIR DATA Three reports have been published recently on the Shell Peace River pilot steam injection recovery project in Definition Value Units northern Alberta. (See Cameron Synthetic Fuels Report, March 1980). At the Seminar on Non-Conventional Oil Total zone thickness 27 M Technology in Calgary, Alberta in May, a paper was Porosity (wgt. average) 28 % B.V. presented on the status of the project by P. Kitzen of Shell Canada Resources Limited. Two papers were Bitumen saturation presented at the 55th Fall Technical Conference of the (wgt.average) 77 %B.V. Society of Petroleum Engineers in Dallas, Texas in Original formation pressure, 3660 KPA September. These papers were entitled, "Thermal referenced to +53 M Sub-Sea Alterations of Asphaltenes in Peace River Tars" by Waxman, Deeds, and Closrnann, and "Peace River Tar Original formation temperature 17 Flow Experiments Under In Situ Conditions" by the same Bitumen gravity 9 °API authors, all of the Shell Development Company. Permeability The Peace River Project is a joint project between the (absolute to brine) 440 MD Alberta Oil Sands Technology and Research Authority, Amoco Canada Petroleum Company Ltd., Shell Explorer The current pilot consists of seven fully developed Limited and Shell Canada Resources Ltd. Shell Canada seven-spot patterns on seven-acre spacing which pro- Resources Ltd. is the operator. The project is located vides for appropriate symmetry for fluid flow and for approximately 30 kilometers northeast of Peace River. more producers than injectors. The seven acre spacing is Table I shows the reservoir data for the 27 meter thick the smallest spacing consistent with overall economics. tar sand zone. The zone may be further divided into an Figure I illustrates the pilot configuration along with the upper rich tar zone and a basal 3 meter water zone. central steam generation/product handling plant. Capa- Laboratory research plus field tests led to the selection cities of the plant are given in Table 3. The field piping, of a pressure pulse steam drive process for oil recovery. satellites, and the central plant segregate production to Investigations also showed that an ultimate recovery of permit independent measurement of production from the at least 50 percent of the original oil-in-place was central six production wells. There is also a provision to indicated. Table 2 shows the results from previous tests. obtain individual well rates from each of the 24 produc- The current pilot test will evaluate the technical and tion wells once every six days. A variety of completion economic feasibility of a full-scale steam drive project. techniques was used to drill the twenty-four wells. Table 4 gives the operating policy for the pilot which consists of seven major events.

TABLE 2 PEACE RIVER PRIOR FIELD TESTS

. Overall objective: Provide basic data and knowledge with respect to alternate recovery mechanisms.

1963-64 1965 1065-66 1973-74 • Process Soak Combustion Drag/Drive Soak • Wells Injection /Production Observation • Results injected Steam-MB 78 137 121.7 Air-MM SC F 30 Recovered-Bitumen MB 8.5 0.75 3.5 29.9 OSR (B/B) 0.11 0.03 0.25 AOR (SCF/BBL) 40,000 • Basic Conclusion By comparison with other field pilots and laboratory information interpretation was that a steam drive mechanism offered the greatest chance of economic success.

3-18 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 4

— SATELUTES PEACE RIVER PROJECT - OPERATING SCHEDULE OtFA" hO NJECTIOFI W 1. Cold Productivity Tests - Short Term. 2. Steam Soak all Production Wells. 3. Steam Drive - Promote Heat Communication. TEkERATURE7 - - P .FEEIRE 4. Back Pressure Production Wells - After Heat Break- through. I 010-A 5.- Controlled Pressure Steam Drive - Until Steam Break- 520 3t SRI - Al through. 6. One or More Pressure Cycles - Pressure Build-Up '27 R 123• / 35 _•.. -"- - 0137 *. 0D - Blowdown COlE •;_' - / - I 7. Final Stage - Gravity Drainage - No Steam h 't_ ICOPE131 I - Heat Scavenging I,, / IOU 1145 - Stripper Operations 77 Expected life approximately 9 year. 17 •1SI IcORE I I CO'E - I. I I P NT PA CPSD - Continuous steam injection at more or less ,A constant rates and with reasonably balanced with- FE ACE RIVEE IN TI drawals from the production wells. 11101 PROJECT o 55 000 ISO 00CR FIELOPATTEEPA The pilot performance will be monitored and evaluated by means of a computerized data collection system and a FIGURE I numerical model. The on-site computer is linked with PEACE RIVER IN SITU PILOT PROJECT Shell's Calgary facilities. These must run for a minimum of five years to generate enough data for a decision on FIELD PATTERN commercial production. Therefore, a commercial start- up date is tentatively set for the early 1990's. Construc- tion costs of the pilot test were approximately $70 million (Cdn.) with operating costs expected to be approximately $10 million.

In 1973-74, Shell Canada Limited and Shell Explorer Limited conducted a steam injectivity and productivity test in the Peace River Bullhead sand. Please refer to Table 2 for the results of this test. The papers entitled "Thermal Alterations of Asphaltenes in Peace River Tars" and 'Peace River Tar Flow Experiments Under In Situ Conditions," present results of laboratory work undertaken in order to obtain mobility data for Peace TABLE 3 River tar in its parent core material at temperatures and stress conditions simulating reservoir zones downstream CAPACITIES OF THE of a steam condensation front. Both asphaltenes and PEACE RIVER PROJECT maltenes were analyzed for quantity and degree of Source Water - 3975 M 3/D (25,000 BID) thermal alteration. A series of flow experiments were then conducted and are described in the second paper. Steam Generation - 2860 M 3/D (18,000 BID) - (80% quality) Conclusions based on solubility and thermochemical tests Water equivalent @ 16,200 of asphaltenes showed that: K PA (2350 PSI) • Based on simple solubility tests, asphaltenes Bitumen Handling - 550 M 3ID (3,500 BID) contained in tars produced from the 1973-74 Peace River field test were thermally altered Produced Water - 2460 M 3/D (15,500 B/D) with respect to unheated Peace River tars. Produced Gas - 23 x 10 M 3ID (I MMCFID) The ability of these altered asphaltenes to interact with organic solvents and/or their maltenes is reduced.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-19 The increased degree of asphaltene alteration TABLE 5 is directly indicated by increases in C/H and EXPERIMENTAL CONDITIONS C/S atomic ratios of the asphaltenes them- FOR FLOW RUNS selves. 380°F (193°C-198°C) Laboratory heating experiments confirmed Temperature that the above changes in asphaltenes proper- In Situ Stress 1,100 psig (7,584 CPa) ties were the result of thermochemical con- Overburden Pressure 1,500 psig (10,342 KPa) versions. Back Pressure on Fluids 400 psig (2,758 lCPa) The changes due to thermal alteration of Peace River tar suggest a less solvated asphaltene structure more favorable for flow. f/il f/Il A possible exception is the production of insoluble products which takes place during SOLVENT EXTRACTION STUDY RESULTS extended alteration. PRESENTED BY NATIONAL RESEARCH COUNCIL Flow experiments were conducted with Peace River "A Study of Some Factors Affecting Solvent Losses in cores preserved in their natural state as much as the Solvent Extraction-Spherical Agglomeration of Oil possible, simulating conditions such as they were thought Sands," is the title of a paper presented at the 63rd to occur in the hot zone during the field test. Table 5 Canadian Chemical Conference in Ottawa, Ontario in summarizes these conditions. Two approaches were June by B. D. Sparks and F. W. Meadus of the National employed in the flow studies: (1) two phase (tar/brine) Research Council of Canada. The paper looks at solvent flow in single pass-through, steady state permeability extraction as a substitute for the hot water separation determinations and (2) one phase (tar) continuous recycle process, which has both environmental and operating flow. Conclusions gained from fifteen core tests problems associated with it. showed: Although solvent extraction processes are attractive, • Tar and brine mobilities in Peace River core because of the lack of a tailings disposal problem which material continuously decline in single pass is encountered in the hot water process, the overall flow runs when thermally unaltered tar is process efficiency can be quite low because of substan- used. Steady state permeabilities were not tial entrapment of residua1 solvent in the sand bed. The obtained. problem is aggravated if the feed is high in clay. Solvent recovery can be improved by use of spherical agglomera- • In recycle flow runs with unaltered tars, tar tion after the solvent extraction of the bitumen com- mobilities in Peace River cores generally ponent. Spherical agglomeration is a technique in which decrease to very low, but steady state values. fine particles in liquid suspension can be formed into large, dense agglomerates of considerable integrity by • Movement of inorganic fines can sometimes be a significant factor in permeability im- preferential wetting with a second immiscible liquid, under appropriate agitation conditions. Because of com- pairment during recycle flow. paratively high solvent costs, the most important factor in this application of spherical agglomeration is the • Stable and reasonably high tar mobilities are amount of residual solvent remaining with the agglomer- obtained with thermally altered tar or a tar ated sand. These solvent losses are discussed by the mixture containing small amounts of therm- ally altered tar in a single pass and recycle author. flow runs. These results are consistent with Residual solvent can remain associated with the agglom- the unimpaired tar production evident in the 1973-74 Peace River field test. erates in several ways: As an external film on the surface of the • Appreciable excesses of soluble asphaltenes, from 1.5 to ID percent by weight with refer- agglomerates, ence to the input tar, accumulate in the tar As an entrapped bulk phase in intra- or inter- phase in the sands during flow of tar. particle voids, • "Rebound" effects are generally observed in As an oil-in-water emulsion. these flow studies, and a flow mechanism involving the presence of associated asphal- The effectiveness of separation is a function of the fluid tene micelle structures in the flowing tar properties and the pore geometry of the draining phase can explain the observed behavior. agglomerate bed. For spherical particles, the agglome- Direct evidence for such structures is rate diameter controls the inter-agglomerate pore size limited, particularly at temperatures as high and, hence, the degree of drainage. The result of this as 385°F. drainage phenomenon is that there is a rapid increase in total residual solvent as agglomerates become smaller. For agglomerates with diameters greater than I cm., the amount of surface solvent remains approximately cons-

3-20 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 tant. Table I illustrates an estimate of the actual In the investigation of particle size as a factor in the oil amount of non-drainable liquid for both kerosene and sands separation process, it was confirmed that the naphtha, with mean agglomerate diameters of about 1 agglomeration process becomes more effective as the cm. Comparison of the non-surface residual solvent on a fines content is increased and, at the other end of the volumetric basis shows no real difference between kero- scale, a minimum requirement for agglomerate growth sene and naphtha. However, naphtha does appear to give to occur is 10-12 percent fines content. Figure I better drainage, possibly because of its lower viscosity. illustrates the effect of fines content on agglomerate composition. At any given moisture content it can be Entrapped solvent in the agglomerate voids is affected seen that the compaction of the agglomerates, as by the compaction conditions in which there is a ten- measured by the mineral content, increases as the dency for the solvent to be selectively expelled. A amount of fines increases. Above about 40 percent variety of agglomerate compositions for different treat- fines, the agglomerate void volume begins to increase ment conditions were examined. Those treatments once more, but the expected increase in residual solvent which gave the highest degree of agglomerate compac- occurs less rapidly because the average pore diameter tion also yielded the lowest values for residual solvent remains low, thus maintaining the high capillary pressure content. The major factors which affected agglomerate condusive to solvent elimination. compaction and, therefore, solvent retention, were as follows: Investigation of the influence of moisture content on an agglomerate revealed that as the moisture content • Method of agglomerate formation (layering increases, there is an initial reduction in solvent level as or coalescence), the water progressively fills the internal pore volume. For coarser feed, adding water beyond a certain point • Particle size distribution of the solid, can cause an increase in solvent content, while finer feeds do not exhibit this effect. This is possible due to • Moisture content of the agglomerates, the fact that there is a breakdown in the agglomeration mechanism under the conditions of low fines and high • Water wettability of the mineral surface, water content, thus leading to an increase in residual solvent levels. • Residence time in agglomerator, and In studying the clay fraction of the oil sands, it was • External compaction of agglomerates as a found that the clay promotes retention of solvent by the result of agglomerator configuration and mineral phase through the stabilization of oil-in-water Size. emulsions and by increasing the probability of oil-phase occulsion. A number of wetting agents were tested in an The layering mechanism was shown to be the most attempt to alleviate the problem with Na 3PO4 shown to effective in minimizing solvent retention. Agglomera- be the most effective. Tests of the solution showed a tion of this type is normally associated with rotating significant decrease in the residual solvent level for the pans or drums. surfactant system, particularly at higher moisture contents.

TABLE I AGGLOMERATE COMPOSITION DATA: NAPHTHA AND KEROSENE

SOLVENT VISCOSITY DENSITY AGGLOMERATE COMPOSITION (wt. % dry basis) cp @ 20°C g/cc @ 24°C WATER TOTAL ORGANIC SURFACE ORGANIC MEAN AGG. DIA. (cm)

KEROSENE 2.23 0.8333 11.4 • 0.5 3.7 • 0.6 1.1. 0.2 0.96+ 0.18 (2.7) 0.7 and 1.5*

NAPHTHA 0.59 0.7195 12.6. 0.7 2.6 + 0.6 0.5 + 0.2 1.04 + 0.14 (2.5) 0.3 and 0.7 NOTE: Organic includes both bitumen and solvent. The figure in brackets represents actual non-surface solvent, corrected for density difference.

•95 percent confidence limits. I. Comparison of residual solvent levels for kerosene and naphtha.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-21 rIuuMc 1 EFFECT OF FINES ON AGGLOMERATE COMPOSITION

Residence time, charge size, speed of rotation and type recovery of at least 98 percent, with a bitumen recovery of equipment were factors acting on the agglomerate of 95-96 percent in a commercial size plant. that were also studied. In the case of residence time, it was shown that longer residence time resulted in greater In conclusion, the author states that it appears that the compaction. However, because of economic considera- spherical agglomeration process has the potential of tions in the plant, little practical use can be made of achieving an effective separation of bitumen from oil extended residence times. The most significant of the sands with comparatively low solvent losses. Since other factors studied, appeared to be the height of the spherical agglomeration is particularly compatible with agglomerate bed, governed by equipment size and high fines feed, another alternative would be to combine loading. A significant decrease in agglomerate porosity, the hot water and solvent extraction processes to pro- with corresponding solvent elimination, was shown as the duce an overall more effective system. Reject material drum diameter increased. from the hot water process could be treated by the spherical agglomeration process to recover the con- In an attempt to compare the effectiveness of the currently rejected bitumen. Two results of this combi- agglomeration system with a conventional solid-liquid nation would be: separation process, such as pressure filtration, it was found that moisture content initially remained constant A large part of the sludge forming compo- while the solvent level consistently decreased. These nents of the oil sands would be eliminated results confirmed that an organic phase can, in fact, be and would not require impoundment and, selectively eliminated from a water-wet, compressible, particulate bed. However, the results with this techni- Bitumen recoveries would be slightly higher que gave residual solvent levels at least twice as high as for the combined process. the best achieved by agglomeration separation. I/fl II II An attempt was also made to predict the behavior of the agglomeration system by a regression analysis. The effect of bed depth, residence time and moisture content on agglomerate composition were considered for a medium grade of oil sands (8 percent bitumen), contain- ing 17 percent -325 mesh material and using kerosene as the solvent. The projection of these results to a larger scale of operation is illustrated in Figure 2. These projections indicate the possibility of achieving a solvent

3-22 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Me 91.2 +1.8 InH-13(I/R)-76(W/M) - - -

—J 4 W 2

4n - -

InN. FIGURE 2 SCALE-UP PREDICTION OF PROCESS PERFORMANCE

GEOTECHNICAL FRONTIERS IN OIL SAND MINING stone in that they are heavily preloaded, with the result EXAMINED that high horizontal stresses occur within the preconsoli- dated deposits. This causes stress relief while unloading, E. W. Brooker presented a paper entitled, "Geotechnical compounded by the presence of gas. The result is Frontiers in Oil Sand Mining" to the International Mining exfoliation slabbing. Stability has also been found to Exhibition and Conference '80 in Calgary, Alberta in decrease with depth due to the unstability of the Clear- August. The paper summarizes the history of geotech- water, Grand Rapids and Wabasca formations. These nical work in the Athabasca oil sands and identifies a findings impact directly on the selection of the correct number of problems to be addressed in the future. mining equipment and are seen as real challenges for the use of both the bucketwheel excavator and the dragline. The author states that all of the knowledge of geotechni- Further details of oil sand slope failure can be found in cal processes in the oil sand industry has been developed the September issue of the Cameron Synthetic Fuels within the past 20 years. This knowledge has been Report. developed mostly from an observational approach. This approach involves estimation of performance during the Both in situ and mine-assisted techniques of producing initial design phase and observation during construction, oil sand require an effective fracture system to increase with further adjustments being made during operation. permeability and allow pumping of the reduced viscosity In essence, oil sand geotechnical engineering has been an bitumen. To understand fracturing, the method of crack iterative process. The development of a specific project propagation must be well understood. In situ methods is also dependent on detailed site-specific information also require an understanding of high pressures when such as detailed geology, geohydraulic conditions, overburden depths range from 1000 to 2000 feet. It has engineering mechanics and statics. been predicted that oil recovery using such techniques will be only 15 to 17 percent of the total potential Today, information with respect to the physical and reserve because of the intricate lithology and naturally index properties of oil sands is well documented with low porosity of the McMurray formation. It is antici- respect to surface mining of oil sands. However, the pated that fluid flow will be more effective horizontally knowledge available is not yet complete with respect to than vertically due to the complex deltaic geometry of in situ and mine-assisted processes. More knowledge interbedded silts and clays surrounding oil bearing sand needs to be developed on oil sand deposits under high lenses. In situ methods will require the combination of stress levels, presures and heat as well as during changes geomechanical and geothermal analyses to predict flows in these environments. of a variable viscosity fluid.

Studies have shown that the massive oil sands in surface Another subject of concern is the permeability of the mining possess some of the characteristics of soft sand- McMurray formation. The McMurray formation is

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-23 intensely dense, low porosity, low permeability material. If the tunnels are driven in the competent Devonian Two types of permeability exist within it. These are the limestone, support conditions will be much better but mass permeability of the material and the discreet problems may arise due to the irregular surface topo- permeability of the intact bodies bounded by fractures. graphy of the Devonian, which can deviate substantially It is a possibility that fracturing, although enhancing over short distances. Karst features may also be mass permeability, will not contribute to extraction of encountered. This will necessitate a sophisticated oil from the chunks of material left between the frac- system of advance probing. One other method of mining tures. This is due to the fact that the intact natural has been examined which utilizes a caving system for permeability of the chunks may be low. recovering the oil sand from the McMurray formation by using draw points in the Devonian. Disadvantages to this Mine-assisted systems have some precedence elsewhere system include transporting large volumes of material to in the world, particularly in the Yarega field in the the surface and the resulting tailings disposal problems Soviet Union. However, several problems are still which accompany it. unanswered and some problems of a geotechnical nature are site-specific to the Athabasca deposit. This includes The author comments that regardless of the system used the presence of an oil barren water sand between the in situ methods, it is obvious that a large volume of Devonian and McMurray formations which is under arte- steam will be required. If solid or liquid hydrocarbons sian pressure and a gas drive or head. One possible are used for steam generation, the energy balance be- solution for mining through these areas is to use a comes questionable. Because uranium resources are freezing technique developed for use in the Saskatche- available in northern Alberta and Saskatchewan, it is wan potash operations. possible that other use of small-scale atomic powered steam generation units could be used effectively on a Another problem is that there is limited experience in large lease area for continuous in situ operations. Figure driving tunnels in oil sand and the resulting problems of I illustrates such a concept. New atomic power genera- creep, stress relief, and geostatic pressures on linings. tion capabilities are in a state of evolution, and it is In addition, information available to date shows that due conceivable that some of these new atomic energy to solution collapse of the Methy formation underlying systems could be implemented for steam generation. the Devonian limestone, a body of oil ladden McMurray formation may be in vertical contact with a water- ft f/f/fl saturated, gas driven, oil barren sand deposit.

mAN TUASINI

(In— Pnn OSDb.U..,

GENENATON

—

S..-. '0......

_____ ------r-z.-----'N,,— ------&

FIGURE I NUCLEAR APPLICATION TO IN SITU DEVELOPMENT

3-24 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 GOVERNMENT

CANADIAN GOVERNMENT IMPASSE SHELVES OIL minated for conventional oil and gas projects. SANDS PLANTS Qualifying expenditures on integrated oil sand projects, enhanced oil recovery projects On October 28, 1980, after oil pricing talks between the and heavy crude oil upgrading facilities will Canadian Federal government and the Province of be retained at a depletion allowance of 33 Alberta had broken down, the Federal government 1/3, up to a ceiling of 25 percent of resource announced a unilateral national energy program together income. with the new Canadian budget. The budget and energy policy contained pricing, tax, and federal payment pro- Incentives--Approved capital expenditures visions for achieving the goals of increased energy for integrated oil sands projects, tertiary security and self-sufficiency, a fairer system of sharing recovery projects, and heavy crude oil up- oil and gas revenues between the Canadian Federal graders will receive a payment of: government and the provinces, and increased Canadian ownership and control of the petroleum industry. Key (I) 10 percent if the company is at least 50 points of the energy plan are as follows: percent Canadian-owned and controlled for approved costs incurred in 1982 and Oil Pricing--The wellhead price for a barrel thereafter, or of oil, now $16.75/bbl will rise by $1.00 every six months until the end of 1983, then by (2) 20 percent if the company is at least 75 $2.25 every six months through 1986, and by percent Canadian-owned and controlled $3.50 every six months thereafter until the for approved costs incurred in 1981 and average of domestic and imported oil prices thereafter. Additional payments will equals 85 percent of the world crude oil also be made for Canadian-owned price. Oil from tar sands will be priced at companies that are doing exploration $38/bbl or world price, whichever is less for work on Canada Lands. all new oil produced. Tar sands oil produced from "old" sources will receive the conven- • Canada Lands--New legislation is proposed tional domestic oil price of $16.75/bbl. For for governing activity on lands under crude oil produced through approved tertiary Canadian Federal jurisdiction including enhanced recovery methods, the Government stiffer work requirements and a reserved 25 of Canada will pay a tertiary supplement to percent interest to the Crown plus Canadian qualifying producers. An incentive price will ownership requirements. also be given to facilities that upgrade heavy crude oil and a reference price for specified • Refineries--A plan to improve the efficiency frontier oil will be established later after of crude oil through reduction of heavy oil acquisition of more detailed cost data. In production and a program for upgrading addition, the Petroleum Compensation heavy oil. Charge, the so-called "Syncrude Levy" which is a single weighted average cost of imported • Exports--A plan to share oil export tax reve- oil and the various streams of domestic oil nues 50 percent with the provinces of Alberta will be increased by $2.50/bbl for the next .and Saskatchewan, to be reviewed in 1985. three years. The total increase in wellhead price for the next three years will then be • Canadianization--A: plan was put forth to $4.50/bbl per year. increase Canadian ownership of the oil and gas industry by government acquisition of Gas Pricing—A new tax of 530 per 1,000 several large foreign-owned oil and gas pro- cubic feet on natural gas became effective ducers through purchase by Petro-Canada. It November I in Canada and on February 1 for will be financed through special charges on exports. This will be followed by a further oil and gas consumption in Canada. A target increase of IS cents each in 1981 and 45 of 50 percent Canadian ownership of oil and cents in 1982 and 1983. gas production was also included. In addition, tar sands projects will be approved only if New Taxes--A new Federal tax of 8 percent "acceptable progress" toward Canadian on net earnings from oil and gas production ownership has been made. will be imposed to help finance incentives to be provided for exploration. Several other programs were addressed in the new energy policy including energy conservation, efforts to Depletion Allowance--The current depletion help developing countries, and increased funding of re- allowance equal to one-third of oil and gas search and development projects. exploration, development and certain capital expenditures in oil sands plants, will be eli-

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-25 On October 31, 1980, in a retaliatory move, Premier Federal Energy Minister say these projects have become Peter Lougheed presented Alberta's response to the the key to achieving adequate fuel supplies. From the unilateral Canadian Federal energy policy. Key points in Province's perspective and the petroleum industry's Alberta's response are: viewpoint, the oil pricing and oil sands plant issues are linked and should be settled as one question, since money Alberta's oil production will be reduced with from conventional oil will be used to finance the oil adequate notice in three-month reductions to sands plants. In the case of the existing oil sands plants, about 85 percent of its capacity. This will Suncor has been hit hard because it will receive only mean a total of 180,000 bbl/day in the nine- conventional oil prices from its current output and world month period. The first cut of 60,000 bbl/day price for oil from its expansion. The company has stated will occur on March I, 1981. This cut will be that the conventional oil price of $16.75 is close to 1980 made under two conditions: operating cost and will therefore make the plant a marginal operation. Syncrude, on the other hand, will (I) If any serious shortage occurs, Alberta continue to receive world prices or $38/bbl. Suncor has will suspend the cut. The cut will be complained that it will be unable to compete on an equal made for the purpose of making the basis with Syncrude for such things as supplies, staff and Canadian Federal government purchase housing. In November, Suncor officially asked the supplies elsewhere at world oil prices, Federal government to reconsider its decision to elimi- and nate the world price compensation for its synthetic crude. (2) The cut will be suspended if negotia- tions between Alberta and the Federal Speculation about the role of Petro-Canada in the acqui- government are resumed and a new sition of one or more of the multi-national oil companies agreement is made. has been frequent. Preliminary indications are that the multi-nationals will refuse to sell. If this happens, In regard to the new oil sands plants, the federal sources say that a nationalization task force, plants will be put on hold until a re-assess- already in place and reporting directly to the cabinet, ment of royalty arrangements can be made. will be asked to find ways of forcing at least one company to sell. Candidates that are considered prime In regard to the natural gas export tax, targets are Petrofina Canada, Inc., 1W Canada, Inc., and Alberta will challenge the matter in court, Suncor, Inc. Suncor, because of its weakened condition and after having the value of iis prime asset cut virtually in half, is considered an easy target. Petro-Canada has Alberta will enter into a campaign along with already made one offer for Petrofina and has been anyone who wishes to support them to con- turned down. vince the Federal government that they have made a mistake and that they should re- U.S. reaction to the new energy policy has been mixed. adjust their energy policies. The U.S. State Department has asked for a clarification of elements of the program which it says are ambiguous, The new energy policy precipitated a storm of contro- discriminatory, and appear to conflict with international versy in Canada with the multi-national oil companies trade and investment agreements. Members of the U.S. re-assessing their investments and many companies oil industry have expressed delight in the fact that many talking of moving south of the border into the more of the Canadian oil companies are moving equipment and hospitable environment in the United States. On services into the U.S. to escape the Canadian policy. It October 31, Prime Minister Trudeau said he was willing is hoped that availability of drilling equipment and to reopen negotiations to settle the energy impasse services will contribute to a boom in U.S. exploration between the two governments. Canadian federal Energy and development. Although the U.S. government is Minister Marc Lalonde let it be known that there night taking a "wait and see" attitude, officials of the state be some leeway to negotiate a new pricing arrangement and energy departments have agreed to meet with their with Alberta on new oil sands production. Then, without Canadian counterparts in December after preliminary waiting for a resumption of negotiations on pricing with meetings in early November. Alberta, the Trudeau government officially seized con- trol of oil and natural gas prices at the wellhead on On November 15, in a Calgary Herald interview, Federal November 13, implementing the new energy program. Energy Minister Marc Lalonde appeared to be wavering After invoking the federal price-fixing power, Energy somewhat in his stance. Major points from the interview Minister Marc Lalonde stated that he had talked with are as follows: Alberta Energy Minister Mery Leitch and hoped that negotiations would resume in the near future. He also Alberta is free to provide its own exploration reiterated the Federal government's hope that Alberta incentives in the province if it considers the might be willing to negotiate a separate agreement on federal policy to be too harsh, development of new oil sands plants. Alberta responded to this request by stating on November 14, that all new Confirmation was made of the existence of a oil sand plants will be shelved until Alberta has an committee to be formed to assist the Crown energy price pact with Ottawa. corporation Petro-Canada in its bid to take over Canadian units of one or two multi- Alberta's oil sands plants are a major focus of the nationals, political controversy as both the Prime Minister and

3-26 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 • Lalonde is prepared to review and perhaps Canada's best interests to preclude the oil sands option, modify certain provisions of the new policy and we feel that won't happen. A workable solution will such as rules regarding exploration grants and be found. the rights of Petro-Canada to take 25 per- cent of frontier oil and gas properties, II 1/ II II • The oil pricing schedule and new energy taxes EROS PROCEDURES REVIEWED are fixed until the next budget but not "cast in stone," "Overviews of Oil Sands Development and Its Role in Meeting Canada's Energy Needs," is the title of a paper • He is not afraid of U.S. retaliation to Cana- presented at the International Mining Exhibition and dianization, Conference 130 in Calgary, Alberta in August by Brahm D. Prasad and Harry 0. Lillo of the Energy Resources • He prefers that the court challenge to the Conservation Board. The paper is an overview of natural gas tax go directly to the Supreme methods used by the ERCB for evaluation of Canada's oil Court of Canada for a decision, sands reserves, approvals of both experimental and commerical oil sands operations and forecasts of synthe- • In the new negotiations, oil sands plants will tic crude production. be of top priority, At the ERCB, the in-place volumes of crude bitumen are • He accused Suncor of trying to play a "double determined in Alberta by using a uniform square area game" in protesting the reduction in price for (building block approach). In this procedure, the in-place its oil sands production, claiming the bitumen volume of each square block of one-quarter company was never promised the world price township or 23 km is evaluated. In evaluating the indefinitely. mineable bitumen reserves, a minimum bitumen satura- tion of 5 mass percent and a minimum oil sands zone Comment thickness of 1.5 m, is used. The ERCB is presently reviewing this criteria because the loss of ore must be The Canadian situation is volatile to say the least. It minimized by the use of as thin a minimum thickness isn't possible at this time to make firm predictions of cut-off as is practical with the equipment selected, what effect the situation will have on the long-term necessitating a review of economic extraction efficien- outlook for an Alberta Oil Sands industry, but if no cies and mining methods selected by theproject. A further progress is made in negotiations between Ottawa variety of economic criteria have been used by proposed and Alberta, the following would appear to be the result: and operating commercial projects. These are summar- ized in Table I. Any consideration by Alberta of the Alsands project as well as all other proposed surface Starting in 1974, the ERCB developed a modified form of mining projects has been curtailed. The a well-established method of determining economically Suncor and Syncrude plants could thus be the mineable reserves, known as the Break-Even Stripping only surface oil sands projects ever in Ratio. The method was subsequently revised in 1975 and Alberta. 1979 to become known as the ERCB's Economic Stripping Ratio (ESR). Figure 1 shows the relationship between Continued operation of the Suncor plant is the ESR and the average plant feed bitumen saturations. even in jeopardy since access to world prices Using this criteria, the potentially mineable reserves for for its product has been cut off. the surface mineable portions of the Athabasca-Wabis- kaw-McMurray oilsands Ø9osits have been calculated Further development of in situ oil sands tech- by the ERCB as 12.4 x 10 m of crude bitumen. Because nology is also in danger of being severely of reserve withdrawals for environmental corridors, curtailed, since most of these projects are pipeline corridors, surface facility placement and being operated by units of multi-nationals. isolated pockets of reserves, the ERCB has estmted the established bitumen reserves to be 5.3 x 10 m or Thus, as things stood in mid-November, the future of oil approximately 43 percent of the potentially mineable sands looks very bleak. This whole situation will no reserves. doubt be resolved in the months--possibly years--ahead. We only hope we won't be in a position then of looking No established reserves have yet been assigned by the back to find that the Suncor project--an otherwise viable ERCB to deposits from which bitumen would be pioneer venture--was permanently closed down solely recovered by in situ techniques. A number of problems because of the politics of the day. What a shame that have prevented the determination of established would be. At a time when other governments are reserves. These include: encouraging synthetic fuels development, even providing financial incentives, Suncor would have been severely Difficulty of establishing a recovery level, penalized for being first on the block and, of course, for because no commercial projects yet exist, belonging to a company on the wrong side of the border. The potential for a repeat of that kind of treatment may Suitability of different in situ recovery tech- discourage a lot of projects in the future. That's the real niques when applied to various reservoir danger in the current situation. However the current types, and impasse is resolved, we certainly feel that it is not in Variability in the actual reservoirs.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-27 TABLE I MINIMUM BITUMEN SATURATION AND MINIMUM THICKNESS CUT-OFF Minimum Minimum Saturation Thickness Cut-Oft Mining Cut-Off Applicant (Mass Percent) System (m)

Suncor S Bucket Wheel None Excavator (BWE) Syncrude 6 Dragline (D/L) Under study Petrofina 6 BWE 6* Home 6 BWE 1.5* Alsands *4 D/L 45 * Minimum one half hour reject production is necessary Alsands based cut-off on an economic computer model utilizing 0.25 in intervals. Under the present Oil and Gas Conservation Act, two types of oil sands operations are provided for: commer- cial and experimental. The schemes operating under experimental status are afforded special tax advantages and reduced royalties by the Canadian Federal and S__ _ Provincial governments. Although the distinction bet- ween a major commercial operation and a small, truly experimental scheme is usually obvious, the distinction may become blurred as the experimental operations of today begin scaling-up to prototype or semi-commercial E operations. A method of distinction will have to be agreed upon in the next few years by government, industry and the ERCB. Once it has been determined that the proposal falls into the experimental category, a full review is undertaken • ma.. by ERCB staff, and the application is also referred to the Department of Environment for review. To date, no experimental scheme applications have been advertised nor have any gone to public hearing, although the ERCB does make the experimental scheme applications public after approval is granted. Currently, all information received subsequent to the application is held confiden- rarra tial until five years after commercial operations have commenced. This policy is undergoing review and it is likely that more information may be made public in the future. In the review of a commercial scheme application, the ERCB will call for a public hearing upon receipt of the application to provide it with necessary information to make an appropriate decision. A detailed evaluation is FIGURE I then made of the application. This review includes the ECONOMIC STRIPPING RATIO following areas of major concern:

. Surface Mining Applications: Surface facility locations, Mining system and mine plans, Geological, geotechnical and hydrological data, Mining at the lease boundary to maximize recovery, and In-pit tailings disposal plan,

3-28 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 • In Situ Applications: plant construction. Major constraints will be the recrui- ting and training of skilled labor, acquisition of construc- Adequacy of recovery, tion material and equipment, financing, crude oil prices, Water supply and disposal, royalties and taxes, political climate, environmental Geology and in-place volumes of crude bitu- obstacles, and technological hurdles. Based on these men, constraints, Table 2 shows the proposed rate of oil sands Utility and upgrading operations, development as forecast by the Canadian Petroleum Site development plan, Association for submission to ERCB. Well drilling and downhole installations, and Material and energy balances. The authors conclude their paper by stating that if Canada should pour capital into rapid development of oil In the determination of mineable reserves of oil sands, sands and other energy sources, a much more stable several factors are considered. These include: economic climate and directly stimulated economy would result, leading to higher employment and increas- • Crude oil price, ing royalties and taxes paid to the governments. By • Project financing, increasing domestic energy supplies through oil sands • Royalties and taxes, development now, the nation can reduce the deficit • Environmental constraints, and dramatically although Canada can not completely fulfill • Miscellaneous factors such as facility loca- its energy needs if oil sands continue at the present rate tions, lease boundary mining and in-pit of development. To ensure expeditious development of tailings disposal. such high risk projects, it will be necessary to develop a long term energy policy that will encourage a stable After a thorough review of all of these factors, the economic and political climate. ERCB makes a recommendation to the Alberta govern- merit as to whether the application should be approved or I/fill/I denied.

When the project is approved, the rate of development will depend on number of complex factors. Lead time from project definition phase until plant start-up will be approximately 10 years, with one to two years for approval, one and one-half years for process design, three years for detailed engineering and five years for

TABLE 2

SYNTHETIC CRUDE OIL PRODUCTION FORECAST

(OIL SANDS) 103m3/d

YEAR 1980 81 82 83 84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 2000

SUNCOR 7 7 999 9 9 9 9 9 9 9 9 99 99 9 9 9 9

SYNCRUDE 11 13 17 20 20 20 20 22 28 30 30 30 30 30 30 30 30 30 30 30 30

ESSO I 9 17 22 22 22 22 22 22 22 22 22 22 22 22

ALSANDS II 22 22 22 22 22 22 22 22 22 22 22 22 22 POTENTIAL PROJECT #1 10 20 20 20 20 20 20 20 20

//2 10 20 20 20 20 20 20

#3 10 20 20 20 20

114 10 20 20

//5 10 TOTAL (COMMERCIAL 18 20 26 29 29 29 30 51 76 83 83 83 93 103 113 123 133 143 153 163 173

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-29 TAR SAND LEASING BILL DIES IN SENATE and local governments, industry, environmental groups and other parties having an interest in tar sand develop- Although the McKay tar sand Leasing bill (H. B. 7242) merit. In addition, he ordered the U. S. Geological passed quickly through the U. S. House of Representa- Survey to make a formal finding of Designated Tar Sand tives in July, (See Cameron Synthetic Fuels Report, Areas within Utah and the Bureau of Land Management September 1980) the companion bill (S. 2717) ran into to analyze those areas prior to a decision by him to trouble at Senate hearings in September and was choose two such areas for the new leasing. A formal call scrapped. Although both the Department of the Interior either for preliminary expression of interest in areas and and the Department of Energy supported the bill, the bill technologies for tar sand development or for nominations ran into opposition on several points by Chairman of specific tracts will also be issued along with the start Wendell Ford, D-ky, Senator Henry Bellrnon, R-Okla, of baseline data collection for an environmental impact Senator Howard Metzenbaum, 0-Ohio and Senator Dale statement. Bumpers, 0-Ark. Among the points of contention were: The Department of Interior had urged that tar sand • Combining oil, gas, and tar sand leases legislation be passed by Congress as the lifting of the instead of separating them, moratorium had not negated the need for additional legislation. The legislation would have removed statua- tory impediments, potential legal conflicts and serious geologic problems. Deputy Under Secretary of the • No provisions for competitive bidding on tar Interior Stephen P. Quarles told the Senate sub- sand leases such as offshore oil and gas committee that two major obstacles to tar sand leasing leases, existed under existing law: Dual development of oil and gas and tar sand • A large number of existing tar sand leases on the same land under separate oil and gas (793)' and tar sand leases is difficult and in some cases will prove impossible, and • Disagreement over the method of lease con- version, The acreage limitation on tar sand leases is too restrictive. The obstacles will probably • A possible waiver of royalties, and prohibit leasing of the Tar Sand Triangle which contains tar sand that is most physi- • An alleged failure to provide for adequate cally similar to conventional oil. environmental protection. Since the legislation was not passed, The Department of Standard Oil of California (Chevron) was the only the Interior will still go ahead with tar sands leasing industry witness testifying against the bill. Specifically, under Section 21 of the Mineral Leasing Act. Guy Chevron Representative Willard Burton objected to com- Martin, Assistant Secretary for Land and Water bining oil, gas and tar sand under one lease because he Resources, in consultation with Joan Davenport, said it would inhibit exploration and development of Assistant Secretary for Energy and Minerals has been conventional oil and gas. An oil and gas developer would instructed to submit an amended schedule of tasks be restricted to: necessary for offering the leases a month after Congress adjourns. A leasing program is anticipated to be in place • Acquiring his lease through competitive in about two years afer preparation of an EIS. bidding rather than the noncompetitive system if the area was designated as contain- In a related development, Dr. Ruth Davis of the Depart- ing some tar sands, ment of Energy stated at a news conference in Salt Lake City in September that she and DOE Secretary Charles • Would be limited to a five year lease term Duncan felt that tar sands have not received the atten- instead of the ten year term. tion they should, and that the production of 100,000 barrels/day from tar sands by 1990 is a reasonable goal. • Would have to pay a minimum 12.5 percent She also stated that the Department of Energy is royalty rather than the fixed 12.5 percent currently drawing up a tar sand industrial plan that will royalty under an oil and gas lease, and be submitted shortly to Utah Governor Scott Matheson. • Would be limited to lesser acreage under a tar sand lease than under an oil and gas lease. The bill was killed when Senators Bumpers and Metzen- baum threatened to attach further amendments to the bill making it unacceptable to the minority. Meanwhile, the Department of the Interior announced in August that it intended to lift the 15 year moratorium on Federal tar sand leasing. Undersecretary of Interior James Joseph directed Interior agencies to prepare to lease tar sand tracts in Utah by meeting with Utah State

3-30 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 ECONOMICS

COST OF THE COMBUSTION PROCESS CAP x u1,N + ANN IN UTAH TAR SAND IS PROJECTED N PC = (Iti) - A paper entitled "Projected Cost of the Combustion Process in Utah Tar Sand" was presented by R. J. Barrett AP at the spring meeting of the Interstate Oil Compact where CAP is the total investment in capital Commission in Vail, Colorado on June 16, 1980. The equipment, including interest accumulated prior feasibility of using forward and reverse combustion tech- to start of operation, i is the real rate of return nology for in-situ thermal recovery of oil from Utah tar on investment (20%), N is the lifetime of the sand was examined. In the combustion process, a flame capital equipment (20 years), ANN is the sum of front is propagated through the tar sand deposit consum- all annual expenses, and AP is the annual oil ing some bitumen as fuel. Compressed air is supplied to production in barrels. the flame front through an injection well, and the oil is extracted through a production well. Forward combus- TABLE tion, where the flame front moves from the injection well to the production well driving the oil ahead of the BASE CASE PROCESS front, is the most popular option for enhanced oil PERFORMANCE PARAMETERS recovery. However in tar sand, the mobilized oil is unable to move through the cold impermeable region Oil Recovery (Fractional) 0.5 ahead of the flame front. Consequently, the approach Air Consumption (scf/ft 3(Sand)) 300.0 being pursued for tar sand recovery is reversed combus- tion, in which the flame front moves from the production Air/Oil Ration (Mscf/bbl) 33.1 well to the injection well. Oil vaporized at the combus- Volume Sweep Efficiency (Fractional) 0.85 tion front has less trouble moving back through the heated and more permeable region behind the flame BASE CASE RESERVOIR PARAMETERS front. After the reverse combustion has swept the entire pattern area, the front can be turned around and Overburden Depth (ft) 350 propagated in the forward mode to extract the remaining recoverable oil. Net Gross Pay (ft) 13.1 Saturated Permeability (md) 85 Process cost calculations can be analyzed to determine whether the cost falls within reasonable limits and to Original Oil In Place (bbl/Acre.ft) 1570 identify those aspects of a process which have the Recovery Pattern Area (Acre) 1.0 greatest effect on its commercial potential. The overall process cost, defined as that part of the price of oil necessary to cover the cost of recovery, is dominated by the cost of compressing the air. It does not include taxes, royalites, exploration costs and other overhead. Hence, the ratio of the required air to the produced oil is an excellent indicator of the economic attractiveness of combustion.

The calculation of process cost is also affected by the assumed characteristics of the tar sand reservoir and by - the pattern area served by each pair of injection and production wells. As shown in Figure 1, pattern areas less than one acre severely increase the process cost. - 0 Table I contains the base case process performance and reservoir parameters. a. 0 The principal equipment required for a recovery project is shown in Figure 2. Capacity and energy requirements I I I I were calculated from process performance data and 0 1 2 3 4 reservoir parameters. Capital costs and operating ex- penses were calculated for each component, as well as PATTERN AREA (acres) the electricity cost of the air compressors. Process cost was then calculated according to the formula: FIGURE I SENSITIVITY OF PROCESS COST TO PATTERN AREA

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-31 GATHERING EQUIPMENT AIR PRODUCTION (2000BFPD) COMPRESSOR EQUIPMENT (256BHP) (72BFPD) LEASE EQUIPMENT I (2000 BFPO)

TI0N PRODUTION WELL WELL (3500) (350f1)

FIUUHt 2 SCHEMATIC DIAGRAM OF TAR SAND RECOVERY PROJECT Based on the given assumptions and limitations, process 40 cost was calculated at $25.20/bbl. The breakdown 1 presented in Table 2 shows that most (78 percent) of the cost results from purchase and operation of the air compressors. It is clear that a program of applied research to minimize air compressor costs could have a favorable impact on process economics. Most of the remaining cost (IS percent) is due to well completion. TABLE 2

COMPONENT BREAKDOWN Ld OF PROCESS COST IO- - Air Compressors 0 Capital costs $4.96/bbl 19.7% Operating & maintenance 2.69 10.7 C. I I I I Electricity 6.21 24.6 ISO 300 450 600 750 Changeover costs 5.85 23.2 C0I1PRESSED AIR CONSUMPTION [SCF/ 113(SAND)J

Wells FIGURE 3 Well completion 4.44 17.6% SENSITIVITY OF PROCESS COST TO COMPRESSED Maintenance 0.01 AIR REQUIREMENT Lease, Gathering and ProductionEquipment 60 Capital costs 0.74 2.9% Operation & maintenance 0.30 1.2 The process is not capital investment-intensive: only 27 60- percent of process cost results from capital-related costs. As for the absolute accuracy of the calculated I- process cost, it will depend on how well the ultimate U, performance of the combustion process compares with 340- U, the assumptions used in this study. U, Ui Because the process is not capital investment-intensive, C) process cost is relatively insensitive to economic 020- assumptions, such as the rate of return on investment. 0 Figure 3 shows that varying the compressed air require- ments within reasonable limits can alter the process cost by a factor of two. Similarly a reduction in fractional 0.2 03 0.4 0.5 0.6 oil recovery from the assumed value of 0.5 to a value of OIL RECOVERY (FRACTIONAL) 0.25 would double process cost (Figure 4). These results demonstrate a need for continued research on the com- FIUUHt 4 SENSITIVITY OF PROCESS COST TO FRACTIONAL OIL RECOVERY

3-32 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 bustion process to reduce air consumption and increase oil is expected to increase after the first quarter of fractional oil recovery. 1981, as refineries increase asphalt supply for road and construction work. Because the assumed value of 1.0 acre is almost 20 times as large as the test area used in the Laramie pilot Also in September, Gulf Canada announced that it has experiments, an important consideration will be the decided to mothball indefinitely its 80,000-barrel-a-day problem of scaling up to large pattern areas without refinery at Point Tupper, Nova Scotia because of the sacrificing process performance. worsening heavy oil surplus. The refinery had been receiving most of its heavy crude from Venezuela and One potentially important factor in the economics of tar Iraq. Gulf decided that the economic climate did not sand recovery is the effect of reservoir parameters on justify the upgrading of the refinery to reduce the process performance and consequently process cost. percentage of heavy fuel oil produced. The Canadian Only limited information containing comprehensive and federal government has been pushing the oil industry in quantitative analysis of these phenomena exists. The Ontario and eastern Canada to improve refineries to author suggests that development of a systematic com- reduce production of heavy fuel oil. puter model study of in situ combustion could help reduce these uncertainties. 11,/f/il In order to relate process cost to crude oil prices, the author set the following conditions: (I) royalties of 12.5 percent, (2) 100 percent equity financing, (3) an income tax rate of 50 percent, (4) sum-of-digits depreciation of capital equipment, (5) state and local taxes equal to 6 percent of gross revenue, and (6) a charge of $3.25/bbl to cover exploration and overhead. Under these conditions, a process cost of $25.20/bbl would correspond to a crude oil price of $39.00/bbl. This is a high price for crude oil, especially the type of crude recovered from tar sands. Given the uncertainty of the calculation and the volatility of world oil prices, it is difficult to say whether oil from tar sand will be commercially attractive. f/ill HEAVY OIL SURPLUS EXISTS IN CANADA A glut of heavy oil on the market forced several refinery cutbacks in Canada in September. Both Gulf Canada and Husky announced cutbacks and refinery shutdowns due to low demand and large surpluses of heavy oil. In addition, refiners have been forced to take delivery of low quality Mexican crude because of Canadian government con- tracts, worsening the outlook for domestic heavy oil. In September, Husky Oil Company announced a 50% cutback in production of Lloydminister, Wainwright, and Wildmere heavy crude oil. The company blamed high costs and lack of immediate markets for the move. At the time, the $19-a-barrel federal export tax on Lloyd- minister heavy oil and the Lloydminister domestic field price of $15.35 a barrel, combined with pipeline tariffs, exceeded the current price for supplies going to the United States. Later in October, the Canadian federal government reduced the export charge on the heavy crude to stimulate sales to the U.S. The export charge which is added to the domestic price was de-valued by 60 cents a barrel for a total price of $16.35 a barrel for heavy crude during November and December. In late October, Husky announced the sale of four million barrels to the Koch Oil Refinery in St. Paul, Minnesota. The sale allowed a return of full production at the Lloydminister field for the rest of the year and for the first three months of 1981. Canadian demand for heavy

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3..33 ENVIRONMENT

ENVIRONMENTAL ASSESSMENT OF over time to leach into the system. Sealing of adjacent UTAH TAR SAND TEST MADE aquifers from drilling will preclude any contamination between aquifers. Two environmental documents were released earlier this year in support of the Laramie Energy Technology During the operational phase, changes will occur to the Center's in situ tar sand experiment in Utah. (See groundwater during in situ combustion. Specific changes article on experiment results in this issue). The first which occur during this phase of operation have not been environmental review was performed by the Rocky quantitatively defined. However, this is not a problem Mountain Institute for Energy and Environment of the at the current research site as no groundwater exists University of Wyoming and is entitled, "Environmental below the research site for over 800 feet. The possibi- Survey - Tar Sands In Situ Processing Research Program lity exists for contamination of groundwater at other (Vernal, Uintah County, Utah)". This review found sites. As a result of the process, produced waters will several areas of potential impacts due to the in situ exist and these waters should be monitored for move- operation in both combustion and steam injection experi- ment away from the retort area. Fracturing research on ments. Of major conern is the air and water quality tar sands beds will promote permeability and may permit impacts of the program. A summary of these impacts communication between water aquifers. are included here. Process water generated by reverse and forward combus- Air Quality tion represents a problem. Process water was previously disposed of by depositing it in liquid waste disposal areas Air quality was expected to deteriorate during construc- of the local sanitary landfill. In a water poor area, the tion, due to exhaust gases from construction and trans- use of evaporation ponds would be wasteful and it is portation vehicles and fugitive dust created by earth suggested that in the future, reuse schemes be moving. Since only 10 vehicles per day would be addressed. The quantities of such water produced by required, impact would not be serious and would be large-scale operations will be a major environmental short-term. More serious deterioration of air quality impact factor in commercial-scale operations. One ion was expected during the operational phase, as air pollu- of concern in the retort water is ammonia which could tion due to well-boring and venting of gases produced produce serious pollution problems if allowed to reach during the process would be added to dust and emissions surface waters. Trace coripounds and heavy metals will from vehicular use. It is expected that vented gas will also require careful monitoring. Organic compounds be of major concern to a large-scale operation. How- represent different problems in that their behavior as ever, this small operation would influence air quality aquatic contaminants is complex and probably site-speci- only in the immediate vicinity of the stack. Gases fic. Toxicity studies of these organic compounds will be during the test were characterized for sulfur oxides, necessary. nitrogen oxides, CO, unburned hydrocarbons, methane, and particulates. No cumulative impacts are anticipated Steam injection into the formation will result in altered from the research program. In the post-operational produced water compared to that in the studies of phase, the area would again be subject to short-term reverse combustion. Leaching of minerals in the test impacts from engine exhaust and fugitive dust. zone could be increased or petroleum-based organics could be carried beyond the test zone. Solvents used No estimation was made of the possibility of an acci- must be monitored for toxicity. Monitoring wells should dental release of air pollution due to explosions or be installed and sampled frequently. In general, a zero ruptures. In addition, the question of influence on water balance plan should be carried out in conjunction natural precipitation in this arid region was not with any of the raw sand experiments. addressed. These questions would have to be answered for a larger facility. During the post-operational phase, the area will have to be restored to its original condition. Short-term impacts Water Quality will consist of water used in re-vegetation efforts which may possibly reduce stream flow in the area. Nitrogen In the pre-operational phase, site clearing and construc- and phosphorus fertilizers may be carried to adjacent tion will affect the imperviousness of the area, areas by rainfall and snowmelt. Long-term effects increasing rainfall and snowmelt runoff volumes and include groundwater leaching of hydrocarbons and corn- peak flows, plus increasing erosion and sediment, and bustion residues from the abandoned site. If evaporation dissolved solids delivery downstream. Although this site ponds are built, deposition of precipitated salts would area is small, larger sites will have a significant impact. occur. These ponds should be lined and groundwater Baseline data will be collected during this experiment to monitoring should continue for several years after com- determine what effects a larger site might have on these pletion of the test. parameters. The construction phase may also affect the groundwater somewhat with the drilling of welts. Mud- The second report is an environmental assessment that pits also affect the groundwater somewhat with the specifically addresses steam injection experiment just drilling of wells. Mudpits formed on the surface could be completed at the Laramie site near Vernal, Utah. The a source of pollution to shallow aquifer systems, if left report, entitled, "Environmental Assessment, Tar Sand In

3-34 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Situ Steam Injection Experiment", was prepared by the In areas where major U.S. tar sand deposits exist, there Laramie Energy Technology Center. The report finds are few other major sources of most of the pollutants that, due to the small scaleof the operation, the impact likely to be emitted by a tar sand industry. These tar of the proposed action will be minimal. These findings sand deposits are located near major U.S. oil shale are summarized by category below: deposits, and the combined effect of simultaneous development is a major environmental constraint. Air Quality - No violation of air quality Primary environmental concerns according to process standards will occur. The major source of were presented in the Environmental Regulations Hand- emissions will be an IS MMBTU steam gener- book and are shown in Table I. ator. It is not anticipated that individual tar sand develop- Water Quality - No surface discharges will ments will have difficulty in meeting new Federal Source occur during the experiment. Spills will be Performance Standards. However, the combination of localized. The experiment will have no im- emissions from a total industry may violate PSD incre- pact on groundwater since no mobile water ments. It is required that ambient air quality standards has been found on site in the tar sand forma- or a PSD standard be met before the facility receives its tion to be used and shales of low permeability construction permit, where standard determination is overlay and underlay the tar sand, preventing made by predictive calculation rather than by actual test transport of contaminants. Down dip water after the plant is operational. It follows, that the wells are approximately 8 miles from the required control technology level is a function of calcu- site. lation method which is in turn based on estimation models having uncertainties of a factor of two. This • Wastes - All wastes generated by the experi- uncertainty is increased because the meteorology of the ment will be transported to a controlled sites to be used for tar sand recovery plants is not well waste facility with sanitary wastes being known, due to complex topography. handled by an on-site septic tank and leach field. Tar sand developments will be able to borrow control technology being utilized in the mining and oil refining • Biological life - No impact will occur to industries. Based on the belief that industrial emission aquatic life with minimal impact occurring to rates can be lowered to any arbitrary specified level, terrestrial life. No rare or endangered provided we pay the cost and allow adequate lead time species will be affected. Small mammals for development of technology, then economics become may be displaced. the primary constraint on development. Because of the expense associated with extremely low emission levels, • Vegetation - The major impact on vegetation it has generally been attempted to find some acceptable will be surface disturbance and removal of level of pollutant discharge rather than strive for zero vegetation. No critical habitat will be lost discharge. and topsoils are being stockpiled for reclama- tion. States have the right to enact more stringent environ- mental regulations than the federal regulations if they so • Socioeconomic - No known effects on em- choose. Colorado enacted a specific standard which is in ployees or the general population will occur effect an emission standard for oil shale (Colorado Air and no serious effects on aesthetic, recrea- Quality, 1977); and such a standard could be enacted by tional or cultural resources is expected. any other state for a nascent tar sand industry. Other state specific regulations (including only oil producing states) are given in Chapter 7 of the "Environmental Regulations Handbook for Enhanced Oil Recovery." In ENVIRONMENTAL REGULATIONS FOR TAR SAND functioning as a guidebook, this report also offers DEVELOPMENT ARE ANALYZED permitting suggestions and procedural advice. Environmental Laws and Regulations which have special The Water Pollution Control Act clearly notes that significance for enhanced oil recovery were identified in states have the primary responsibility for controlling two separate U.S. Department of Energy publications. water pollution. In some cases, the states apply more "Environmental Regulations Handbook for Enhanced Oil stringent controls to regulate pollutants than does the Recovery" was prepared by Spears and Associates Inc., Federal government. under contract No. DE-AC 19-BC00050 and published in August 1980. The report primarily emphasizes U.S. laws Individual permits set specific limits on the content, and regulations for the control or prevention of pollu- volume, and temperature of what may be discharged into tion. An earlier report entitled "Analysis of the Environ- water. This is generally based on best available tech- mental Control Technology for Tar Sand Development," nology, economically available for pollution control faci- and written by the University of Utah College of lities by 1983. Usually, discharge limitations effect the Engineering, stresses environmental constraints and con- content and volume of what is dumped into waterways, trol technology for both Canada and the U.S. This report but there is an increasing tendency for the purity of was published in June 1979 under Contract No. EX-76-S- receiving waters to serve as a standard for controlling 02-4043. pollution.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-35

TABLE 1

PRIMARY ENVIRONMENTAL CONCERNS (BY PROCESS)'

STEAM INJECTION IN SITU COMBUSTION MICELLAR-POLYMER CO 2 INJECTION

AIR . SO , NO , AND TSP . tic and CO emissions . Fugitive emissions . Leaks of CO, in EN?ISSIO1S FROM from wells from on-site mona- process use br STEAM GENERATORS facture of chemicals transport Wellhead emissions of • SO9 , NO , TSP • H,S emissions tic en1tssion from air ffom wells compressors

WATER . SIGNIFICANT WATER • Moderate water demand • SIGNIFICANT WATER • SIGNIFICANT USE DEMAND in wet combustion DEMAND WATER process DEMAND

WATER • DISPOSAL OF PRO- . DISPOSAL OF PRO- • AQUIFER CON- • DISPOSAL OF EFFLUENTS DUCED WATER DUCED WATER TAMINATION FROM PRODUCED INJECTED WATER CHEMICALS . Aquifer contamination • DISPOSAL OF PRO- I Aquifer contami- from low pH water DUCED WATER nation from low with trace metals res- pH water and tilting from corrosion • Spills/leaks of chemi- corrosion of well of well casings cals to surface waters casings SOLID . Disposal of scrubber • Disposal of wastes • Disposal of wastes • Disposal of water WASTE - sludges from wellhead gas from on-site chemi- treatment wastes cleaning cal manufacture • Disposal of water • Disposal of water • Disposal of water treatment wastes treatment wastes treatment wastes 'Capital letters indicate major environmental issues; italics indicate environmental issues of lesser concern.

Problem constraints could include such factors as the 2. maintaining the protection of high quality grey areas of water quality standards ("best practicable waters from new degradation, technology") and difficult enforcement areas (aquifer disturbance, groundwater contamination) where 3. specifying where the policy is attainable and semantics and personal interpretations enter. The applicable. University report concludes that since water pollution abatement is a relatively young field, it should be To enforce the antidegradation policy, the state of Utah expected that technology, regulations, and enforcement has assigned beneficial water-use classes with specific will not remain the same, but change subject to socio- water quality criteria. The rivers and tributaries in the logical developments and public reactions. Utah tar sands areas have been assigned beneficial-use classes by the Utah Committee on Water Pollution and The Utah Committee on Water Pollution consists of essentially all carry an "Agriculture" classification. eight members, appointed by the Governor to staggered four-year terms, with the Director of Health as an ex- The Utah Committee on Water Pollution has generally officio member. The Committee sets the Utah State taken the position that the Utah Water Pollution Act water quality standards and cooperates with EPA and the applies to all of the State's waters including ground- Utah Division of Health in administering the state and waters, underground contamination, aquifer disturb- federal water standards, permits, and programs (Utah ances, etc. This stand has sometimes brought the Div. of Health, 1978). In 1976, the Utah Committee on Committee into conflict with the Oil, Gas, and Mining Water Pollution adopted an antidegradation policy with Division of the Utah Department of Natural Resources. regard to water quality in the state of Utah. Due to the concern over salinity in the Colorado River, Specifically, the Utah antidegradation policy consists of it is unlikely that tar sand projects will be approved three parts: which may significantly increase the salinity of surface or groundwater runoff. I. restoring water quality to those waters that have already been degraded, Fines are produced when the tar sand is washed. In the GCOS operation in Canada, the fines produce a gel-like

3-36 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 suspension (active clay particles) which is difficult to Ore of too low a quality to be economically treat by ordinary sedimentation (Allen and Sanford, processed. 1973). Since the U.S. tar sands have a larger particle size matrix, this is not anticipated to be as much of a Processed sands problem. Nevertheless treatment of the wash water will be necessary to conserve water and to minimize the Dusts and fines created during ore transpor- discharge of suspended sediments. tation and crushing operations.

The water rights process in Utah follows the "doctrine of Federal laws and regulations relating to surface mining prior appropriation" which gives the water rights to the and the surface disposal of mine wastes and refuse claimer with the highest priority of use but which, in include: practice, has given the water as well as the water right to the first and earliest filer. Since most of the water The Surface Mining Control and Reclamation available in the Colorado River Basin has been filed on, Act of 1977 this means that the tar sand industry will have to purchase water rights from local users (mainly irrigation 2. Mandatory safety standards for surface coal rights) or otherwise negotiate for their water. Water mines, surface work areas of underground rights in Utah are generally regarded as heirlooms, and coal mines, refuse piles, and impounding their availability does not follow usual free marketplace structures (30 CFR 77). principles. This may prove a constraint depending on the particular location and the quantity of water needed. 3. The Resource Recovery and Conservation Act of 1976. Most of the tar sands resource is on federal lands. There will probably be lease stipulations on their exploitation Although the first two of these statutes specifically which will presumably be similar to those for oil shale. refer to coal mining, this is probably because coal mining The oil shale stipulations presented here may serve as a activities are considered the most pressing current guide for the future. problem. However, it is likely that tar sands operations will be ruled within the intent of the laws or the scope of The oil shale operations being developed on public lands the laws; and they will be expanded to include tar sands are controlled by lease agreements entered into between operations. the developer (lessor) and the Bureau of Land Manage- ment of the U.S. Department of the Interior (BLM, The environmental protection performance standards of 1974). The typical BLM oil shale lease agreement the Surface Mining Control and Reclamation Act of 1977 requires (I) that the lessee file and obtain approval of a require that surface mining operations be conducted in a detailed development plan before any work other than manner (1) to maximize the utilization and conservation exploratory be performed, and (2) that operations con- of the full resource being recovered; and (2) to allow ducted under the lease be "in compliance with all appli- restoration of affected lands, including surface disposal cable federal, state, and local water pollution control, of mine wastes, tailing, coal processing wastes, etc., "to water quality, air pollution control, air quality, noise condition capable of supporting the uses which it was control, and land reclamation statutes, regulations, and capable of supporting prior to any mining or higher or standards." In addition, such leases include specific better uses of which there is reasonable likelihood." This environmental stipulations which require that the lessee will require the separate removal and segregated storage avoid removing or damaging objects of historical or of top soil; stabilization and protection of all affected scientific value; minimize damage to fish and wildlife surface areas, backfilling, compaction and grading to habitat; incorporate the means to insure the health and restore the approximate contour of the original land, safety of their workers and personnel; minimize air, replacement of removed top soil, re-establishment of a water, and noise pollution; and preserve the scenic and diverse, effective, and permanent vegetative cover, and functional aspects of the land both during and on com- the long-term assumption of responsibility for successful pletion of the operation. In the area of land rehabilita- revegetation. There are Special provisions for prime tion, the lease requires that all lands disturbed by the farm lands, but they are not relevant to the lands of development be returned "to a usable and productive significance to tar sands operations. It is further condition consistent with or equal to pre-existing land required that mining and associated operations be con- uses in the area and compatible with existing adjacent ducted in a safe manner, with a minimum disturbance to undisturbed natural areas." The latter requires that the prevailing hydrologic balance, minimum chance of disturbed land masses and waste dumps be stabilized, land slide or damage, etc. contoured, and protected against wind and water erosion. The mine safety standards of interest to tar sands The solid wastes to be dealt with in a major tar sands operations are those dealing with (1) the required operation are: character and construction of refuse piles and (2) water, sediment or slurry impoundments, and impounding Top soil stripped from affected lands (pre- structures. Although designed for coal mine refuse piles, sumably stockpiled for later use in rehabilita- they are directly applicable to the piles to be used for tion programs). the surface disposal of processed tar sands. Overburden (if open pit mining is used). In Section 3 of the University of Utah report, U.S. Federal Regulations are specifically compared to Cana- dian Federal and Alberta Regulations.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-37 Although there are significant differences in the funda- mental legal structure of the two countries, it is the authors observation that the final result of environ- mental control law in Canada is not drastically different than it would be for a similar facility in the United States. Thus it appears to the authors that if the existing tar sand plants in Alberta and those which are envisioned for the near future had been subject to U.S. environmental regulations (instead of Canadian) as they existed at the time of the construction or will exist in the future, the plants would have been (or would be) substantially the same as they are now. 1/11111/

3-38 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF OIL SANDS PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name Page Alberta Energy Company. Ipiatik Lake Project . 3-47 Suffield Heavy Oil Pilot 3-50 Syncrude Canada, Ltd ..... 3-43 Alberta, Province of Syncrude Canada, Ltd. . 3-43 Alminex, Ltd. Home Oil Athabasca Lease 3-46 Amoco Canada Ltd. Alsands Project Group 3-42 Block One Project ..... 3-44 Peace River In Situ Pilot Project. 3-49 AOSTRA Block One Project ..... 3-44 North Kinsella Heavy Oil Project. 3-48 Peace River In Situ Pilot Project. 3-49 Suffield Heavy Oil Pilot 3-50 Surmont Project 3-50 Taciuk Process Pilot 3-50 Aquitaine Company of Canada Ltd. Huff-and-Puff Cold Lake Project. 3-47 Barber Heavy Oil Process, Inc. Heavy Oil Process (HOP) Technology 3-46 BP Exploration Canada Ltd. Marguerite Lake Phase A Pilot Plant 3-48 Canada Cities Service, Ltd. Syncrude Canada, Ltd. . . . . 3-43 Manatokan Project ..... 3-47 Mine Assisted In Situ Project 3-48 PCEJ Project 3-49 CDC Oil and Gas, Ltd. Athabasca In Situ Pilot Project 3-44 Chanslor Western Oil & Development Co. Vaca Tar Sand Project 3-51 Chevron Standard Ltd. - Alsands Project Group . . . -. 3-42 Huff-and-Puff Cold Lake Project. 3-47 Dome Petroleum Canada Ltd. Alsands Project Group 3-42 Department of Energy, U.S. LETC-TS-2C Reverse Combustion 3-47 (Laramie Energy Technology Center) Esso Resources Canada Ltd. Mine Assisted In Situ Project 3-48 PCEJ Project 3-49 Getty Oil Company . Cat Canyon Steamflood Project. 3-44 Diatomaceous Earth Project 3-42 Great National Corporation Sunnyside Project ...... 3-50 Guardian Chemical Corporation Aqueous Recovery— Polycomplex. 3-43 Gulf Oil Canada Ltd. Alsands Project Group 3-42 Home Oil Athabasca Lease 3-46 Mine Assisted In Situ 3-48 Pelican ...... 3-49 Resdeln Project ...... 3-49 Surmont Project 3-50 Syncrude Canada, Ltd.. - 3-43 Wabasca Project 3-49 Home Oil Company Home Oil Athabasca Lease 3-46 Hudson's Bay Oil and Gas Alsands Project Group 3-42 Marguerite Lake Phase A Pilot 3-48 Syncrude Canada, Ltd. . . . 3-43 Husky Oil Operations, Ltd. Aberfeldy Project ..... 3-43 Mine Assisted In Situ Project 3-48 Hydrocarbon Research, Inc. Dynacracking Upgrading Plant. 3-45

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-39 Company or Organization Project Name Es Imperial Oil Ltd. Commercial Extraction Plant, Cold Lake ...... 3-42 Leming Project ...... 3-46 Japan Canada Oil Sands, Ltd. PCEJ Project ...... 3-49 Japan Oil Sands Co. (JOSCO) Primrose Project ...... 3-49 Kaiser Oil, Ltd. Suffield Heavy Oil Pilot ...... 3-50 Kirkwood Oil and Gas Tar Sand Triangle ...... 3-50 Mobil Canada Ltd. Celtic Heavy Oil Wet Combustion ...... 3-45 Cold Lake Stratigraphic Test Program ...... 3-45 Murphy Oil Canada Ltd. Lloydminster Fireflood ...... 3-47 Lindbergh Steam Project ...... 3-47 Eyehill In Situ Steam Project ...... 3-46 Natomas Energy Company Natomas Solvent Extraction Process ...... 3-48 Norcen Energy Resources Ltd. Primrose Project ...... 3-49 Petrocanada Alsands Project Group ...... 3-42 Block One Project ...... 3-44 lpiatik Lake Project ...... 3-47 Mine Assisted In Situ Project ...... 3-48 North Kinsella Heavy Oil ...... 3-48 PCEJ Project ...... 3-49 Syncrude Canada, Ltd ...... 3-42 PanCanadian Petroleum Syncrude Canada, Ltd ...... 3-42 Marguerite Lake Phase A Pilot Plant ...... 3-48 Petrofina Canada Ltd. Alsands Project Group ...... 3-42 Syncrude Canada, Ltd ...... 3-42 RTR Oil Sands Alberta, Ltd. RTR Pilot Project ...... 3-49 Sandia Laboratories Deepsteam Project ...... 3-45 Santa Fe Energy, Inc. "200" Sand Steamflood Project ...... 3-51 Vaca Tar Sand Project ...... 3-SI Saskatchewan Oil and Gas Corporation Meota Steam Drive Project ...... 3-48 Shell Canada Resources, Ltd. Alsands Project Group ...... 3-42 Block One Project ...... 3-44 Peace River In Situ Pilot Project ...... 3-49 Strathcona Synthetic Crude Refinery ...... 3-43 Shell Explorer, Ltd. Alsands Project Group ...... 3-42 Peace River In Situ Pilot Project ...... 3-49 Sohio Natural Resources Company Asphalt Ridge Pilot ...... 3-44 Standard Oil of Indiana (Amoco) Sunnyside Project ...... 3-50 Sun Oil Company Block One Project ...... 3-44 Suncor, Inc ...... 3-43 Fort Kent Thermal Project ...... 3-46 Syncrude Canada, Ltd. Syncrude Canada, Ltd ...... 3-42 Tenneco Oil of Canada, Ltd. Athabasca In Situ Pilot Project ...... 3-44 Texaco Canada, Ltd. Texaco Athabasca Pilot ...... 3-SI Texas Gulf, Inc. Meota Steam Drive Project ...... 3-48 Total Petroleum Meota Steam Drive Project ...... 3-48 Underwood McLellan & Associates Taciuk Processor Pilot ...... 3-50 (UMA Group) Union Oil of Canada, Ltd. Chipewyan-Buffalo Creek Carbonate ...... 3-45 Union Texas of Canada, Ltd. Ardmore Thermal Pilot Plant ...... 3-44 U.S. Department of Energy Cat Canyon Steamflood Project ...... 3-44 Deepsteam Project ...... 3-45

3-40 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Company or Organization Project Name Page University of Utah Sunnyside Project. . 3-50 Westcoast Petroleum, Ltd. Manatokan Project . 3-47 Suffield Heavy Oil Pilot 3-50 World Wide Energy Fort Kent Thermal Project 3-46

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-41 STASLJS OF SYNF(JELS PROJECTS (Underline denotes changes since September 1980) OIL SANDS **************.**wM.**********4******,4** COMMERCIAL PROJECTS ****ww*,w*.**.*,,.*fl,... ALSANDS PROJECT GROUP (Shell Canada Resources, Ltd.) -- Shell Explorer, Amoco Canada, Chevron Standard, Dome Petroleum, Hudson's Bay Oil & Gas, Petro-Canada, Gulf Oil Canada, Petrofina Canada Proposed commercial bituminous sands plant of 140,000 BPD. Located on Lease 13 (Shell) and Leases 12 and 34 (Fina- Daphne) at Athabasca, Alberta. Mining--electric dragline, bucket wheel excavators; extraction-hot water process; upgrading—fluid coking. Alsands intends to manufacture hydrogen initally by heavy oil partial oxidation and ultimately by coke gasification. Consortium of nine members consists of: Shell Canada Resources-25 percent, Shell Explorer-20 percent, Amoco Canada Petroleum-ID percent, Chevron Standard-8 percent, Dome Petroleum-4 percent, Hudson's Bay Oil and Gas-8 percent, Petro-Canada-9 percent, Gulf Oil Canada-8 percent, Petrofina Canada-8 percent. The consortium's application was heard by ERCE3 in June 1979 and substantially approved in December. A preliminary field program, including site clearing and drainage, was begun, January 1980. An acceptable tax package will still have to be negotiated with the federal and provincial governments. Project Cost: Estimated at $8 billion

ESSO RESOURCES CANADA LIMITED - Cold Lake Project Esso Resources Canada Limited is proceeding with design work on a 141,000 IWO 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. Major construction is expected to begin in 1982, with completion and plant startup in 1986. 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 Provinced Government. This decision is expected when the Federal and Province of Alberta governments have reached an agreement on the pattern for future increases in Canadian Crude prices, and the sharing of the resulting revenues betweent he two levels of government. Esso Resources will act as the plant operator and is inviting financial participation by other interests. Project Cost: Estimated cost $9 billion GETTY OIL COMPANY -- Diatomaeous Earth Project Getty Oil Company is studying the feasibility of commercial oil production from oil-saturated deposits of diatomaceous earth located in the McKittrick 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 mineable oil, which will be recovered using open pit mining and backfilling techniques. Two extraction processes, the Dravo solvent extraction method and a Lurgi-Ruhrgas retort, are scheduled to be tested in pilot plants to be constructed during 1980. Tentative completion dates for pilot plant construction are April 1981, for the Dravo pilot and September 1981, for the Lurgi pilot plant. Following pilot construction, 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 crude oil production of 20,000 barrels per day. 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 1984. Site preparation for the pilot phase of the project began in March. Project Cost: Undetermined at this time. OIL SANDS SURFACE MINE PROJECT - Petro-Canada, Alberta Gas Trunkline, Ltd. (Nova) A fourth oil sands plant is planned on a site in the Athabasca deposit. The plant is expected to produce 100,000 to 150,000 barrels per day at an undisclosed cost. Both Husky Oil Ltd., and the Alberta Indian Tribes have been offered a ID percent share each in the project. Work will begin shortly on the preparation of a regulatory application at a cost of $100 million (Cdn). The application is scheduled to be submitted in 1982 with construction to begin in 1985 and plant start-up by 1990.

3-42 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980)

COMMERCIAL PROJECTS (Cont..) STRATHCONA SYNTHETIC CRUDE REFINERY - Shell Canada Ltd., Husky Oil 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. The refinery will be owned 60 percent by Shell Canada Limited (operator) and 40 percent by Husky Oil Ltd. 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 be gasoline, diesel and jet fuel and stove oil. The refinery will also produce 4,700 barrels per day of benzene which will be used as feedstock for a planned world scale styrene plant in Alberta. An application for a permit to construct has received the approval of the Energy Resources Conservation Board of Alberta and the Government of Alberta. Construction is planned to begin in early 1981 with start-up in 1984. The prime contractor will be PCL-Braun-Simons Ltd. (P13-5). Project Cost - $750 million (Cdn.) as spent.

SUNCOR, INC. (formerly Great Canadian Oil Sands, Ltd.)-- Sun Oil Co. (97.8 percent), publicly (2.2 percent) Cmercial plant at 83+8072-10-W4M has been in production since 1967 with authorized annual pduction of 1,334 m per day from the Athabasca bituminous sands deposit. Annual production for 1979 was 6,800 in per day. Mining is carried out with bucketwheel excavators; extraction is by hot water process. Upgrading is by delayed coking and hydrogen saturation (Unifining). Coke fuels the on-site power pint. Work is underway on a $185 million expansion program designed to increase output by approximately 2,067 m per day. Expansion plans involve a third mining bench and bucketwheel excavator, a fifth line in the extraction plant and an additional pair of coking drums. A 250,000 lb. gas-fired boiler will be added in the utilities plant. Suncor Inc. was formed in August 1979 by the amalgamation of Great Canadian Oil Sands and Sun Oil Co. Ltd. Net earnings for the entire company for the first six months of 1980 were $174.7 million Canadian. Suncor receives world price for its synthetic crude production from the Oil Sands Division operation at Tar Island.

SYNCRUDE CANADA, LTD. -- Esso Resources Canada Limited (25 percent); Canada Cities Service, Ltd. (17.6 percent); Gulf Canada Resources Inc. (13.4 percent): Petro Canada Exploration Inc. (12 percent); Alberta Energy Company (10 percent); Province of Alberta (8 percent); PanCanadian Petroleum Limited (4 percent); Petrofina Canada, Inc. (s percent); Hudson's Bay Oil and Gas Co., Ltd. (5 percent) Plant at 93+92-I0 W4M with an allowable production of 129,000 BPCD has been in early stages of production since July 31, 1978. Mining --electric draglines; extraction -- hot water floatation 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. Jan 1980, to September 1980, 21.6 million barrels were delivered. All major equipment in place and operational; four draglines and four bucketwheels working. Syncrude's staff is now 3,800.

Project Cost: Total cost $2.3 billion

w*w*ww*w*www*-*w*w** R & 13 PROJECTS ***-**********-ww*w*w*w***********w**w*fl**** ABERFELDY PROJECT - Husky Oil Operations, Ltd. An in situ steam drive with steam stimulation project is being developed at Aberfeldy Section 20-49-23 W.3 in Saskatchawan. Installation of equipment and flow lines is underway with initial production expectedto commence by June1980. Husky signed an agreement with Gulf Canada, Ltd., in which Gulf will commit about $35 million (Cdn.) to earn up to a 50 percent working interest in part of the Husky's Saskatchewan properties. AQUEOUS RECOVERY -- Dikor Process, Guardian Chemical Corporation The aqueous recovery process investigates the feasibility of using a low concentrate solution of a polycomplex to extract bitumen from oil sands. The chemical was originally designed to break up oil slicks. Pilot plant operates on 400 pounds of feed per hour. Claim made that process uses only one-third the energy of conventional hot water process and requires only one-third the construction costs. New Western Oil Sands, Ltd., a subsidiary of Rainbow Resources, Ltd., has provided the oil sands feed for the test as well as financial backing for the pilot plant. Construction of a semi-commercial 100 TPD plant is complete. The plant has been tested in New York and will be moved to Alberta for long period demonstration phase. Australian businessmen adding $113 million for interest in the 100 TPD unit. Construction of the demonstration unit is complete and the company has expressed intentions to build commercially in the Athabasca deposit with support of major companies. Results of testing encouraging, and

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-43 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

the company has demonstrated success in U.S. oil sands, particularly in Utah. However, these oil sands do not contain enough oil to make extraction economically feasible, at present. Project Cost: $1.0 million

*ARDMORE THERMAL PILOT PLANT - Union Texas of Canada, Ltd. Union Texas of Canada, Ltd., is operating an in situ recovery pilot in the Cold Lake tar sand deposit of northeastern Alberta. The project, consisting of 15 wells on 5 acre spacing, is evaluating both huff and puff and steam drive recovery techniques. Production rates of up to 350 BOPD have been achieved from the project and more than 230,000 bbls. of the 10-12° API crude have been produced. Project Cost: Capital Costs estimated at $3.0 million ASPHALT RIDGE PILOT - Sohio Natural Resources Company A surface mining project using solvent/water extraction, located on 1828 acres in Uintah County, Utah. The demonstration plant would produce approximately 5000 BPD with an eventual scale-up to a commercial-sized plant of 25,000 BPD by 1990. The tar sand to be used runs from 6.4 to 29 gallons per ton with an average of 11.3 gallons per ton. The extraction process is a process called "continuous counter current solvent extraction process" developed by Sohio in the laboratory. Phase I of the project will involve completion of the laboratory process development work, design of the pilot plant and obtaining of necessary permits and approvals and completing notification procedures. This is expected to be completed by the end of 1982. Project Cost: Undisclosed

ATHABASCA IN SITU PILOT PROJECT - CDC Oil and Gas, Ltd., Tenneco Oil of Canada, Ltd In situ steam-drive pilot project located 25 miles northeast of Suncor, Ltd., on a 49,000-acre oil sands lease. CDC Oil and Gas owns 51 percent interest in the lease. ERCB approvals have been obtained and design of the pilot is underway. Forty-one holes were cored and logged and nine wells logged this winter on the south half of the lease to confirm reserves. Following evaluation, construction of the pilot plant will begin in 1980 for startup in July 1981. Project Cost: Unknown

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 27-85-3 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.)

CAT CANYON STEAMELOOD 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 is currently shut- in in an attempt to de-water the pilot area. Resumption of injection is planned as soon as the de-watering operation is complete. Ultimate Project Cost: $8,700,000

*New or Revised Projects

3-44 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

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 is in progress. Air injection started in late October 1980.

Project Cost: $30 million (Cdn.)

CHIPEWYAN - BUFFALO CREEK CARBONATE-- Union Oil Company of Canada Testing of an in situ recovery project has taken place under Approval No. 2062 in 2149-21 W4 in the Chipewyan area west of the Athabasca deposit, Alberta, Canada. A single huff-and-puff test was run to determine steam injection capacity and sample deposit fluids. Exploration and testing is continuing. A second test near Buffalo Creek was conducted in 1977 utilizing steam extraction from carbonate rock 700-1200 feet below surface level. Union operated a small in situ combustion test at the Buffalo Creek test site during 1978 and 1979. A single well steam stimulation test is being conducted in 1980. This well is surrounded by four observation wells which should provide data for an improved description of reservoir heating and recovery performance. 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). An estimated 20 billion barrels are in place in these carbonates on Union land. Testing will continue throughout 1980.

Project Cost: Approximately 12 million spent to date.

COLD LAKE PILOT PROJECT - BP Canada, Pancanadian Petroleum Ltd., Hudson's Bay Oil and Gas Company A second pilot plant is being planned by BP Canada, located near the-Albeftikatchewan border in the Cold Lake ares, on 75,000 acres of land. The plant will-cost $100 million and produce 5,000 to 10,000 barrels of oil per dày. The current timetable calls for 30 wells to be drilled this winter to determine a site for the plant, an application to be filed with the ERCB in 1981 and construction to begin in late 1981. A completion date has been set for late 1983. Scheduling will depend on resolution of the current conflict in oil pricing between the Canadian Federal government and Alberta.

Project Cost: $100 million (Cdn.)

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. Heavy oil zones up to 30 meters thick have been delineated at depths of between 290 and 460 meters. A 10-well evaluation program is being carried out in 1980, in addition to 94 holes previously drilled. A decision on location of

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 ralifnrnia hv Ilino tErn dnuinhnl C3.IICUUICcJL2y Lilt tHU UI iYai. me program is intended to units by 1982-1983.

DYNACRACKING UPGRADING PLANT - Hydrocarbon Research, Inc. HRI is working with CaliforniaSynfuels Research Corporation, operators for an industrial joint venture to build a commercial-scale heavy oil upgrading plant in Cali1—ornia, capable of handling heavy oil tar sand bitumen and shale oil. The facility is designed to initially handle 5000 barrels per day of vacuum residue from west coast refinery crudes. The plant will use an HRI-patented process known as "Dynacracking." Project Cost: $I million for design phase only.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-45 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980)

R&D PROJECTS (Cont.) 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 Essos Lease No. 40. Current project approval is 1,500 BOPD with productivity around 800 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 5,000 BOPD. The Leming pilot uses a seven spot as well as an oblong line drive pattern and a total of 90 wells have been operated since 1976. A horizontal well was drilled in 1978. Esso is currently expanding its Leming field and plant facilities to increase the capacity to 14,000 BOPD and some 125 additional prqduction and observation wells have been drilled. The expansion will cost $60 million and will come on-stream during 1982. Project Cost: $110 million EVEHILL IN SITU STEAM PROJECT -- Murphy Oil Company Ltd, Canada Cities Service, Ltd., Canadian Reserve Oil and Gas Ltd. An experimental pilot plant in the Eyehill field, Cummings Pool, at Section 16-40-28-W3 in Saskatchewan. Construction is now complete and start-up began in June 1980. The project utilizes in situ combustion as a drive system, with steam stimulation at the producers. The steam stimulation is to increase productivity and aid in overcoming production problems. The project consists of nine five-spot patterns. Partial funding for this project was provided by the Canada-Saskatchewan Heavy Oil Agreement Fund. Canada Cities Service, Ltd recently signed an agreement to obtaina one-third interest in the project

Project Cost: $13.0 million FT. KENT THERMAL PROJECT-- Worldwide Energy Corporation and Suncor, Inc. Worldwide Energy Corporation and Suncor, Inc. have completed Phase II 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, and by the end of 1980, production is estimated to reach 2,000 BPD. Under an agreement between Worldwide and Suncor, Suncor became the operator of the project on January I, 1980. Engineering evaluation of Phases I and II will proceed throughout most of 1980. Current plans project the start of a Phase Ill commercial development in 1981 or 1982, the drilling of 1500 wells, and construction of facilities to produce 13,000 BPD over a 20-year period. Phase Ill development is expected to have a total cost in excess of $200 million (Cdn.) Suncor will spend 55 percent of the first $137 million (Cdn.) and the companies will share the remaining cost equally. Project Cost: Estimated Total Cost $268 million HEAVY OIL PROCESS (HOP) TECHNOLOGY - Barber Heavy Oil Process, Inc. The project is a demonstration project located on a 25 acre site in the Kern River Field in California. The site was obtained on a farmout agreement from Shell. The process involves steam injected through boreholes drilled radially from the bottom of a large diameter shaft. Barber Heavy Oil Process, Inc., hopes to recover 60 to 65 percent of the oil reserves during the five-year life of the project. Apprimatelyox $1 million has been spent on development with $5.0 million authorized for the remainder of the project. The project was certified by the Tertiary Enhanced P ernueru Prnoram nf the flenartment of Enerev such that tertiar y incentive revenue is available for partial funding

Project Cost: $6-7 million total HOME OIL ATHABASCA LEASE-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 1130) consists of 15,086 hectares (37,715 acres), situated 43 kilometers F26- 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 Ali-ex Ltd. 6.25 percent. An exploratory drilling program began in December 1979 and was completed in February 1980. Results of this program were encoura2in2 and Gulf has elected to proceed with further exploration in 1981. - A decision to proceed with

Project Cost: Gulf Canada only $42 million.

3-46 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

HUFF-AND-PUFF COLD LAKE PROJECT - 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 an 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-I W4. Construction began in early May 1977. Project consists of seven producing wells and six temperature observation wells. A huff-and-puff procedure is followed utilizing a 25 MM BTU/hr steam generator. Aquitaine Company of Canada Ltd. may spend up to $1.5 million over the next five years to acquire information from the pilot. Operations began in March, 1978. Project Cost: Undetermined

*IPJATIK LAKE PROJECT - Petro-Canada, Alberta Energy Company This project is a multi-well exploration program operated under a farm-out agreement with Alberta Energy Company. The project is located in a portion of the Primrose Bombing Range near Cold Lake Alberta. Sixty-four test wells of a proposed 100 wells were drilled by the end of 1979 with an 80 percent success ratio. After drilling is completed in 1981, a thermal recovery test is planned for 1982. Heavy oil-in-place is estimated to be 12 billion barrels.

Project Cost: Undetermined

LETC-TS-2C, Reverse Combustion -- U.S. Department of Energy U.S. Department of Energy Tar Sand Program conducted by the Laramie (Wyoming) Energy Technology Center. Field experiment site on Sohio Natural Resources Company fee property in Utah's Northwest Asphalt Ridge deposit west of Vernal, UT. Steam injection into 0.25 acre inverted 5 spot pattern began April 23, 1980, and was completed September 29, 1980. Cumulative oil production from the 50 feet thick tar sand zone was 1,100 barrels. Other recent supporting research activities include: steam injectivity tests (field), hydraulic fracturing test (field), rock fracturing research (field and lab), steam injection process experiments (lab), computer process modeling, a study of water availability.

Project Cost: $5.9 million - FY SI funding LINDBERGH STEAM PROJECT-- Murphy Oil Company, Ltd. Experimental in situ recovery project located at 13-58-5 W4, Lindbergh (Grand Rapids Formation), Alberta, Canada. In 1974, approval was granted for a 31-well pilot consisting of seven 7-spot patterns. An inverted seven-spot pattern has been drilled to date. Each well has been steam stimulated and produced several times. Steam drive from the center well was initiated in September 1980. Production rates from the seven-spot area have been encouraging to date.

Project Cost: $2 million to date LLOYDMINSTER FIREFL000 -- Murphy Oil Company, Ltd. An experimental wet in situ fireflood project located in the Lloydminister area, Silverdale (Sparky Pool Formation), Saskatchewan, Canada, has beenoperated from August of 1973 until May of 1980. The pilot consisted of a nine spot prn 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 *MANATOKAN PROJECT - Canada-Cities Service Ltd., Westcoast Petroleum This project is on 41,000 acres in the Manatokan area of Alberta, about 25 miles southwest of Esso Resources Cold Lake Project. Twelve evaluation wells have been drilled by Westcoast in the past five years and consultants have estimated the oil-in-place at 4.2 billion barrels in the Lower Cretaceous sands. Canada-Cities Service has farmed in and could earn a 50 percent interest in 20,000 acres by spending $15 million under the agreement. Canada-Cities Service will drill a minumum of 12 wells and carry out a series of cyclic steam injection tests on at least one well. By October 1, 1983, the company must install a 25 well pilot project to conduct steamflooding by November I, 1984, to qualify for the interest in the project. The pilot would be operated for a minimum of 48 months, during which Canada-Cities Service will receive 100 percent of the revenues with Westcoast receiving a 10 percent gross overriding royalty.

*New or Revised Project.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFIJELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980)

R&D PROJECTS (Cent.) MARGUERITE LAKE PHASE A PILOT - BP Exploration Canada Limited, Hudson's Bay Oil & Gas Company Limited PanCanadian Petroleum Limited BP Exploration Canada Limited, Hudson's Bay Oil and Gas Company Limited, and l'anCanadian Petroleum Limited have entered into arrangements whereby Hudson's Bay and PanCanadian will join 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 about seven years, involves the use of steam and combustion for bitumen recovery and is located at 7-66-115- W4M. It has been approved for 50 percent funding by the Alberta Oil Sands Technology and Research Authority and the remaining project costs will be shared in the following manner: BP Exploration Canada Ltd. (20 percent), Hudson's Bay Oil and Gas Company Limited (17 1/2 percent), PanCanadian Petroleum Limited (12 1/2 percent). At the conclusion of the project the other companies will 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. Commercial development (Phase B) which could commence by the mid-1980's is dependent on the success of the pilot project. The project utilizes cyclic steam stimulation followed by in-situ combustion in the Mannville "C" zone at a depth of about 500 meters. The pilot consists of four 5-spot well patterns with 5-acres per well spacing, plus four "out-of- pattern" test wells. Initial steam injection (Phase A) commenced in 1979 and will continue through mid- 1980's.

Project Cost: $18.4 million MEOTA STEAM DRIVE PROJECT - Texas Gulf, Inc., Total Petroleum, Saskatchewan Oil and Gas Corporation. Nine oil production/steam injection wells have been drilled on a 2.5 acre spacing in the Meota area, about 20 miles northwest of North Battleford. Cyclic steam injection is presently tried. Plans are to convert the project to steam drive with an expected recovery of 40 percent of the oil in place. The Project is presently running with one 20 million Btu generator. The second phase of the project will entail expansion to a second nine-spot pattern. A 3.9 mile pipeline to draw water from the north Saskatchewan River to the plant has been constructed.

Project Cost: The Saskatchewan and Canada Federal Governments contributed $1.5 million in funding assistance during 1977 and 1978 for Phase I of the project. MINE ASSISTED IN-SITU PROJECT - Husky Oil Operations, Ltd., Esso Resources Canada, Ltd., Gulf Canada Resources, Inc., Canada-Cities Service, Ltd., and Petro-Canada The Mine Assisted In Situ Project is being undertaken in the Mildred Lake area, located in section 34-92-10 W4M. The project consists of three horizontal wells, gm apart which were drilled and completed to a total length of 310 M. The drilling phase of the project has been successfully completed and the steam injection phase began in December, 1979. The experimental plant will run for a period of one year.

Project Cost: $5 million (Cdn.) 'NATOMAS SOLVENT EXTRACTION PROCESS - Natomas Energy Company Natomas Energy Company has received a grant from the Departmentof Energy to study the "Feasibility of Natomas Process For Extraction of Bitumen From Domestic Tar Sands.' DOE will contribute $363,594 towards the expected total project cost of $450,000. The feasibility study will consist of a detailed development for a 20,000 barrel of oil/day extraction facility for tar sands, including engineering design and cost estimates and environmental, health, and socioeconomic impacts investigations. The process to be used is a solvent process based on Natomas' patents for separation of fines and solvent recovery. In laboratory tests bitumen recovery has been 98 percent. The study is to be site-specific for a domestic tar sand resource; California or Utah tar sand deposits are under investigation for the site. If the feasibility study shows economic, technical, and permitting practicality, a 60-100 B/SD plant would be operable by late 1982, a 2000 B/SD commercial demonstration unit by mid 1985, and the full-scale 20,000 B/SD commercial plant by 1990. Kaiser Engineers, Camp Dresser & McKee, and SRI will also be participating in the study. 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 known as fireflooding. Twelve wells have been drilled for each scheme. Pilot plant construction was completed in October 1979 and operations are underway.

Project Cost: $17.7 million

'New or Revised Project

3-48 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

PCEJ PROJECT -- Petro-Canada, Canada-Cities Service Ltd. and Eno 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 under construction and initial well drilling has been completed. Twelve wells were drilled, consisting of four electrode wells and eight observation wells. Start-up of the electric preheat process is scheduled for October 1980. 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.

Project Cost: Undetermined.

PEACE RIVER IN SITU PILOT PROJECT - Shell Canada Resources, Ltd./A05 TRA, 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 oil sands with the project to be operative by 1981. Thepilot will consist of a 31 well centrally enclosed 7 spot pattern. Both steam stimulation and fireflood nrnrp ccec will k tpctrrl

PRIMROSE PROJECT - Norcen Energy Resources Ltd. & Japan Oil Sands Co. Norcen 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 been over four-fifths of that amount. RESDELN PROJECT - Gulf Canada Resources Inc. The Resdeln Project, located approximately 60 miles South of Fort McMurray, comprises six wells which will be steam stimulated. Production from the Wabiskaw - McMurray formation will be monitored. This project is totally sponsored by GCRI with a capital investment of approximately $4.5 MM. Steaming of the first three wells will commence in November and December 1980, with the remainder being put on line in the first half of 1981.

Project Cost: $45 million (Cdn.) RTR PILOT PROJECT - RTR Oil Sands Alberta, Ltd. Tar Sands Extraction pilot project located at the Suncor plant. Field work on the project was completed in July 1979. The project was shutdown in August. The pilot is not expected to run for the next year during which time data will be analyzed and assessed. Development work is continuing and is being directed toward a process which may lead to the elimination of the large tailings ponds generally associated with the traditional hot water process. A decision will then be made as to whether or not to modify the plant and continue with testing in the spring of 1981. Project Cost: Unknown New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-49 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980)

R&D PROJECTS (Cont.) SUFFIELD HEAVY OIL PILOT - (SHOP) - Alberta Energy Company, Ltd., AOSTRA, Westcoast Petroleum Ltd., Kaiser Oil, Ltd., Musketeer Energy, Ltd. An in situ combustion project located in southeastern Alberta within the Suffield Military Range. Phase A of the project consists of one isolated five-spot pattern. The reservoir is a Glauconitic sand in the Upper Mannvtlle formation which is underlain by water. The wells, including three temperature observation wells, were drilled during the summer of 1980. Completion of facilities construction and start of injection is forecast for early 1981. Phase A is expected to continue for our years. AOSTRA holds a 50 percent interest in the project, Alberta Energy Company holds a 25 percent interest and Musketeer Energy and Westcoast Petroleum each hold a 12.5 percent interest. Project Cost: $9 million (Cdn) SUNNYSIDE PROJECT - Great National Corporation, University of Utah An 80 barrel per day pilot plant on 1200 acres in the Sunnyside deposit of Utah is planned. The project will use either a hot water or thermal process or a combination of both processes developed by the University of Utah. Surface mining will be used to recover the tar sands. An eventual scale-up to a 25,000 barrel per day commercial plant is planned. Phase I will involve organization, engineering, and design of the pilot plant.

Project Cost: Unknown WSUNNYSIDE PROJECT - Standard Oil Company of Indiana (Amoco) Amoco is conducting a feasibility study for a commercial project in the Sunnyside deposit in Carbon County, Utah. Various extraction technologies are being studied under an agreement negotiated between Standard and Dravo Corporation earlier in 1980. Drilling is now being done to determine the extent of the resource and the water supply is under study. Baseline data for environmental purposes is also being collected. The feasibility study is slated for completion in early 1981. The project is partially funded by the U.S. Department of Energy.

Project Cost: Undisclosed *SURMONT PROJECT - Gulf Canada Resources, Inc., AOSTRA The project is a $130 million, ten-year joint venture program to determine 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 means of access to the formation will be considered; the drilling of wells from the surface which will be deviated to the horizontal plane and the drilling of wells from tunnels placed above, within or below the pay zone. The first phase of the project will consist of a two-year study to investigate feasibilities and will provide design engineering and cost estimation. The second phase will be an eight-year field project on acreages owned by Gulf and AOSTRA in the Surmont area. Evaluation drilling and seismic programs have been carried out to select a pilot project site.

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. 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 1000 tons of Athabasca oil sand have been processed. Performance information has been compiled and a study on comparative economics is in progress. Further pilot work is planned to evaluate modifications 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 plans to drill seven coreholes during 1980 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.

Project Cost: Unknown

*New or Revised Projects

3-50 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underlining Denotes Changes Since September 1980) R&D PROJECTS (Cont.)

TEXACO ATHABASCA PILOT-- Texaco Canada Ltd. Texaco's experimental in situ recovery project is located at 15-88-8 W4M on the Company's Bituminous Sand Lease No. SI in the Athabasca Oil Sand deposit, Alberta, Canada. Construction was started in 1972 and initial recovery operations commenced in 1973 with thirty-four wells. Eighteen new wells were drilled in 1975 and an expansion of facilities was completed in 1976. Displacement efficiencies with the processes tested to date have been between 35 percent and 55 percent as confirmed by Carbon/Oxygen (C/o) logging measurements. A final caustic flood is being conducted on a portion of the original pattern and preparations are underway to conduct a final wet combustion test on the second pattern. Casing has been set on the first well of a three hnno f.... . - horizontal well pattern. Preparations are

Project Cost: Approximately $28 million to end of 1980.

"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; *New or Revised Projects 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 will drilling anticipated to start in April 1980. Current expenditures on the project total $3,059,963. 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. It is anticipated that all wells will be completed in September, 1980.

Project Cost: Total cost $8.25 million

VACA TAR SAND PROJECT - Chanslor Western Oil and Development Company (Santa Fe Energy Company) Proposed commercial steamflood or cyclic steam recovery project located near Camarillo, California in Ventura County. The Project consists of two phases. Phase I will be construction of a pilot project consisting of drilling up to 20 wells over a 30-month period. Both cyclic steam and steamflooding techniques will be tested at this time. Phase II would be a commercial phase consisting of an additional 100 wells with a production of 2,080 BPD. Project life is estimated at 20 to 22 years. This project is currently in the permit acquisition stage.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-51 RECENT OIL SANDS PUBLICATIONS

Adam, D.G. and B.O. Regensburg, "Oil Sands Mining by Draglines," presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980. Baker, "Differences in the Composition of Soils Under Open and Canopy Conditions at Two Sites Close-in to the Great Canadian Oil Sands Operation, Fort McMurray, Alberta;" AOSERP Report Series 97: September 1980. Barnes, D.J. and M.B. Dusseault, "The Consequences of Diagenesis on the Geotechnical Behavior of Oil Sands," presented at the 3rd International Symposium on Water-Rock Interaction," Edmonton, Alberta, July 14-24, 1980.

*Barrett, R.J., "Projected Cost of the Combustion Process in Utah Tar Sand," presented at the Spring meeting of the Interstate Oil Compact Commission, Vail, Colorado, June 16, 1980, preprint LA-UR-80-1583. *Boon, J.A., "An Experimental-Statistical Study of Mineral Transformations During In-Situ Recovery of Bitumen from Various Oil Sands Deposits in Alberta, Canada," presented at the 3rd International Symposium on Water-Rock Interaction, Edmonton, Alberta, July 14-24, 1980. *Brooker, E. W., "Geotechnical Frontiers in Oil Sand Mining," Technical Paper No. 80-4, presented to IMEC 1 80 Calgary, EBA Engineering Consultants Ltd., Calgary, Canada. Bunger, J.W., and H.M. Wells, "Economic Evaluation of Oil Shale and Tar Sands Located in the State of Utah," prepared by the State College of Mines & Mineral Industries, University of Utah, for the Division of State Lands, State of Utah, September 1980. *Camp, Fred W., "Hot Water Extraction-Process Principles," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, September 10, 1980. Camp, Fred W., "Overview and Perspective," presented at the Tar Sands and 0,1 Shale Symposium, Salt Lake City, September 10, 1980. *Camp, J. and M. Supple, "Oil Sands Mining by Bucketwheels," presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980. Carrigy, M.A.,"The Role of Bituminous Sands in Extending the Petroleum Era Beyond 2000 A.D.," presented at the 26th International Geological Congress, Paris, France, July 7-17, 1980. Czaja, E.J., "Mining the Oil Sands," presented at the Canadian Society of Petroleum Geologists' 1980 Convention, Calgary, Alberta, September, 1980. Davitt, H. James, "Economics and Operations," presented at the Tar Sands and Oil Shale Symposium," Salt Lake City, September 10, 1980 Davitt, H. James, "Environmental Concerns in Tailings Disposal," presented at the Tar Sands and Oil Shale Symposium, Salt Lake City, September 10, 1980. Dick, Richard A. and Sheldon P. Wimpfen, "Oil Mining," Scientific American, October 1980, Vol. 243(4). Dobson, Warren F., and Daniel R. Seelye, "Mining Technology Assists Oil Recovery from Wyoming Field," presented at the 55th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME, Dallas, Texas, September 21-24, 1980, SPE 9418. Dussealt, Maurice B., "Sample Disturbance in Athabasca Oil Sand," The Journal of Canadian Petroleum Technology, p. 85, April-June, 1980, Montreal, Energy Resources Conservation Board, "Alberta's Energy Resources, A Summary," ERCB Report 80-32, December 31, 1979. Gomez Bueno, C.O., et al., "Physical and Chemical Characterization of Athabasca Tar Sands Fly Ash," CM Bulletin, p. 147, August 1980. *Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-52 RECENT PUBLICATIONS - OIL SANDS Hall, E.S. and E.L. Tollelson, 'Recovery of Residual Bitumen from the Aqueous Tailings from Hot Water Extraction of Oil Sands by Air Sparging," presented to the First International Conference on the Future of Heavy Crudes and Tar Sands, Energy Processing/Canada, September-October 1980, p. 39. Hamilton, T.S., "Primrose Pilot Hydrothermal Studies Program," presented at the 3rd International Symposium on Water- Rock Interaction, Edmonton, Alberta, July 14-24, 1980. Harrison, D.B., "Geology and Project Description of the Cold Lake In Situ Oil Sands Project," presented at the Canadian Society of Petroleum Geologists' 1980 Convention, Calgary, Alberta, September, 1980.

Jansen, G.F. and D.W. Savory, "Design and Development of Oil Sands Mining,' presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980. Jantizie, T., et al., "Response of Confined Aquatic Biota to Mine Depressurization Water in Beaver Creek Reservior," Environmental Research Report 1980-2, A Public Service of Syncrude Canada, Ltd. *Lillo, H. and B. Prasad, "Oil Sands Overview and Its Role in Meeting Canada's Energy Needs," presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980. McLeod, John G.F., "Numerical Simulation of the Behaviour of Enriched Gas Injected Alternately with Water in Horizontal Miscible Floods," The Journal of Canadian Petroleum Technology, April-June 1980, p. 51, Montreal. McMillan, J.C., "The Challenge of Financing Canadian Oil Sands Development," Energy Processing/Canada, September- October 1980, p. 24. Moughamian, 1M., et al., "Simulation and Design of Steam Drive in a Vertical Reservoir," Society of Petroleum Engineers of AIME, SPE 9451. Nagendran, 3., "Oil Recovery and Recycle Water Treatment for In Situ Oil Sand Production," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. *Rountree, Russ, "Conoco Oil Mine New Technique to Produce Shallow Sands," Western Oil Reporter, p. 118, August 1980. *Sahuquet, Bernard C. and Jerome J. Ferrier, "Steam Drive Pilot in a Fractured Carbonated Reservoir LACQ Superior Field," Society of Petroleum Engineers of AIME, SPE 9453.

Shori, A., "Reclamation of Oil Sands Mines," presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980.

Slawson, P.R., et al. "Dispersion Modeling of a Plume in the Tar Sands Area," Environmental Research Report 1980-1, A Public Service of Syncrude Canada Ltd.

Strausz, O.P., "Recent Advances in the Geochemistry of Oil Sands and Oil Shales," presented at the 26th International Geological Congress, Paris, France, July 7-17, 1980. *Thakur, P.C., and H.D. Dahl, "Horizontal Drilling—A Tool for Improved Productivity," presented at the 1980 SME of AIME Fall Meeting, Minneapolis, Minnesota, October 22-24, 1980, Preprint No. 80-396. U.S. Department of Energy, "Analysis of Reservoir Pretreatment in Chemical Flooding: A Literature Review," Topical Report, Fossil Energy, July 1980, report number DOE/BC! 10027-I1.

*U.S. Department of Energy, "Analysis of the Environmental Control Technology for Tar Sand Development," Fossil Energy, June 1979, report number COO-4043-2.

U.S. Department of Energy, "Big Muddy Field Low Tension Flood Demonstration Project - Second Annual Report, April 1979-March 1980," Fossil Energy, August 1980, report number DOE/SF/014214-26. U.S. Department of Energy, "Bodcau in Situ Combustion Project," Third Annual Report -- July I, 1978-August 31, 1979, Fossil Energy, August 1980, report number DOE/ET/12057-6. U.S. Department of Energy, "Development and Field esting of a Process for Recovering Heavy Crude Oil in the Carlyle Pool--Allen County, Kansas Using the Vapor THERM Generator—Final Report," Fossil Energy, September 1980, report number DOE/BETC-2880-I. -Reviewed in this issue

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 3-53 RECENT PUBLICATONS - OIL SANDS -U.S. Department of Energy, "Environmental Regulations Handbook for Enhanced Oil Recovery," Fossil Energy, August 1980, report number DOE/BC/00050-15.

U.S. Department of Energy, "Flow in Porous Media, Phase Behavior and Ultralow Interfacial Tensions: Mechanisms of Enhanced Petroleum Recovery,' Annual Report, July 1978-July 1979, Fossil Energy, August 1980, report number DOE/BC/lU 116-8. U.S. Department of Energy, "Foam as an Agent to Reduce Gravity Override Effect During Gas Injection in Oil Reservoirs,' Final Report, Fossil Energy, August 1980, report number DOE/ET/12056-Tl.

U.S. Department of Energy, "Hydroprocessing of Heavy Oils," Quarterly Technical Progress Report, September 4- December 3, 1979, Fossil Energy, February 1980, report number SAN-10760-1. U.S. Department of Energy, "Improved Polymers for Enhanced Oil Recovery Synthesis and Rheology," Second Annual Report, Fossil Energy, June 1980, report number DOE/BETC/5603-10. -U.S. Department of Energy, "1980 Annual Heavy Oil/EOR Contractor Presentations--Proceedings,' presented at the Sheraton-Palace Hotel, San Francisco, CA, July 22-24, 1980, published September 1980, report number CONF-800750. U.S. Department of Energy, "North Burbank Unit Tertiary Recovery Pilot Test,' Final Report, Fossil Energy, June 1980, report number DOE/ET/13067-60. U.S. Department of Energy, "Proceedings of the Symposium on Technology of Enhanced Oil Recovery in the Year 2000," Fossil Energy, July 1980, report number DOE/ET/2628-1.

U.S. Department of Energy, Bartlesville Energy Technology Center, "Technical Constraints Limiting Application of Enhanced Oil Recovery Techniques to Petroleum Production in the United States," report number DOE/BETC/RI-80/4 published May 1980, Revised-September 1980.

U.S. Department of Energy, "Tertiary Oil Recovery Processes-Annual Report," October 1978-September 1979, Fossil Energy, August 1980, report number DOE/BC/20001-6.

U.S. Department of Energy, "Williams Holding Lease Steamflood Demonstration Project Cat Canyon Oil Field," Third Progress Report for July 1978-November 1979, Fossil Energy, June 1980, report number DOE/SAN/I 188-4. *Van Der Knapp, Willem and S.A. Maraven, 11M-6 Steam Drive Project Preliminary Result of a Large Scale Field Test," Society of Petroleum Enegineers of AIME, SPE 9452.

Venkatram, "Evaluation of the Effect of Convection on Plume Behavior in the AOSERP Study Area;" AOSERP Report Series 95: September 1980.

-Waxman, M.H., et al., "Peace River Tar Flow Experiments Under In Situ Conditions," Society of Petroleum Engineers of AIME, SPE 9511.

*Waxman, M.H., et at., "Thermal Alterations of Asphaltenes in Peace River Tars," Societ y of Petroleum Engineers of AIME, SPE 9510. Werth, F.W., "Application of Dredging to Oil Sands Mining," presented at the International Mining Conference, Calgary, Alberta, August 26-28, 1980. OIL SANDS - PATENTS

Botts, Elton M. - Inventor, U.S. Patent 4,214,628, July 29, 1980, "Multiple-Purpose Underground Fluid Injection System." A system for injecting fluid into underground formations for various purposes including the secondary and tertiary recovery of oil or other hydrocarbons from underground formations. The system includes a unique injector capable of gravity flow injection or pressure injection by use of a pump arrangement with the gravity flow of fluids such as water enabling turbines to be utilized in the flow path at a point having the necessary water head and pressure characteristics to rotate a generator for providing electrical energy to power certain components of the equipment or for use in any manner desired.

*Reviewed in this issue

3-54 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 OIL SANDS - PATENTS

Energy Mines and Resources Canada, Ramaswarni Ranganathan, et al. - Inventors, U.S. 4,214,977, July 29, 1980, "Hydrocracking of Heavy Oils Using Iron Coal Catalyst." An improved process is described for the hydrocracking of heavy hydrocarbon oil, such as oils extracted from tar sands. The charge oil in the presence of an excess of hydrogen is passed through a tubular hydrocracking zone, and the effluent emerging from the top of the zone is separated into a gaseous stream containing a wide boiling range material and a liquid stream containing heavy hydrocarbons. According to the novel feature, the charge oil is in the form of a slurry together with an iron-coal catalyst. The presence of this catalyst in the charge oil serves to greatly reduce coke precursors, such as benzene and pentane insolubles, and thereby prevent the formation of carbonaceous deposits in the reaction zone.

Gulf Research & Development Company, John A. Paraskos, et al. - Inventors, U.S. Patent 4,217,202, August 12, 1980, "Process for Selective Recovery of Relatively Metals-Free Bitumen from Tar Sand Using a Halogenated Aliphatic Solvent in Combination with a Second Solvent." A process for the selective recovery of tar sand bitumen from tar sands using a two-solvent system comprising a halogenated aliphatic solvent in combination with a second solvent selected from an oxygenated compound. The process provides for an inexpensive method for selectively removing substantially metal-free tar sand bitumen from tar sands. The bitumen so recovered renders the same amenable to catalytic desulfurization and upgrading processes.

Hanson, Lester - Inventor, U.S. Patent 4,216,999, August 12, 1980, "Machine for Mining Tar Sands Having Rearwardly Directed Exhaust Related to Conveyor Trough." The present invention presents a new improved machine, suitable for mining tar sands and other soft materials such as soft coal, oil shale and so forth. The machine can be used both above ground and below ground. Underground mining use of the machine is particularly suitable since the tar sands will not freeze up when the mining function is accomplished below-grade. The machine itself has a cutting face comprising a series of cutting heads that may be rotated in the same direction, revolve at the same speed, and intermesh so as to provide for an effective solid cutting surface. The machine is provided with air compressor means to blow cuttings rearwardly of the machine through a trough. The deck or primary plate of the machine can be adjusted for incline or decline so that a variety of mining functions can be accomplished. The track drives are provided with means of advancing the machine forwardly, rearwardly, turning the same about a vertical axis, or indeed turning the machine in any desired manner. This is accomplished by a pair of variable speed motors, with gear boxes, that are supplied for driving the respective track drives on the opposite sides of the machine.

Kureha Kagaku Kohyo Kabushiki Kaisha, Nihonbashi; Chiyoda Chemical Engineering & Construction Co., Yokohama, both of Japan, Nakanishi, 1-lajime Makanishi, et al. - Inventors, U.S. Patent 4,214,979, July 29, 1980, "Method of Thermally Cracking Heavy Petroleum Oil." Disclosed herein is a method of thermally cracking a heavy petroleum oil by introducing the heavy petroleum oil into a reactor and contacting the heavy petroleum oil thus introduced with a gas, which does not react with the heavy petroleum oil, at a temperature of 400 0 - 2000°C, thereby thermally cracking the heavy petroleum oil. The method uses plural reactors and introduces the heavy petroleum oil into the reactors in a specified manner, and charges the reactor in advance with a specified amount of heavy petroleum oil of a specified temperature.

Petroleum Recovery Insititute, Phillip M. Sigmund, et al. - Inventors, U.S. Patent 4,217,955, "Oil Recovery Process." The recovery of oil from a subterranean hydrocarbon-bearing reservoir by the injection of a mixture of carbon dioxide and sulfur dioxide which is miscible with the reservoir oil at pressure and temperature prevailing in the reservoir. For production a driving fluid is then injected to displace the zone and reservoir oil and fluids for recovery. Posomarev, Jury V., et al. U.S. Patent 4,211,606, July 8, 1980, "Method for Thermal Processing Bitumen-Containing Materials and Device for Realization of same." Bitumen-containing material is processed by distillation with a solid heat- carrier with subsequent gasification of the distillation residue and combustion of the gasification residue in an aerofountain furnace. During gasification, the formed flue gas and ash are heated and part of the ash is used as the heat- carrier. The flue gas and ash are withdrawn from the process simultaneously in the form of their suspension in air, from which the heat-carrier is isolated for the distillation process, the consumption of the heat-carrier being controlled by withdrawing part of the suspension containing fine fraction of ash before the heat-carrier is isolated. The device for realization of the proposed method comprises an aerofountain furnace and is provided with a means for delivering the heat-carrier into the reactor, which is actually a separator with leading-in and leading-out gas ducts and a by-pass gas- duct provided with a controlled valve intended to control the delivery of the aerosuspension through the bypass gas-duct. Texaco, Inc., Joseph C. Allen, et al. - Inventor, U.S. Patent 4,210,205, July 1, 1980, "Secondary Recovery Process." Significant improvement in the recovery of hydrocarbons from a subterranean hydrocarbon-bearing calcareous formation is accomplished by injecting into the formation via an injection well drilled into a formation communicating with an adjacent producing well and containing acid-soluble components which may or may not have water-sensitive clays and shales included, a composition comprising an aqueous solution of a mineral acid having dissolved therein a small amount of a vinyl pyr rolidone terpolymer solution whereupon the acid solution reacts with the acid-soluble components of the formation creating passageways or enlarging existing passageways thus facilitating the flow of fluids and thereby increasing the recovery of hydrocarbons from the formation through the adjacent producing well. Optionally, the injected composition may be saturated with natural gas at the injection pressure.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 OIL SANDS - PATENTS Texaco Inc., Ricardo L. Carenas, et al. - Inventors, U.S. Patent 4,213,500, July 22, 1980, "Oil Recovery Process: Injection of Fatty Alcohol Followed By Soap." An oil recovery process comprising injecting a fatty alcohol into the oil phase of the reservoir followed by the injection of a soap which effectively emulsifies the oil-fatty alcohol mixture followed by further water injection to displace and produce the emulsified oil. Texaco Inc., Charles A. Christopher, Jr., et al. - Inventors, U.S. Patent 4,210,204, July I, 1980, "Method for Plugging High Permeability Zones in Subterranean Reservoirs." Fresh water solutions of pectic materials are injected into high permeability zones in the subterranean reservoir. These materials upon contact with brine solutions form thick gels for the purpose of reducing the permeability of these high permeability zones thereby improving the vertical conformance efficiency of flooding operations within the reservoir. Texaco Inc., Wilbur L. Hall - Inventor, U.S. Patent 4,212,353, July 15, 1980, "Hydraulic Mining Technique for Recovering Bitumen from Tar Sand Deposit." Viscous petroleum including bitumen may be recovered from unconsolidated sand formations such as tar sand deposits by hydraulic mining. Hot water or steam and an amine are introduced into the subterranean deposit with sufficient velocity to dislodge bitumen and particles of sand. The process is a single wellbore operation using a rotatable vertically moveable injection string with one or more jets near the bottom, with separate return flow path to surface, the inlet to which may be on the bottom of the injection string. The injection string may be raised or lowered while rotating and jetting so the full vertical thickness of tar sand interval is contacted by aqueous mining fluid. Jet pumps may be used to pump petroleum to surface. The aqueous hydraulic mining fluid comprises hot water or steam and an amine having the following formula: R 1R2R3 wherein R 1 and R are each hydrogen or a C 1 to C and preferably a C 2 to C 0 alkyl, linear or branched and R 3 is an alkyl, alkyl, linear or linear or branched having from 3 to 20 and preferably 4 to 12, or R 1 is--R 4NII, wherein R 0 is a C 2 to CIR branched, and preferably 3 to 11, the sum of carbon atoms in R 1 , 1Z 2, and R 3 being from ito 20 and prererably from 7 to 13. Texaco Inc., Wilbur L. Hall, et al. - Inventors, U.S. Patent 4,207,945, June 17, 1980, "Recovering Petroleum from Subterranean Formations." A process for enhanced recovery of petroleum from subterranean formations wherein a vapor mixture of steam and a petroleum fraction containing naturally occurring phenolic and carboxylic compounds is injected via an injection well, and a mixture of steam condensate and petroleum is produced via a production well.

Texaco Inc., Warren C. Haltmar, et al. - Inventors, U.S. Patent 4,207 1946, July 17, 1980, "Tertiary Recovery Process." A process for recovering hydrocarbons from a hydrocarbon-bearing formation penetrated by an injection well and a production well which comprises injecting an aqueous solution of a vinlypyrrolidone polymer into the formation to condition the reservoir, in a first step injecting an aqueous surfactant solution into the formation and recovering hydrocarbons via the said production well. The pretreatment of the formation with the vinylpyrrolidone polymer reduces the consumption or loss of surfactant and thus improves the efficiency of the process. Optionally, after the injection of the aqueous surfactant solution an aqueous drive fluid is injected into the formation. Texaco Inc., George Kalfoglou - Inventor, U.S. Patent 4,219,082, August 26, 1980, "Lignosulfonate-Formaldehyde Condensation Products as Additives in Oil Recovery Processes Involving Chemical Recovery Agents." A process for producing petroleum from subterranean formations is disclosed wherein production from the formation is obtained by driving a fluid from an injection well to a production well. The process involves injecting via the injection well into the formation an aqueous solution of Iignosulfonate-formaldehyde condensation products as a sacrificial agent to inhibit the deposition of surfactant and/or polymer on the reservoir matrix. The process may best be carried out by injecting the lignosulfonate-formaldehyde condensation products into the formation through the injection well mixed with either a polymer, a surfactant solution and/or a micellar dispersion. This mixture would then be followed by a drive fluid such as water to push the chemicals to the production well. Texaco Inc., Vernon H. Schlevelbein - Inventor, U.S. Patent 4,217,997, August 19, 1980, "Oil Recovery Method." Petroleum is extracted from a subterranean reservoir by injecting into injection wells an aqueous surfactant solution wherein the surfactant is a mixture of mono- and di-alkyl benzene polyethoxy alkyl sulfonates wherein the alkyl group contains the same number of carbon atoms in both components of the surfactant, driving the surfactant solution through the reservoir and recovering petroleum from production wells penetrating the reservoir. The fluid composition of the surfactant mixture is also claimed. Texaco Canada Inc., Michael J. Goss, et al. - Inventors, U.S. Patent 4,217,956, August 19, 1980, "Method of In Situ Recovery of Viscous Oils or Bitumen Utilizing a Thermal Recovery Fluid and Carbon Dioxide." A method for the in situ recovery of viscous oils or bitumen from subterranean oil-bearing formations by the injection of steam or a mixture of steam and an oxygen-containing gas under operating conditions that utilize pressurization and drawdown cycles wherein carbon dioxide is injected at the start of the pressurization cycle.

3.56 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 OIL SANDS - PATENTS

Ube Industries, Ltd., Michiharu Nakayasu, et al. - Inventors, U.S. Patent ,208,180, June 17, 1980, "Mixed-Firing Burners for Use with Pulverized Coal and Heavy Oil." A heavy oil supply pipe, a protective pipe, an air supply pipe for burning heavy oil, a coal-air supply pipe, a coolant supply pipe and a protective caster are arranged concentrically in the order mentioned. A coal whirler and an air whirler are provided to impart whirling motions to coal flame and heavy oil flame for thoroughly admixing them.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 357 oic "m \ COE1LJIL PROJECT ACTIVITIES

GREAT PLAINS COAL GASIFICATION PROJECT UNDERWAY according to Mike Mujadin, manager of process engineer- ing for American Natural Resources Company, lead partner of the Great Plains Consortium. Site grading and preliminary construction work began on July 25, for the Great Plains Gasification Project near The study centers on the design of the boilers that will Beulah, North Dakota. Additional encouragement was produce steam for the gasification process. In one of the given to the project in November when DOE gave initial stages of the process, carbon dioxide is removed conditional approval of a $1.5 billion loan guarantee. This new commitment includes the $250 million loan in a stream that also contains burnable hydrocarbons. guarantee previously reported in the September 1980, The current design calls for burning this stream in the Cameron Synthetic Fuels Report. boilers. This would make full use of the hydrocarbons but would contaminate the carbon dioxide. However, if the stream is sold for oil recovery, the boilers will need Bids had been received for the required 14 steel pressure to burn an alternate fuel. vessels necessary for the project and originally were awarded to Hitachi Limited of Japan as the low bidder. The question of whether the plant's carbon dioxide can After much objection from American firms and Con- be usefully employed also depends on the cost of trans- gressmen, Great Plains, in consultation with the Depart- porting the CO by pipeline to wells in the Williston ment of Energy, decided that the job should be divided Basin oil and gas production area of North Dakota and between the low bid American firm, Chicago Bridge and Montana. Iron Company (Cm), and the Japanese,CBI was awarded a contract for seven of the vessels. The gasification plant could produce up to 200 million cubic feet of carbon dioxide daily. The amount of Agreement Signed With Basin Electric additional oil that could be recovered with a set amount ANG Coal Gasification Company and Basin Electric of carbon dioxide varies greatly from reservoir to reser- Power Cooperative signed an agreement in October voir, but a recent American Gas Association study suggests that 66.4 billion cubic feet of CO2 -- the plant's covering joint use of common water gathering and distri- annual carbon dioxide production if it is found to be bution facilities, coal mine and coal-handling facilities, recoverable -- could add some 8.3 million barrels of and a railroad spur. See page 4-1, of the June 1980 otherwise unrecoverable oil to the nation's reserves. Cameron Synthetic Fuels Report for a review of the (See the Technology Section for a review of this study). water assessment for the plant. The agreement was negotiated in 1979 but was delayed until the project was assured of its financing. American Natural Resources Chairman Arthur R. Seder, Jr., who strongly encouraged the CO study, said that the trailblazing Great Plains plant can be expected to The agreement provides that Basin Electric will supply answer dozens of scientific questions about synthetic primary power to the gasification plant at rates based on cost of service from the Antelope Valley station. ANG, fuel production. "The projects's research and develop- in turn, will sell coal fines too small for the gasification ment prospects are among its greatest attractions. Not process to Basin for fueling its power plant. The fines only will we learn a great deal about the production of synthetic natural gas and possible valuable by-products, will constitute about 50 percent of the coal requirements but we will also learn valuable lessons on how to convert of the power plant. Great Plains will provide its own coal to liquid fuels,'he said. process steam and supplemental power needs, using by- products of the gasification plant for fuel. ill/I/il Design of Plant Modified to Include Methanol Production SRC-IITSL COMMERCIAL PLANT ECONOMICS PRESENTED Great Plains also announced in October that the plant design had been modified to produce methanol from coal. Originally, the project would have purchased up to 17 Under a contract with the Department of Energy, Inter- national Coal Refining Co. (ICRC) is planning to tons per day of methanol to clean the raw gas stream of impurities. Cost of transporting methanol to the plant construct and operate a 6000 ton per day SRC-I Demon- stration Plant in Newman, Kentucky. (For a detailed site and storing it were sufficiently high to warrant the description of the SRC-I agreement refer to page 4-2 in design change. American Natural applied to DOE for a the September 1980 Cameron Synthetic Fuels Report.) $2.6 million grant to fund further research into gasoline production from coal-derived methanol. Data from. this Under the terms of the agreement, ICRC will invest $90 research, along with the information collected during million in the project, the Commonwealth of Kentucky methanol production for Great Plains, will be a basis for will invest $30 million, and the DOE will fund the large-scale conversion of methanol to gasoline plant. balance. The contract states that ICRC will eventually own the coal refinery after buying out the federal and Possible Design Changes to Utilize CO Production state governments' interest. At that time, ICRC plans to expand the facility fivefold to 30,000 tpd. Since the Engineers are also studying the feasibility of recovering signing of the cost-sharing agreement, Alcoa and Cities carbon dioxide, a by-product of the gasification process,

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-1

Services Co. have agreed in principle to become minority Solid-Liquid Separation Techniques Evaluated partners of ICRC. Operations at the Demonstration Plant are due to commence by late 1984, with expansion The Kerr-McGee Critical Solvent Deashing Process was to a 30,000 ton per day commercial capacity scheduled chosen over the Lummus Antisolvent Deashing Process for 1990. ICRC initially prepared the conceptual design, and mechanical methods for ash separation. The Kerr- preliminary cost estimates, marketing assessments, McGee CSD is a solvent extraction process which pro- economic evaluation and environmental assessments. duces a fine powder which is fed to the gasifier to The project has entered the detailed engineering phase, generate hydrogen. The process is operated at condi- and the selection of major technologies for both the tions near the critical point of the deashing solvent for Demonstration Plant and the Commercial Plant has been which two liquids phases are formed. Filtration, based completed. A discussion of the criteria upon which these on U.S. vertical leaf filters, appeared promising, but was decisions were based was presented by John C. Tao at ultimately eliminated because it operated in a batch the Seventh Annual International Conference on Coal mode, has high maintenance requirements, and subjects Gasification, Liquefaction, and Conversion to Electricity workers to a potential exposure to heavy hydrocarbons. held at the University of Pittsburgh, on August 5, 1980. The Lummus Process, an agglomerative sedimentation The paper was entitled "Demonstration and Commer- process, has not yet demonstrated a sustained operation cialization of the SRC-1 Technology." that produces an acceptably low ash in the overflow and a high enough (70 percent plus) SRC recovery. The objective of the 6000 tpd Demonstration Plant is to demonstrate the technical feasibility, economic via- GKT Process Will Produce Hydrogen bility, and environmental acceptability of the SRC-1 process. Figure I shows a block diagram of major Evaluations were made of Texaco, Gesellschaft fur processes to be included at the facility. In selecting Kohle Technologies (GKT) -formerly known as Koppers- major technologies for the Demonstration Plant, four Totzek, and Shell Koppers Coal Gasification Process for processing steps were considered and analyzed as producing hydrogen for the SRC Process from a mixture follows: (1) Deashing, (2) Gasification of Mineral Ash of filter cake and coal. This step has not been piloted in Residue for the Production of Hydrogen, (3) Product any of the four coal liquefaction pilot plants including Cooling or Solidification of SRC, and (4) Expanded-Bed SRC-I at Wilsonville, Alabama; SRC-11 at Tacoma, Wash- Hydrocracking to convert the SRC to Liquid Fuels. ington; Exxon Donor Solvent at Baytown, Texas; and H-

-P + P ruso't ANODE COKE -1-i c' TOT SOLID EXPANDED SOLID I RED COKING! C RAC KER [CALCTN F-1 COAL 1 1

DR Y SIZEDC OAL COAL ETC I PREPARATION PR OCESS I MOLTEN SRC

HP N, PRODUCT RECYCLE RICH GAS S LuRRY HYDROGEN

'CYC LE I ACID GAS r I SAC TREAT MENT SET sthFUR DEASII INIS RECOVERY —L C4PHESEION I I

AIR KERR MCGEE API MAKEUP CONCENTRATE HYDROGEN 500 DAY

MAICESJP GAS 1 AIR OXYOTN TREATMENT SZFARAT ION GASIFICATION AND FAIR SYNTHESIS GAS

INERT SLAG

FIGURE 1 SRC-I DEMONSTRATION PLANT PROCESS FLOW DIAGRAM

4-2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Coal at Cattlettsburg, Kentucky. The GKT Process has The stream is divided into multiple streams which are been recommended for use in the Demonstration Plant then dropped into the solidifier through cylindrical because of the potential uncertainties in the characteris- nozzles at a height about 6 to 12 inches above the water tics of the ash concentrate feedstock, and the develop- surface. ment or demonstration status of the alternate choices was considered insufficient. In the solidifier, the denser pitch is cooled and solidified into rods as it falls through the water bath. The water Mitsui-Miike Process Chosen for Solidification flows upward countercurrent to the pitch. At the bottom of the solidifier vessel, the solid pitch is trans- The alternatives considered for solidification of the ferred by the screw conveyor to the bucket conveyor SRC-1 were Rexnord indirect cooling in a small batch on located outside the vessel. The bucket conveyor trans- vibrating trays, Sandvik indirect cooling on a continuous fers the solid pitch to the screen conveyor where water moving belt, and Mitsui-Miike direct contact cooling by is removed. Product pitch is then transferred to a injection into a water bath. In both indirect cooling storage via belt conveyor(s). processes, molten SRC is sprayed under open atmos- pheric conditions onto a metal surface where it is The process water, which cools and solidifies the SRC, is indirectly cooled with water. Currently, Wilsonville uses supplied by the submerged circulation pump in the water a vibrating tray. pit. The process water, which contains fines, is cooled in the process water cooler against cooling water. It is The Mitsui-Miike Process has not been used in the U.S., then injected into the solidifier at the bottom section of but ICRC hopes to demonstrate the technical feasibility the vessel through multiple nozzles. Most of the process of the process at Wilsonville. A flow diagram of the water returns to the water pit via overflow ports at the process is shown in Figure 2. top of the solidifier vessel. Water separated by the screen conveyor and a small fines purge stream from the The Mitsui-Miike Process cools and solidifies SRC by bottom of the bucket conveyor is also returned to the direct contact with water. Because it has not been used pit. Due to vaporization which occurs in the solidifier, in the U.S. up to now, the Mitsui-Miike Process is makeup water is required and it is introduced into the discussed in detail here. Figure 2 represents a schematic solidifier below the process water inlets. flow diagram of the process. Fines are generated in the process primarily by crushing The hot molten SRC (pitch) is first cooled against and attrition in the conveying equipment, especially in Dowtherm in the pitch cooler. The extent of the cooling the screw conveyor. They are removed from the system depends on the softening point and viscosity of the pitch. by sending a slip stream of the recycle process water to

PITCH + COOLER BUCKET •SRC CONVEYOR

"PITCH') SCREEN t CONVEYOR lOt' BELT CONVEYOR

MAKEUP WATER nSRC

CONVEYOR

SRC I FINES PIT FINES 44 SEPARATION

FIGURE 2 MITSUI WATER-BATH SOLIDIFICATION

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-3 the fines separation unit. The separation can be Two-Stage Liquefaction Analyzed achieved by either centrifugation or sedimentation. The clarified water is returned to the water pit for reuse. An Sac-I facility would produce approximately 75 wt There is no water treatment required except fines sepa- percent of its product as Classic SRC Solid and the ration. remaining 25 wt percent as a range of liquid products. A Two-Stage Liquefaction facility based on low severity Although the Rexnord cooler is the most economical and hydrocracking would produce approximately 40 wt per- technically proven process, the Mitsui-Miike process is cent of the product as TSL Solids and 60 wt percent as simpler with more compact design and lower fume liquid products. A high severity hydrocracker would generation. result in only 10 wt percent of TSL Solids and 90 wt percent of liquids. Expanded-Bed Hydrocracking Added For Flexibilit The ultimate selection of the Commercial Plant configu- An expanded-bed catalytic hydrocracker will be incor- ration will be determined by market forecasts for the porated into the Plant to obtain maximum product various products. While the decision is still several years flexibility through conversion of the SRC-1 Solids to away, the analyses of Two-Stage Liquefaction facilities liquid products. The Demonstration Plant will be have already been performed for both low severity designed to test two proposals. The first, is to run two- hydrocracking and for high severity hydrocracking. thirds of the SRC-I Solid through the hydrocracker at 50 percent conversion to minus 850°F products (Two Stage A schematic of a Commercial TSL Plant in which all the Liquefaction or TSL) with the remaining 50 percent of SRC is processed through a hydrocracker at high severity the solid produced as low sulfur solids (TSL Solids). The is shown in Figure 3. This configuration is based on a second proposal, requested by DOE, will make only one- Shell-Koppers Gasification Unit for makeup hydrogen. third SRC-1 Solid available to the hydrocracker to be As shown in the figure, approximately two-thirds of the converted at 85 percent severity to naphtha and fuel oils product oils are produced in the hydrocracker with the below 850°F. The economic attraction of both conver- remaining one-third produced in the SRC Liquefaction sions is essentially the same with higher capital and Unit. operating costs being offset by the higher value of the lighter product slate. The primary benefit for further Figure 4 shows the Commercial Plant Schematic based processing of the SRC-I Solid, is the resulting reduction on low severity hydrocracking. As less hydrogen is in sulfur content (approximately .80 percent for SRC-1 required, a larger fraction of the coal is sent to the SRC Solids versus .21 percent for TSL Solids). In order to Unit, making this unit slightly larger than is called for in produce these low sulfur solids, the proposed hydro- the high severity design, however, the hydrogen gasifier cracker will use Lummus/Cities Service LC-Fining Tech- is substantially smaller. For the low severity design, nology. approximately half the product oils are produced in the

PRODUCT . 400°F OILS { 2,475 TPSD C5 2,031 TPSD 400- 650°F 416 TPSD 650-850°F FUELLPG GAS 1 31,6 SRC LPG 0 RAW EFACTION 1,176MM BTU (HHV)/HR. OAL AND SRC ASHING14 774 TPSD PR::UCT 1,699 TPSD C5- 400°F TPSD 400-650°F 999 TPSD 650-850°F MSCFD ...u...... _I4IHYDROCRACKER SRC 7,578 TPSD MAKEUP HYDROGEN I71141MMScFD ol 2,752 DROGEN'—I CT ION

FIGURE 4 SRC-I WITH LOW SEVERITY HYDROCRACKING

4-4 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 1

COST AND ENERGY COMPARISONS TSL FACILITIES

High Severity Low Severity Hydrocracking Hydrocracking

Feed (TPD) 30,000 30,000 Output, High Heating Value (MM Stu/Day) LPG 68,000 28.000 NAPHTHA (C 5 - 655°F) 240,000 165,000 MEDIUM OIL (400 0 - 655°F) 230,000 175,000 HEAVY OIL (650 0 - 850°F) 54,000 51,000 TSL SOLIDS 48,000 246,000 640,000 665,000 Input, High Heating Value (MM Btu/Day)

COAL 850,000 850,000 ELECTRICITY 125,000 96,000 975,000 946,000 Overall Efficiency 65.6% 70.3% Total Project Cost (MM$) $ 3,570 $ 3,25 Annual Operating Cost ($) $ 1,295 $ 1,160 -

TABLE 2 CAPITAL COST SUMMARY (Cost in MM $, de-escalated to 1980 onstrearn)

High Severity Low Severity Hydrocracking Hydrocracking

SRC liquefaction and deashing $ 640 $ 685 Expanded-bed hydrocracking 515 355 Hydrogen production and treatment 760 605 Utilities, ofisites and coal preparation 460 455 Subtotal plant and equipment 2,375 2,090 License fees, 1 land, initial catalysts and chemicals 80 70 Contingency 490 430 Interest during construction 320 280 start-up costs 140 110 Working capital 165 145 Total project cost $ 3,570 $ 3,125

I. Paid out to third parties

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-5

TABLE 3 OPERATING COST SUMMARY (Cost in MM $, dc-escalated to 1980 onstream)

High Severity Hydrocracking Low Severity Hydrocracking Item Quantity Annual cost 2 Quantity Annual Cost2

Goal @ 51.30/MM Btu 33,333 TPSD 365 33,333 TPSD 365 Power @ 50.034/kwh 548,000 kw 145 422,000 kw 115 Catalysts and chemicals -- 55 45 Maintenance materials -- 60 -- 50 Operating and 1,645 persons 100 1,455 persons 85 maintenance labor

Subtotal 725 660 Capital charges 16% of project cost 570 500 Total 1,295 1,160 I. Assumes start-up in 1990 and 20-year operating life. 2. 328.5 days/yr onstream 3. Based on 65% debt, 35% equity, 20% contingency on capital, 15% discounted cash flow, 9% interest rate on debt 4. includes manpower allowances for vacations and sick leave, fringe benefits, plant supervision, and overhead

TABLE 4

FINANCIAL ANALYSIS (Cost in S/MM Btu, 1980 $) High Severity Low Severity Hydrocracking Hydrocracking

Total Btu produced, MMM Btufyr 210,330 218.538 Average required price, 1 S/MM Btu $ 6.15 $ 5.30 Solid SRC cost, 2 5/MM Btu 3.25 3,25 Average cost of liquid fuels produced, 3 $/MM Btu 6.40 6.50 Average market value of liquid fuels produced, S/MM Btu 6.95 6.75

I. Derived from annual operating cost presented in Table 3 and total Btu produced. 2. Derived from evaluation of investment and operating cost for a stand-alone SRC Plant constructed without an expanded-bed hydrocracker. Market value of liquid products was based on the following unit prices in 1980 $: Naphtha—$7.69/MM Btu. The above prices were forecast for 1990 by Air Products and Chemicals, Inc., and de-escalated to a 1980 basis. Value of SRC solids established by difference.

3. Established by difference after setting value of TSL Solids equivalent to value of SRC as described in the paper by G. C. Rappe, "An Evaluation of Solids Separation Techniques in Coal Liquids,' at the International Conference on Solids Separations in Dublin, Ireland, April 17, 1980.

4-6 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 PRODUCT OILS 2,252 TPSO C5 - 400°F 1,845 TPSD 400- 650°F 378 TPSD 650 - 850°F FUEL GAS 28,754 TPSD (MF) 0 RAW ...... n._.p LIQUE FACTION LPG COAL AND SRC 2,851 MM BTU (HHV)/HR. DEASHING 13,427 T ASH PRODUCT 3,830 TPSD C5 - 400°F OILS CONCENTRATE 261 300 MMSC FD ' 4,486 TPSD 400 - 650°F 7,773 TPSD MMSCFD (1,121 TPSD 650- 850°F HYDROCRACKER SRC ,4,579 TPSD (ME) MAKEUP 1,466 TPSD HYDROGEN

HYDROGEN CT ION1

r,uIJtlt a SRC-I WITH HIGH SEVERITY HYDROCRACKING

hydrocracker along with 7578+ IPSO of TSL Solids. A program to operate a FLEXICOKING* prototype on Table I summarizes the cost and energy comparisons, EDS vacuum bottoms feed is also underway. Part I, assuming start-up in 1990, a 20-year operating life, and engineering design studies, (5.6 M$) was approved by the costs de-escalated to 1980 onstream of both high sever- project sponsors. Part II of this $69 million program, ity and low severity hydrocracking. revamp and operation of the 750 5/0 FLEXICOKING' unit, is being supported by the U.S. Department of Table 2 shows a capital cost summary for the major Energy - 50 percent, Exxon - 36 percent, JCLD - 8 sections of the plant for both degrees of hydrocracking, percent, Atlantic Richfield - 2 percent, and Ruhrkohle - while the summary of operating costs are shown in Table 2 percent, AGIP - 2 percent. Field construction is 3. These costs have also been de-escalated to a 1980 projected to begin the second quarter of 1981, with onstream date. After start-up in 1990, the plant is mechanical completion during the third quarter of 1982. assumed to have a 20-year operating life. These costs Exxon USA will operate the plant for IS months on are based on a typical operating year having a 90 percent vacuum bottoms generated in a 250 TPD coal liquefac- onstream factor or 328-1/2 days per year onstream. tion pilot plant. The first bottoms run in the Prototype will be from Illinois No. 6 coal. Pilot plant evaluation A financial analysis was required to determine whether of partial oxidation as a second bottoms process is also the value of the products was adequate to permit the being considered. rate of return specified. A summary of that analysis is presented in Table 4. B. T. Wade of Exxon presented an update of the Project at the Electric Power Research conference in October. fl//I/il According to the presentation, integrated operations began on the 250 T/D Exxon Coal Liquefaction pilot EXXON ADDS NEW PARTNER FOR THE DONOR plant, (ECLP), June 24. "The first run continued 5 days SOLVENT PROJECT when coal feed was halted to make modifications to alleviate several minor mechanical problems. The AGIP, a subsidiary of the Italian State Petroleum Co., longest run to date had been 21 days. The coal-in factor has been added to the list of participants in the Exxon has been 47 percent versus a target of 50 percent, and Donor Solvent Project. Funding for the $296 million the unit has logged over 1000 hours of coal in operation Program is proportioned as follows: DOE - 50 percent, as of the end of September. The unit has operated on -8 Exxon Company, USA - 22 percent, Electric Power mesh coal at 4 percent coal moisture content, and the Research Institute - 12 percent, Japan Coal Liquefaction slurry and vacuum tower furnaces and atmospheric and Development Co. - 8 percent, Phillips Petroleum Co - 2 vacuum towers have been operated at their design heat percent. Atlantic Richfield - 2 percent, Ruhrkohle - 2 fluxes and flash zone temperatures. The goal of testing percent, and AGIP - 2 percent. the limits of operability in these sections has yet to be

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-7 attempted. No process problems have been identified, but experience thus far has identified four mechanical areas which have posed some operating difficulty. "Erosion has proven to be a problem in the transfer line between the vacuum tower and vacuum preheat furnace. A 90 0 elbow in the line eroded through July 31 and resulted in termination of Run 2 after a total of 26 days of coal-in operation. X-rays of the "Flooded 1" replace- ment indicate that it is subject to unexceptably high rates of metal loss. "The eroded "1" and downstream portion of the transfer tine is slated for replacement by refractory lined piping. The metal fiber reinforced refractory system is the same as that successfully tested in a pipe spool already installed in a high velocity segment of the transfer line as part of the equipment component test program. "Reciprocating pump packing life is a continuing con- cern. Proper choice of packing materials and careful installation are required. Plans are being made to spare the two most troublesome pumps that are in atmospheric bottoms service with a centrifugal pumping system. "The lack of Dowtherm heater capacity has plagued the entire operation. The existing Dowtherm furnace output is about five times smaller than is needed for startup. As a result, the vacuum separation section is difficult to start up and relatively intolerant to upset. To alleviate this problem, a new Oowtherm furnace was installed and commissioned on September 19. It is expected that this furnace will provide the necessary Dowtherm capacity to handle startup needs and permit flexibility in responding to upsets. "The final area experiencing difficulties is the coal preparation unit. Problems with the prepared coal feeder belt on the gas-swept mill system have hampered operations. While aggravating, this problem is not felt to be critical. Separately, the coal slurry drier heat exchanger is experiencing severe plugging and fouling. After two trial fixes, it has been concluded that the existing multipass horizontal exchanger should be replaced with four singlepass vertical exchangers. The exchangers themselves are expected to be delivered late this month. Procurement of the necessary block valves may delay installation until 1981." ft//fill

4-8 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 ENVIRONMENT

TVA MEDIUM BTU COAL GASIFICATION Draft Environmental Impact Statement Compares the DEMONSTRATION PLANT DRAFT EIS RELEASED Processes In October 1979, the Tennessee Valley Authority (TVA) The Draft Environmental Impact Statement (EIS) for the requested proposals for Phase I, the conceptual design of project was released on August 1, 1980. It was prepared a coal gasification plant capable of processing up to in parallel with the conceptual design effort and will 20,000 tons of coal feedstock per day. The TVA project serve as a planning document wherein the possible envi- will provide synthetic gas for industrial development ronmental impacts of the proposed coal gasification consistent with TVAs economic development responsi- facility are evaluated at alternate sites. Major design bilities in the area and will develop a capability for alternatives, such as the selection of the gasification future generation of TVA power and steam consistent process, are assessed. The EIS, along with other perti- with the TVA Act. nent technical and economic information, will be used to decide whether to proceed with the project. By comple- The TVA Act of 1933 explicitly assigned to TVA the ting the EIS at this point in the project, management authority to conduct studies, experiments, and demon- decisions regarding the future of this action will be strations to assist the Tennessee Valley region and based on an understanding of the environmental as well adjoining territory. According to a TVA fact sheet, the as the economic consequences of the project. TVA is the only Federal agency with the capability of demonstrating nationally the viability of a commercial- As part of the environmental review process, public sized coal gasification plant at an early date. input was encouraged in scoping the contents of the EIS. Two public meetings were conducted by TVA in the In determining what process to use for the Medium-Btu vicinity of the preferred site, and opportunity was pro- plan, TVA evaluated a broad spectrum of technologies vided to the public to express their concerns through and identified eight processes which were thought to be written or verbal statements including TVAs toll-free technically ready. The eight gasification process telephone Citizen Action Lines. Over 200 people vendors were given TVA's objectives and technical data responded during the EIS scoping process. A synopsis of and were asked whether their processes should be consi- these comments was prepared and used in development dered for the project. Five responded affirmatively. of the EIS scope. These processes fall into two general classes: The environmental consequences of each of the five Entrained Bed--Coal particles are carried processes were compared using the following criteria-- along by the gas in concurrent flow, similar solid waste disposal, wastewater treatment, presence of to a conventional pulverized coal-fired hazardous compounds, water requirements, and auxiliary boiler. coal burn requirements. In general, the Babcock & Wilcox (B&W), Koppers-Totzek (K-T), and the Texaco Fixed Bed--A bed of coal moves counter to processes were determined to be more environmentally the gas stream, producing discrete tempera- acceptable than the Lurgi and slagging-Lurgi processes. ture zones. We have included the entire Appendix B, "Waste Of the five technologies considered, three of them, Characteristics and Flow Diagrams" from the Draft EIS Babcock & Wilcox, Koppers-Totzek, and Texaco are in the Appendix of this report for a more detailed entrained bed gasifiers. The remaining two processes, presentation. While some of these technologies have Lurgi dry-ash and the British Gas Corporation's slagging been operating overseas for a number of years, little Lurgi, are fixed bed systems. attention has been given to characterizing waste products. Ten firms meeting TVA's participation requirements in replying to the personal service contract request were While available technical data were generally sufficient asked to submit proposals for the proposed plant. The to determine the potential impacts and to compare the ten firms were: Babcock Constructors, Bechtel, C.F. acceptability of the processes, the level of detail regard- Braun, Davy-Mckee, Ebasco, Fluor, Foster Wheeler, ing potential discharges and waste products needs Parsons, Pullman-Kellogg, and Stearns-Roger, Inc. expanding. TVA will collect and analyze environmental data as part of its operational readiness test program. Bechtel National, Inc., C.F. Braun Co.1 and Foster These data will expand the effluent characterization Wheeler Energy Corporation were awarded a total of data base and will assist in the design and permitting $2.7 million for conceptual design studies incorporating process. the five different coal gasification processes. Each contractor evaluated at least three of the five processes The EPA is developing regulatory guidance for the for a total of eleven conceptual designs. environmental control technology to be employed at synthetic fuels production facilities. As a part of this A summary of the utility requirements and material effort, conceptual design recommendations for medium- balances for the five processes is given in Table 1. A Stu coal gasification plants are being formulated. (See consistent design basis was used, consequently there article on page I-Il, General Section, that describes the were no significant differences in certain parameters. Pollution Control Guidance Documents).

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-9 TABLE I SUMMARY OF GASIFIER UTILITY REQUIREMENTS AND MATERIAL BALANCES

Lurgi Lurgi Evaluation Factors K-I Texaco B&W dry ash Power consumption, MW 11311 91 256 162 76 Auxiliary Boiler Coal Feed Rate T/D i,Boo 1,300 900 14500 2,400 Make up Water Requirements gpm 16,900 24,400 16,000 31,000 15,000 Gasifier slag, l/D 990 3,040 2,580 -- 3,250 Gasifier Ash, lID 3,070' -- 860 3,250 -- Tars ------(recycled to gasifier) Oils, BID -- -- 1,620 1,830 Phenol, T/D ------53 81 Ammonia, lID ------252 57 llaptha, B/D ------2,080 1,351

*Ash from the K-T gasifier is a fly ash-like slag particle

Gasification Technology Evaluated for Each of the Pro- TVA coal will be tested at an existing K-T, two-headed lects commercial gasifier in Ptolemais, Greece, to confirm the design parameters for the TVA application. The five alternative gasification technologies considered Effluents will be sampled at that time to support the for the project were discussed in detail in the EIS. Each design of appropriate environmental control systems. process was described, and unique characteristics Tests should be completed in February 1981. presented. The technical risks associated with each technology and the opportunities available for testing Texaco Utilizes Heavy Oil Experience for Coal Gasifica- TVA coal at a significant scale were discussed. tion The technical and environmental evaluations of the five The risks in the Texaco Process are concentrated in the processes indicated that the Texaco or the Koppers- subsystems involving coal preparation, gasification and Totzek (K-fl would minimize potential health and envi- heat removal where coal slag is present. Texaco has had ronmental impacts. These processes also offer signifi- extensive commercial experience in gasifying heavy oil, cant advantages for the gasification of the eastern coals but has not commercially gasified coal. Recovery of that TVA plans to use. high temperature steam from the slag-laden raw product gas, scale-up of the gasifier by a factor of about IC and Design Parameters of Ko ppers-Totzek to be Tested in preparation of a high concentration coal-water slurry Greece - using TVA coal are among the most serious technical risks. Other risks involve the long-term reliability of The K-T is a commercially used technology. The instrumentation, controls, and materials. primary risks associated with it are applying the process to the specific TVA coals under U.S. technical, environ- Several large-scale test facilities are available to mental, and economic constraints. Most of the resolve some of these risks prior to design and/or opera- experience overseas is with a two-headed gasifier design, tion of the TVA plant. The 150-ton per day Ruhr- but economics suggest that four-headed design with Chemie plant in Oberhausen-Holten, Germany, is now higher throughput should be used for the TVA applica- operating for test purposes and has a heat recovery tion. There has been limited experience in India with the system similar to that proposed for the TVA plant. TVA four-headed design. coal will be tested there, as well as at TVA's own 150 ton-per-day ammonia-from-coal plant at Muscle Shoals, Alabama.

4-10 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Commercial Demonstration Necessary for Latest Fifteen Sites Considered in the Site Screenin Babcock and Wilcox Design g Process Siting studies were initially limited to reviews of 11 The B&W gasifier was developed and tested on pilot and previously identified sites within potentially promising semi-commercial scale units in the 1950's, but the market areas for medium-Btu gas. As additional infor- efforts were discontinued, and the facilities no longer mation became available indicating that the north exist. None of these units were operated under the Alabama area showed a greater potential for developing pressure and capacity now being proposed. The new a coal gas market, four additional site areas in that B&W gasifier design, however, is based on B&Ws exten- sive pulverized coal technology base. region were identified and reviewed. Of the sites considered, the TVA-owned Murphy Hill site in Marshall County, Alabama, was selected as the preferred loca- The list of technical risks reflect the fact that the tion. The vehicle used for conducting the siting studies proposed design is based on successful integration of was an interdisciplinary siting working group (SWG) com- many concepts some of which have not been commer- prised of a number of disciplines including engineers, cially demonstrated. This includes special large-scale chemists, biologists, and regional planners. Site reviews heat exchangers, dense phase coal feed, particulate included assessments of engineering and environmental removal, raw gas compression, and control systems. concerns in each potential site area. With no existing facilities to test TVA coal at a commer- Site screening activities were based on generic coal cial or semi-commercial scale, it does not appear gasification plant parameters and were not tied to a possible to overcome these risks in time to support the specific process with definitive design information or TVA schedule. known effluent levels. The assumption was made that the control of effluents from a coal gasification facility Lurgi Dry Ash Needs Further Development for Eastern Caking Coals could be tailored to fit Federal or State regulatory requirements. Site areas were therefore reviewed from the standpoint of air quality increment availability or Based on successful commercial experience at the Lurgi, maximum emissions allowable in a given area. Consider- especially in South Africa, the dry ash Lurgi is generally ation was also given to potential water and solid waste regarded as the most desirable process for noncaking constraints. For siting purposes, the following plant coals when substitute natural gas or fuel gas is desired. parameters and assumptions were used: TVA application, however, will use eastern caking coals. S Economic Life of Facility - 35-40 years. The major technical risks associated with use of the dry (Some of the equipment may have a shorter ash Lurgi in the TVA application involve the reliability life and would require replacement. The of coal stirrers particularly at the large size proposed to remainder of the document assumes a 20- handle caking coals, and the recycle of fines, tars, and year plant life.) oils and disposal of other byproducts in an environ- mentally acceptable manner. While solutions to these • Product - Medium-Stu Gas of approximately problems have been proposed, they have not yet been 300 Btu/SCF proven in an integrated system at commercial or semi- commercial scale. • Coal Use - approximately 20,000 tons/day; four 5,000 tons/day modules To rectify the situation, Lurgi has begun a program to modify one of the Mark IV gasifier units at SASOL (South • Coal Delivery and Source - by barge and/or Africa) to test caking coals at a commercial scale. This rail, primarily from western Kentucky and unit should be available for testing in the spring of 1981. southern Illinois British Gas Corporation/Lurgi Slagging Gasifier Poses • Water Intake - approximately 50 cfs (22,220 Similar Risks to Conventional Lurgi gpm)

According to the EIS, the risks associated with the • Water Discharge - two scenarios: British Gas Corporation/ Lurgi Slagging Gasifier techno- logy are essentially similar to those associated with 1. Continuous Discharge of 10 cfs operating the conventional Lurgi on eastern U.S. coals 2. Closed-Cycle Cooling, 0 Discharge plus the risks associated with long-term full-scale opera- tion of the gasifier in a slagging mode. For a detailed • Solid Waste Disposal Requirements 750 - to description of the British Gas Corporation/Lurgi Slagging 900-acre feet/year Gasifier, see the article in the Foreign'Section of this Report. • Optional Auxilliary Coal Burn, 200 - to 400- MW equivalent. A 600 to 700 ton-per-day gasifier is being built by British Gas for operation in the fall of 1982, so that long term Based on the above factors, minimum site requirements semi-commercial testing would not be possible until late included approximately 1,000 to 2,000 acres of land; 1982. available air quality increment; accessibility by barge, rail, and highway; sufficient water supplies; and suffi- cient market for the product gas. All of these factors given above provided the basic criteria for site

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-I1

r\ 1L LKmJN T U A -- sin — - sr., SITE 9N I

SITE Ill

N, 9 si - SITI CaflT SITE 50 SIT 4

• 1 A7tARTA LI (fl". ( .

IIUUKt 1 POTENTIAL SITE AREAS FOR TVA COAL GASIFICATION PROJECT

I2 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 I,

2 C —J 0. IL' I.- Ca,

., C 'Th z ?2fl{Jf / ) \ •J\ '% •P \l —j \- Iii U 2A . ','• L Cdt

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-13 screening, which lead to selecting for interdisciplinary The selected scenarios encompass varying coal produc- review an initial II potential site areas, shown in Figure tion levels, mining methods, coal transportation modes, I on the previous page, dispersed throughout the TVA and development levels. North Kaiparowits, South Kai- region. parowits and Alton lease areas were studied and are identified in Figure 1, following, along with possible The Murphy Hill, Alabama site is the preferred site for transportation routes. the plant because it appears to result in the lowest overall economic cost of the sites evaluated and because AIR QUALITY it offers important environmental advantages in the areas of solid waste disposal and air quality. Figure 2, Under each study scenario, modeling results indicated shows the preliminary site plan for the plant. that unmitigated emissions would violate National Ambient Air Quality Standards (NAAQS) and Prevention This site was purchased as a potential nuclear power of Significant Deterioration (PSD) increments for total plant site in 1973 and has been in TVA's inventory since suspended particulates (TSP). Mitigation of 88 percent then. In September 1979, the TVA Board stated that for would be sufficient to meet air quality standards for all the foreseeable future additional nuclear reactors, if areas at a low production level, but for medium and high any, would be limited to sites that already had reactors production levels, South Kaiparowits and Alton would installed. Consequently, the Murphy Hill site was freed require additional mitigation at up to 96 percent and 94 for consideration of nonnuclear uses. percent respectively. According to study projections, air quality violations are not anticipated from non-TSP Plans call for site preparation to begin in the spring of pollutants. 1981 with operation of the first gasifier module scheduled to begin in 1985. VISIBILITY

Comment An increase in TSP concentrations under medium and high production levels produces visibility reduction that TVA Chief, S. David Freeman has predicted that the particularly effects the viewing range from Bryce Point plant will be the first commercial coal conversion plant to Navajo Mountain (shown in Figure 1). With 88 percent completed. If development continues at the rate that it mitigation, visual range would be reduced from 200 to has in the past year, he would be right. The fact that 109 km (124-68 mi) which represents a 12 percent TVA has not been involved with the Department of reduction. Navajo Mountain would be visible 50 percent Energy has contributed to the speed. In addition, the EIS of the time as compared to 75-85 percent of the time at follows the guidelines set by the EPA very closely. See present. the article in the General Section on EPA's meeting in Denver on page 1-14, as well as the article on the SRC-II WATER RESOURCES EIS in the Coal Section of this Quarterly. The TVA EIS, in fact, would be a good model for any of the other The Upper Colorado River Basin Compact of 1943 limits proposed coal conversion projects. Not every project has Utah's allotment of surface water from the Upper $2.7 million at its disposal to investigate all the alter- Colorado River Basin to about 1,700,000 acre-feet per native technologies, however, as TVA spent in its year. Almost all available surface water has been analysis. The environmentalists have also chosen to not appropriated. Viable sources of water supply for coal tangle with TVA, which will increase the speed of production are limited to Lake Powell and to ground- development. water. In the Alton and North Kaiparowits lease areas, surface water is almost fully appropriated and ground- water from the Navajo Sandstone appears to be the most viable source of water supply. The Navajo Sandstone is the major aquifer underlying the coal lease areas which FINAL REPORT ON ENVIRONMENTAL IMPACT OF contains substantial quantities of groundwater and is KAIPAROWITS COAL DEVELOPMENT RELEASED relatively undeveloped. Recharge rates to this aquifer are unknown but are thought to be low. The chemical The "Kaiparowits Coal Development and Transportation quality of the groundwater appears to be consistently Study" which was published August I, 1980, resulted good, varying from 500 to 1000 mg/I total dissolved from an agreement made by the Secretary of the Interior solids. Although the potential exists for development of and Governor Scott Matheson of Utah for a cooperative groundwater from the Navajo Sandstone in the South study by the Department and the State of Utah to review Kaiparowits lease area, economic feasibility greatly the issues raised by potential mining and transportation favors the use of surface water from Lake Powell. of coal from the Kaiparaowits Plateau. In contrast to an EIS, the study does not evaluate specific proposed Impacts on groundwater quality and quantity would not actions, but rather summarizes the potential environ- be significantly affected at a low production level. mental impacts of various levels of coal development However at higher production levels, the construction of and various modes of coal transportation from the Kai- railroads and slurry pipelines would result in temporary parowits region. The three scenarios are shown in Table increases in runoff and sediment. A potential pipeline I. The scenarios were analyzed, and based on the rupture could adversely affect water quality in streams conclusions, six major environmental elements were receiving the discharge. The operation of a coal slurry identified as areas of potentially significant impact. The pipeline would affect the groundwater stored in the elements include air quality, visibility, water resources, Navajo Sandstone. In the Alton lease area, water level wilderness resources, transportation, and socio- drawdown in the immediate vicinity of the well field economics.

4-14 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

SALINE - 17 MILES

AN No AN AN AN NA ME S I ,t MILFORD / •,' S Ill I t Ill S I , 2' I I I STUDY AREA BOUNDARY I - — I eeeeeeeeee

NORTH / KAIPAROWITS • I / I i 1 I ' I ;' NORTH I I , I t ._ KAIPAROWITS I • I ' I'.._. \ I • 3 ' ti, I I Is CEDAR CITY • I I • , / t :-Ltt • I • ,, /i SOUTH • ,,. / : KAIPAROWITS ij : / "fi, €PARK ZION I S I% Ls. PARK1 tr,1 : / NAVAJO LLE /?ic••J'U • '' / u---- \ SITE U T A H I _. rc1h c,y_ -, I '.0 A R I Z 0 NA C

I / STATION I------/ L ------STUDY AREA BOUNDARY

KEY MAP I\ t CORRIDOR BOUNDARY I't TRUCK HAUL ROUTE UTAH • GENERAL COAL. • LEASE AREA SOUHOART POTENTIAL ACCESS ROAD I ARIZON

TO FLAGSTAFF - MILES 75 MILES KILOMETERS 10 5 0 '0

FIGURE I KAIPAROWITS COAL DEVELOPMENT MAP

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-15 TABLE 1 STUDY SCENARIOS Coal Pro guction Transportation Lease Area (10 Tlyr.) Mining Methoc' Mode

Alton 2 surface truck North Kalparowits 1 underground truck South Kaiparowits 2 underground truck TOTAL 5 Medium Level Alton 9' surface & underground slurry pipeline North Kaiparowits 15b surface & underground slurry pipeline South Kaiparowits 30 underground rail TOTAL 54 High Level Alton 9 surface & underground slurry pipeline North Kalparowits 30c surface & underground rail South Kaiparowlts 45 underground rail TOTAL 84

Source: ERT Project Team Years

Years 1-20 all surface mining Year 21, 75% surface, 25% underground Year 22, 50% surface, 50% underground Year 23, 25% surface. 75% underground Years 24-40. all underground mining

2 million tons/year surface mining C3 million tonsiyoar surface mining would reach 350 feet after 40 years of pumping. Increasing coal production results in increasing levels of Regional effect would be a 1-foot drawdown extending traffic, which results in reduced operating speeds and to a 11.8-mile radius from either of the well fields back-ups during peak hours. The combined impact of analyzed. This drawdown would eventually reduce flow coal development traffic with recreation and miscel- by 25 percent to 50 percent in the East Fork of the laneous travel would gradually exceed Utah Department Virgin River and reduce output or interrupt flows in of Transportation Standards for Level of Service. Unit Johnson Canyon Springs. Under medium production coal operations would result in traffic flow delays and conditions in the North Kaiparowits area, drawdown create a potential for vehicle-train accidents. The study would reach 450 feet after 40 years of pumping. The I- projects that increased accident occurance would range foot cone of depresson would extend an estimated radius from 125 to 370 additional accidents per year for low of 12.7 miles. Due to decreased water requirements level through high level coal production plans. under the high production scenario, this radius would extend only 10.9 miles in the North Kaiparowits area. SOCIOECONOMICS Overall drawdown in Navajo Sandstone would not affect shallower aquifers and would not affect existing wells. Communities in the study area utilize substantially less than one percent of the land area for residential and WILDERNESS RESOURCES supporting urban uses. Cedar City is the only community in the study area with an "urban" character. Other The designation of Wilderness areas either within or communities are typically rural residential clusters, surrounding the study area will significantly affect the many of which contain substantially more agricultural development of the Kaiparowits coal leases. Such land and land classified as vacant than residential or wilderness areas would be unavailable for use as rights- other 'urban" land. of-way unless and until they were released from wilder- ness classification. Kane and Garfield counties comprise the bulk of the study area and a large majority of the population of the TRANSPORTATION two counties resides within the study area such that county-wide socioeconomic impacts would largely be The existing system of roadways in southcentral Utah is impacts on the defined study area. Although much of oriented towards through traffic movement and access the socioeconomics discussion focuses on these two between the few existing population centers. The counties, other portions address the entire five-county, physical structure of the roadway system is character- southwestern Utah planning reki'on comprised of Beaver, ized by alignments which have been determined by the Garfied, Iron, Kane, and Washington Counties, because topography of the area and the relative location of the socioeconoic data base is more complete for the population centers. region than for individual counties.

4-16 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Baseline population projections for southwest Utah with- out coal development show a steady growth. The distri- faction pilot plants. The report also assesses the health bution of employment in the region is expected to and process aspects of coal liquefaction technology. The significantly shift by the year 2000, with a major decline report is entitled, "Coal Liquefaction: Recent Findings in agriculture being offset by increases in manufacturing in Occupational Safety and Health." and trade. Population increases with coal development In 1975, would range as high as 26 times greater than baseline NIOSH, together with DOE, EPA, and the projections, and occur in a 5 to 8 year period. The most National Institute of Environmental Health Sciences, extreme growth example would be the assumed New initiated a research program which consisted of the Town on East Clark Bench where no current population following work (some of which is still in progress): exists. The New Town is projected at 45,315 people by • the year 2000 under the high coal development scenario. An occupational hazard assessment for coal liquefaction pilot plants; Significant positive socioeconomic effects would occur • as a result of Kaiparowits Coal development. These An industrial hygiene characterization of benefits vary with production levels and include creation coal gasification plants; of new permanent jobs (1,990 - 21,600 in mining and coal • transportation), a boost to the area economy from direct A medical monitoring protocol for new salaries and wages ($35 million to $413 million annually), energy industries; and finally, Kane and Garfield Counties would experience operating revenue surpluses. • An industrial hygiene characterization of direct coal liquefaction plants; and Significant negative socioeconomic effects would be as follows: Current residents on fixed incomes would be • A control technology assessment of coal gasi- adversely affected by above average price increases for fication and liquefaction processes, which goods and services; highway maintenance requirements will include related technology from other would increase substantially; county level capital industries. improvements needs would be accelerated. All communities affected by coal related growth would Samples were obtained at two facilities; one used the experience significant revenue shortfalls at current tax donor solvent (DS) process and the other donor solvent/- rates, some would require doubling projected revenues to catalytic hydrogenation (DS/CH) process. Although a maintain service levels; many communities would face limited number of personal and area samples were taken, the data characterize worker exposure in these facili- significant capital improvements needs, in particular, ties. water system, waste water treatment and school needs would have to be in place prior to population growth which would pose significant "front-end" financing Area samples taken at the two facilities were qualita- problems; areas affected by transportation facilities tively compared for organic materials with a computer construction in Beaver and Washington Counties would data base of known compounds. PNA's, benzene, tolu- experience short-term, "boom bust" conditions due to ene, xylene, and aromatic amines were present in the construction activities. workplace environment, and the degree of worker expo- sure to airborne contaminants at the two coal liquefac- Although the "Kaiparowits Coal Development and Trans- tion pilot plants was determined. A discussion of the portation Study" thoroughly examines the environmental workers exposure to various potentially hazardous sub- impact based on a series of scenarios and projections, stances follows: significant data gaps remain which could potentially alter the environmental constraints. Identification of ?Plynuclear Aromatic Hydrocarbons Were Present in Air important unknowns and determination of possible pes and Process Streams environmental fatal flaws is necessary to assure timely, responsible and efficient project development. Exposures were determined for 29 PNA's for which analytically pure standards were available. Total PNA The elements analyzed in the Kaiparowits study are exposure of workers at the two facilities was determined significant, because already two California Utilities (San as the sum of the concentration of 29 PNA's. In general, PNA exposure was greater for workers of the DS Diego Gas & Electric and Southern California Edison) process. have announced preliminary plans to mine 10.5 million tons of coal annually from the Kaiparowits Plateau by 1988. The coal would be transported by slurry line to Of the PNA's found in the air samples, 97 percent were two California sites, where it would be gasified for use two- and three-ring PNA's; 3 percent were four- and in the southern part of the state. five-ring PNA's. The two- and three-ring PNA's are not currently known to be carcinogens whereas some of the II f/I//I four- and five-ring PNA's are considered potent carcino- gens. PNA's were observed in the process streams of the NIOSH ASSESSES HEALTH ASPECTS OF COAL two facilities. Quantitative analysis of one plant showed LIQUEFACTION the two- and three-ring PNA's ranged from 85 to 90 percent; the balance were four- and five-ring com- The National Institute for Occupational Safety and pounds. The predominance of these low molecular Health (NIOSH) has issued a report which includes the weight PNAs in air samples could be due to their higher results of industrial hygiene studies at two coal lique- volatility relative to the higher molecular weight PNA's.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-17 Benzene. Toluene, and Xylene (BTX) Levels Were Low materials known to be produced in coke oven and coal tar processes, which have been associated with a higher Exposure levels for field technicians at the OS plant cancer risk. Other potential adverse health effects were less than 0.02 ppm for benzene, 0.1 ppm for associated with constituent chemicals in coal liquefac- toluene, and 0.04 ppm for xylene. At the DS/CH tion products include acute effects from inhalation, facility, area samples indicated that the concentration severe respiratory irritation, and chemical and thermal of these low molecular weight aromatics were of the burns, lire and explosion hazards are assumed to be same order of magnitude or lower. In all cases, potentially significant, as most coal liquefaction pro- measured BTX levels were lower than current OSHA cesses operate at high temperature and pressure and standards. contain flammable materials. Aromatic Amines Present at Low Levels The longest exposure period for U.S. workers for whom health effects have been reported is said to be approxi- Worker exposure was determined for seven aromatic mately I years. In this case no systemic cancers were amines for which OSHA standards exist. These amines reported, but basal cell carcinomas reportedly occurred included aniline and its three derivatives, o-toluidine, on exposed parts of the body (lip, ear, and nose) in 3 of and o-and p-anisidine. Exposure to o-toluidine and to 190 employees. However, the significance of these cases aniline and its derivatives was of the same order of is questionable because of the small number of magnitude at the two facilities, with exposure levels less employees involved and the lack of reference data than 0.1 ppm. A comparison with current OSHA stan- available at the time. These data are currently being dards indicates that the measured levels were lower than acquired by plant personnel. the standards. Foreign plants have operated for a number of years Particulates Ranged from 0.7 to 10mg/m (from 1927 to 1945 in Germany, and from 1955 to the present in South Africa), but no epidemiologic studies Particulates were sampled at the coal preparatioi area. have been undertaken. The Sasol coal gasification/lique- Total particulates ranged from 0.7 to 10 mg/ni The faction plant at Sasolburg, South Africa, is presently the respirable dust levels ranged from 0.1 to 1.4-mg/rn (less largest commercial process in operation; it has been than 3 percent silico3 dioxide)-. The OSHA coal dust operating for over 23 years and currently employs appro- standard is 2.4 mg/m (respirable fraction less than 5 ximately 5,600 workers. After NIOSI-I personnel visited percent silicon dioxide). The Mine Safety and Health the Lurgi gasification and tar handling sections of the Administration3(MSHA) standard for respirable coal-mine plant and discussed health problems with the plant dust is 2 mg/m doctor and workers, they reported that skin cancer was not observed among the gasifier and gas clean-up crew, Heat Stress and Radiation Were at Background Levels nor among the workers of the coal tar separators. However, it was indicated that the plant record keeping All high-temperature equipment was insulated. did not include chronic disease such as cancer, and Measurements of gross alpha, beta, and gamma radiation follow-up studies on workers were not undertaken. at these facilities were determined to be at background levels. It II II 1/ Noise Was Generally Below 85 d&A A noise survey of the facilities was conducted with a Type 2 sound-level meter. Levels were below 90 dBA and most areas were below 85 ElBA. Health Aspects Assessed The report concedes that only limited information exists on the effects of occupational exposure to coat liquefac- tion materials because most work in the United States has been with bench-scale units and pilot plants, which have minimum processing capacity and minimum opera- ting time. The number of operating pilot plants and the number of workers employed at these plants are small. The report contends, however, that coal liquefaction materials contain potentially hazardous and biologically active substances. Many of these materials have not been characterized as to their composition and/or health effects. Although some of the available information has demonstrated a direct association between coal liquefac- tion materials and carcinogenicity, NIOSH believes that future investigations may find a greater occupational hazard than is currently documented in the literature. This belief arises from the apparent similarities of those

4-18 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 GOVERNMENT

DOE AND EPA REACH AGREEMENT ON SRC-11 EIS In addition, before a draft or final Environmental Impact Statement is transmitted to the Environmental Protec- The Draft Environmental Impact Statement for the Sol- tion Agency (EPA) for filing and notification in the vent Refined Coal (SRC-11) Demonstration Plant was Federal Register, the Assistant Secretary for the Envi- issued May 26, 1980. (See page 4-36 of the September ronment must specifically approve its acceptability for Cameron Synthetic Fuels Report for a review of the publication. Draft EIS). Public hearings were held on June 30 and July I, and the comment period ended on July 30. As the Fumich also established an Environmental Task Force, first EIS for a DOE synthetic fuels demonstration pro- responsible for ensuring that guidance issued at Head- ject, the draft elicited comments from 47 individuals and quarters is incorporated into the EIS by the field offices, organizations. Hearings before the House Subcommittee and for insuring timely compliance with NEPA by the on Energy Development and Applications of the Commit- Office of Fossil Energy. The Task Force is also respon- tee on Science and Technology were also scheduled. sible for making sure that proper planning is done for all necessary preconstruction regulatory approvals. At the hearings on September 19, George Fumich, Jr., Assistant Secretary for Fossil Energy for the DOE Cost Increases Likely From Delay Caused By EIS reviewed the DOE organization for preparing an EIS for fossil energy demonstration plants and the relative roles In his testimony, Fumich addressed cost increases and of the Offices of Fossil Energy and of Environment. In schedule delays in construction of the demonstration addition, he submitted an agreement reached between plants. He agreed that a delay in the EIS process has the DOE and the Environmental Protection Agency re- critical implications for the cost and schedules of these garding the SRC-II EIS. The agreement is included in its already expensive projects. Costs of delays are entirety in the Appendix. composed primarily of two factors: (I) the cost of maintaining a project team; and (2) escalation of costs DOE Demonstration Plant EIS Preoaration Described due to inflation. Preparing environmental impact statements is the res- According to Fumich, "a general rule-of-thumb for bud- ponsibility of the Assistant Secretary. In the case of getary increases due to delay is roughly one percent per Fossil Energy demonstration projects, this is the respon- month delayed. For the Solvent-Refined-Coal plants, sibility of George Fumich, Jr. Under his direction, the with total estimated costs of approximately $1.4 billion Office of Major Projects has primary responsibility for each, this would mean an increased cost of roughly $14 the Synthetic Fuels Demonstration Program, and within million for each plant for each month's delay in comple- that office is a program office for each of the major tion of construction. However, for these particular projects. Additionally, project managers in Fossil projects, there is not sufficient design work yet to Energy's field structure are assigned to each of the develop final baseline projections for costs and sche- demonstration plants. dules. Although some cost impact from NEPA compli- ance is possible, initiating construction activities early Responsibility for implementing the contractual agree- in calendar 1981, following the issuance of the Record of ments for the Solvent-Refined-Coal demonstration Decision, will not necessarily delay the projected date of plants has been assigned to the Department's operations completion since some time might be made up during office in Oak Ridge, Tennessee; similarly the DOE construction." Chicago Operations Office has responsibility for the Memphis Fuel Gas demonstration plant. These offices, He also referred to the Memphis demonstration plant, with technical support from the Fossil Energy Techno- estimated to cost slightly more than $700 million, with logy Centers, have the primary role in preparing the construction originally scheduled for November. He Environmental Impact Statement. said, "In hindsight, this schedule failed to recognize the significant effort involved in preparing the EIS. We Steering Committees, comprised of representatives of quickly recognized this deficiency and had established a the Office of Fossil Energy Environment, General working schedule calling for completion of the EIS in Counsel and the appropriate field operations office have December with the Record of Decision occurring been established for both the gasification and lique- approximately 30 days later and a construction start in faction efforts. These committees were organized to February. Based on our experience with, and the com- provide a formal mechanism to resolve differences of ments on, the SRC-1I EIS we are now projecting an opinions arising during the preparation of the EIS's, in additional two months; that is, construction starting in order to give guidance on policy matters to the actual April." preparers of the documents. The Draft EIS for the Memphis Light, Gas and Water The Office of Environment, in addition to its participa- Division Industrial Fuel Gas Demonstration Project was tion on the liquefaction and gasification Steering issued in October, and announced in the Federal Committees, provides guidance to Fumich's office on the Register, October 31, 1980. A public meeting was full range of issues involved in compliance with NEPA scheduled for December 3, in Memphis, Tennessee. through its NEPA Affairs Division.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-19 Sheckells Explains EPA's Action Regarding SRC-11 EIS which became effective July 30, 1979. These are to effectively streamline the NEPA process by reducing Thomas Sheckells, Deputy Director of the Office of paperwork and delays to produce expedited decisions. Environmental Review of the U.S. Environmental Pro- The concept of scoping was developed by these regula- tection Agency (EPA) also spoke before the Committee tions to aid Federal agencies in early indentification and hearings to discuss EPA's role in the environmental concentration on the central issues involved. In addition, review process for synthetic fuel demonstration projects. the ability to tier an EIS on an earlier document is He described the EPA's approach for responding to the promoted to avoid duplication and allow for incorpora- Administration's energy program. tion by reference those issues not directly relevant to the decision at hand. These regulations also provide for First, an Alternate Fuels Group has been established analysis and alternative actions as part. of the EIS. "The which includes policy level officials from every major EIS," said Sheckells, "should compare the environmental program and office in EPA. The group is charged with impacts of the alternatives and provide the clear basis the responsibility of drafting and implementing an for decision." Agency-wide regulatory and research strategy for syn- thetic and other alternate fuels, and is preparing envi- He further explained, "Specifically, in the case of an EIS ronmental guidance for emerging fuels and technologies on a synthetic fuel project, three general classes of for use by industry planners and permitting officials. It alternatives must be considered. First would be site will also oversee preparation and promulgation of future selection. Among the relevant factors to be addressed environmental standards for these fuels and technologies are environmental constraints, economic implications as appropriate. The group is actively involved in each of and socio-economic impacts associated with each pro- the major synfuel technologies and helped coordinate the posed site. Of critical importance is the early identifi- SRC-11 review. cation of any environmental condition(s) which could result in possible non-compliance with Federal statutes A second effort underway has been the Permits Coor- or lead to permitting delays. Considerable time and dination Group which set up the Priority Energy Project expense can be saved through early identification of the Tracking System. The tracking system has three major most appropriate alternative. The second set of alterna- objectives: (I) establish deadlines for permitting and tives that would be addressed in an OS would be environmental reviews; (2) provide senior management mitigation measures. Of critical importance are the with timely and accurate information; and (3) and enable types of control technologies to be employed. Sufficient EPA to anticipate and resolve problems early. Initially, information must be provided to enable those reviewing the system will be used to track selected major energy the EIS to have reasonable assurances that the proposed projects such as synthetic fuel demonstration projects. controls represent the Best Available Control Techno- The two SRC projects are presently included in the logy. The third set of alternatives appropriate for system which will eventually be expanded to cover all of discussion in an EIS on a synfuels project would be the EPA's major permitting activities. Permit guidance type of synfuel technology and the scale chosen for documehts and model decision schedules are also being demonstration." developed. According to Sheckells, the third effort has been assuring appropriate and timely environmental He gave as an example, in the case of Morgantown, that review of energy projects and programs. it would be appropriate to discuss the siting decision for the demonstration facility and why the SRC-II process EPA's Environmental Review Process Described was chosen as opposed to some other coal liquefaction process. EPA's Office of Environmental Review (OER), in con- junction with the appropriate regional offices and head- He discussed the EPA's review of the Draft SRC-11 EN. quarters, carries out EPA's consulting and review respon- EPA Region III office in Philadelphia coordinated review sibilities under both the National Environmental Policy of the EIS. Numerous meetings and discussions were Act (NEPA) and Section 309 of the Clean Air Act (42 held between EPA and DOE since late 1978 to convey U.S.C. 7609). Section 309 imposes a non-discretionary EPA's advice concerning both the scope and depth of the duty on the EPA Administrator to evaluate and comment EIS as well as the requirements for Federal air, water, publicly in writing on the impacts of certain actions and other permits. being proposed by other Federal agencies. In complying with this mandate, EPA evaluates Draft Environmental SRC-111 Draft EIS Deemed Inadequate Impact Statements (ElS's) in terms of both the adequacy of the information contained in the statement and the Sheckells explained EPA's decision concerning the OS, nature of the environmental impacts associated with the "Although the draft EIS is, in our view, an improvement proposed action. EPA also provides detailed comments over earlier versions, the timing of the document --that to guide the proposing agency in preparing its final EIS is, prior to the design of several industrial processes and and in reaching its ultimate decision. The OS is the pollution control equipment -- led to the conclusion that summary documentation of the findings of the NEPA it was inadequate." process. The NEPA process should begin as soon as possible; the OS, however, should not be written until He also provided the subcommittee with a copy of the the impacts of the alternatives have been adequately EPA's Region III administrator Jack Schramm's detailed assessed, according to Sheckells. review of the draft EIS. The review covers a wide variety of areas including water useage, groundwater The Council on Environmental Quality, pursuant to monitoring and contamination, wastewater treatment, Executive Order 11991, promulgated NEPA regulations spill containment, wetlands, air quality, emission control

4-20 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 equipment, solid waste handling and disposal, site selec- fuels. The GAO expressed two concerns. First, DOE has tion, material transport and operator training. yet to develop a comprehensive program for alcohol fuels which includes appropriate plans, goals, and strate- He also stated that, "EPA also believes that a commit- gies. Second, the effectiveness of DOE's recently ment should be made at this time to prepare a supple- created Office of Alcohol Fuels may be impaired due to mental EIS after the SRC-II demonstration phase has limitations on its span of authority and responsibility been completed, but prior to deciding whether to expand and, relatedly, on the-level to which the Office reports. its capacity five-fold to commercial scale. This recom- While representing a significant step in the direction of mendation derives from the probability that several achieving a comprehensive alcohol fuels program, GAO environmental and socio-economic impacts which are not noted that the potential of methanol from coal is not significant at a demonstration scale may emerge when being considered by the Office of Alcohol Fuels. expansion takes place, while other significant impacts will be increased. A supplemental EIS after some years GAO noted that, although alcohols can be used as fuel in of operating experience would obviously provide more a number of applications, such as to fuel turbines for accurate impact assessment and would be useful to the generating electricity, their use as a substitute for government and private concerns contemplating con- conventionally produced gasoline in the transportation struction of additional coal liquefaction facilities else- sector can have the greatest impact on reducing the where. EPA will certainly provide appropriate assist- Nation's oil consumption. In this connection, nearly 40 ance to DOE if a supplemental EIS is prepared." percent of the oil consumed by the United States each year is used to produce gasoline. Based on current U.S. He commented that the Joint Meeting Memorandum (see consumption levels, about 110 billion gallons of gasoline appendix) establishes that EPA and DOE are in agree- are needed each year to power the Nation's motor ment on the application of NEPA to the SRC-11 project. vehicle fleet. Both ethanol and methanol can, to varying degrees, be substituted for gasoline thereby reducing the He assured all the Members of the Subcommittee that Nation's dependence on this oil-based fuel. EPA intended to provide all appropriate assistance to DOE and the operators of SRC-11 in meeting all environ- Accordingly, GAO looked at the potential of both fuels mental review and permitting requirements. from the perspectives of their potential production levels and use in automobiles, the state-of-the-art of Comment: Obviously, the EPA has lost sight that the production technology, and potential cost competitive- purpose of the SRC-II demonstration plant is to prove ness with gasoline. Overall, GAO found that alcohol the further scale-up of that particular process not the fuels have vast potential to substitute for conventionally Lurgi, not the K-T, not the Bergius, or the IG, but the produced gasoline. specific SRC-II process. Further, GAO contends that although much larger quan- Consequently, the EPA needs to reevaluate its stand that tities of ethanol are being produced today for fuel, alternative technologies must be addressed. As Fumich methanol's ultimate production potential as an automo- stated in his testimony, the Energy Resource and tive fuel far exceeds that of ethanol. In this connection, Development Administration Alternative Fuels Environ- vast quantities of methanol can be produced from coal mental Impact Statement provided a programmatic ana- which is in bountiful supply. Some studies have shown lysis of the potential widespread commercialization that existing coal reserves in this country, which are impacts of alternate fuel technologies, including lique- economically recoverable using current mining tech- faction and gasification. Chapter I of the SRC-11 EIS niques, are sufficient to provide a methanol production references this 1977 document. capacity equivalent to fueling the Nation's entire motor vehicle fleet for about 100 years. Moreover, DOE has When EPA asks industry to address competing technolo- estimated that nearly 42 billion gallons of ethanol could gies, they are asking for a reinvention of the wheel. be produced annually by the year 2000 with the use of When, as is the case at the Region VIII meeting where cellulose feedstocks, such as trees, agricultural residues, Wilson said that "no action" needs to be addressed, it and municipal solid waste. These same feedstocks, becomes ridiculous. If "no action" were the preferred however, can potentially be used to produce nearly 155 alternative, then the EIS would not have been needed to billion gallons of methanol. Unlike ethanol then, which begin with. will probably be limited to the role of a valuable gasoline extender, methanol could eventually be produced in Outlandish as EPA's viewpoints are, industry must not sufficient quantity to totally replace gasoline. only be cognizant of them, but must address them in the EIS or be prepared to accept delays of construction and Methanol from coal technology has also been available the one percent per month cost increase that will for years. Prior to the availability of relatively inexpen- accompany that delay. sive natural gas (which has subsequently faced periodic domestic supply shortages) as a methanol feedstock, flog,, France produced methanol from coal in the late 1940's, and in the mid-1950's the DuPont Chemical Company GAO SAYS DOE NEEDS To DEVELOP A METHANOL- operated a methanol from coal plant in the United FROM-COAL PROGRAM States. Advances which maximize the amount of metha- nol producible from a given volume of coal continue to Late in July, the General Accounting Office (GAO) sent be made. Nonetheless, industry officials told GAO that a letter to the Secretary of Energy expressing concern a commercial-sized methanol plant could, with existing over the Department of Energy's program and organiza- technology, be in operation within 5 years. tion for developing and promoting the use of alcohol

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-21 GAO pointed out that the impact on the fuel consumer "Ensure that from an organizational stand- resulting from a nationwide gasohol program, as repre- point, methanol from coal is brought into the sented by the price at the service station pump, could be mainstream of those activities aimed at slight. On the other hand, with available technology, promoting the development and use of methanol's potential production costs indicate that the alcohol fuels. This can be accomplished by price of methanol could be significantly lower than establishing an integrating mechanism, such ethanol's and, in fact, may be very competitive with as a standing committee chaired by the gasoline's. Director of the Office of Alcohol Fuels and assigned responsibilities that currently do not According to GAOt5 letter to Duncan, DOE, however, come within the purview of that Office. does not have a comprehensive program aimed at pro- Regardless of the integrating mechanism moting alcohol fuels to attain their potential. Operating used, GAO believes the Office should be within its broad policy, DOE is working towards achiev- required to report directly to Secretary of ing ethanol production goals of 500 million gallons Energy or to the Under Secretary. annually by the end of 1981 and between 2 and 3 billion gallons annually by 1985. DOE has set no goals for the //fl I//I period beyond 1985, and no goals of any kind have been set for methanol production, even though methanol is GAO REPORT PROMOTES INDIRECT COAL irecngnized as having much more potential than ethanol LIQUEFACTION for replacing gasoline and reducing the Nation's depen- dence on oil. Furthermore, DOE does not have a The Comptroller General has submitted a report (EMD- comprehensive program plan for ethanol and methanol 80-84) to the U.S. Congress entitled "Liquefying Coal for with appropriate milestones and strategies, although Future Energy Needs." The main conclusion of the efforts have been made to develop such a plan. General Accounting Office (GAO) report is that if any portion of the national goals of 500,000 barrels per day Both ethanol and methanol can have a significant role in by 1987 and 2 million barrels per day by 1992 of crude oil resolving the Nation's liquid fuels shortage. To ensure equivalent is to be met with coal liquefaction, the bulk that the potential role of each is effectively defined, and of the production is likely to come from the indirect systematic efforts to reach such potential are under- processes. In this report, as in the GAO letter reviewed taken, DOE needs a comprehesive alcohol fuels program. in the previous article, the GAO reiterates its contention Such a program--addressing both ethanol and methanol in that indirect coal liquefaction needs to be encouraged. complementary fashion--should be developed around a program plan that sets forth appropriate goals, mile- The four direct liquefaction processes under develop- stones, and strategies. ment by the Department of Energy, SRC-I, SRC-II, H- Coal, and Exxon Donor Solvent Processes, are described Earlier in the year, DOE took steps to improve its in the GAO report. A brief overview of the problems of alcohol fuels program by crediting the Office of Alcohol scale-up, liquid/solid separation, product upgrading, Fuels with the responsibility for developing a program potential health and environmental concerns, solid plan covering alcohols from biomass and directed at wastes management and siting is given for each of the achieving production goals for ethanol. This effort falls four processes. short of the comprehensive alcohol fuels program that is needed, contends GAO, because it does not consider the Direct and Indirect Liquefaction Processes Compared potential of methanol from coal. Because of this, GAO is concerned that a comprehensive, balanced considera- According to the GAO study, three indirect processes tion of alcohol fuels, from the standpoints of both their are commercially available and may contribute to the development and commercialization, may not be U.S. energy supply in the near term -- Fischer-Tropsch, achieved. methanol from coal, and Mobil Oil Corporation's M-Gas process. It notes that the Department of Energy GAO concluded: "DOE's activities related to ethanol and believes that further research, development, and demon- methanol should be balanced in consequence with their stration can substantially improve these processes and relative merit and potential. The presently existing that their efforts to commercialize them can assist in fragmentation of these activities within DOE's organiza- industry adoption of the technologies. The report makes tion, primarily with respect to methanol from coal, the distinction between the Fischer-Tropsch and the provides little assurance of achieving the desired methanol from coal process as the catalyst used to balance. Consequently, a mechanism needs to be estab- produce liquids from the synthesis gas. In the Fischer- lished to ensure that methanol from coal not be sub- Tropsch process, an iron-based catalyst is used, while in jugated to a position of lesser urgency and importance the methanol process, the synthesis gas is catalytically vis-a-vis ethanol and methanol from biomass and thereby converted into crude methanol using chrome/zinc-based receive disparate treatment in commercialization activi- catalysts which operate under high pressure or copper- ties." based catalysts which work under low pressure.

The GAO recommended that DOE: The Mobil Gasoline process (M-Gas) takes the methanol from coal process one step further. After the crude "Establish a comprehensive and balanced pro- methanol is produced, the M-Gas process reacts this gram for alcohol fuels and develop a defini- methanol with a zeolite catalyst (developed by Mobil) tive program plan setting forth appropriate which separates water from the hydrocarbons in the commercialization goals, milestones, and methanol and rearranges the hydrocarbons to form high- strategies for both ethanol and methanol. octane gasoline.

4-22 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 According to a DOE official, a high grade methanol is According to the GAO Report, DOE did not promote not needed for the M-Gas process, therefore, the distil- indirect liquefaction in the past as the indirect processes lation step common to the production of methanol can be are less efficient, more costly, and available gasifiers eliminated. The daily product yield for a 25,000 TPD M- could operate on noncaking coals. Gas plant is estimated to be 52,700 barrels of premium gasoline and 7,300 barrels of liquefied petroleum gas. Direct Liquefaction Process More Efficient The synthetic gasoline is comparable with petroleum- derived gasoline and can be mixed in distribution/mar- The estimated thermal efficiency of indirect lique- keting systems and used in the automobile gas tank without adjustments. faction is 45 to 60 percent while that of the direct processes is 65 to 70 percent. This is largely due to the Mobil officials have stated they were ready to build a fact that estimates of the amount of coal required per unit of product are almost always greater for the commercial M-Gas plant to produce gasoline, but due to the projected uncompetitiveness of M-Gas with petro- indirect processes than for the direct processes. For example, per ton of coal, liquid yields are in the range of leum-derived gasoline, they would require financial assistance to begin the project. 1.6 to 1.7 barrels of fuel oil equivalent for the Fischer- Tropsch process, and 2.2 to 2.5 barrels of gasoline equivalent for M-Gas. The direct processes, on the other As GAO noted in its letter, as described in the previous hand, are currently estimated to yield in the range of 2.5 article, DOE had not encouraged liquids from synthesis to 3.0 barrels of fuel oil equivalent per ton of coal. gas in the past. However, the liquids production work outlined in DOE's fiscal year 1981 Fossil Energy program DOE's estimate that the indirect processes will be more plan will include such areas as the development of costly is based partly on the lower efficiency argument improved catalysts for Fischer-Tropsch and methanol, discussed above, and also on the fact that a more and a variation of the Ni-Gas process in which gasoline complex plant is required for indirect liquefaction since can be produced directly from coal, thus bypassing the it must include the hardware to first gasify the coal production of methanol. The Assistant Secretary for before liquefaction occurs, whereas direct liquefaction Fossil Energy has requested an additional $27 million for omits the gasification step and liquefies the coal fiscal year 1981 for work in producing liquids from directly. synthesis gas. Wide Disparity in Costs Reported Between Direct vs. GAO noted that: "Indirect liquefaction has an environ- Indirect Processes mental advantage over direct liquefaction. During the gasification step of indirect liquefaction, the synthesis In "Coal Liquefaction Technology," prepared by Fluor gas produced is cleaned, thereby removing sulfur and nitrogen. Since direct liquefaction does not include a Corporation, the estimated cost of direct liquefaction products was $20 to $30 per barrel and indirect lique- gasification step, these elements cannot be removed as effectively.,- faction products at $30 to $40 per barrel (1978 dollars). The September 1979 report by Cameron Engineers prepared for the Synthetic Fuels Task Force of the On June 30, 1980, the President signed the Energy Security Act which established a Synthetic Fuels Senate Budget Committee, estimated the cost of direct liquefaction products at $34 to $38 per barrel and Corporation (SFC) to provide financial incentives for the indirect products at $35 to $39 per barrel (1979 dollars), development of domestic substitutes for imported oil. while the Electric Power Research Institute, in October (See the General Section for a detailed description of the 1979 testimony before the Advisory Panel on Synthetic SEC). The Congress has thus far appropriated $19 billion Fuels of the House Science and Technology Committee, for use by the Corporation. In the interim before the estimated $51 per barrel for coal liquids from direct Corporation is fully operating, the Department of Energy processes and $56 per barrel for methanol from coal may use $5.5 billion of the $19 billion to begin offering (1978 dollars). financial incentives. Originally, DOE was appropriated $2.2 billion; later in the year a supplemental $3.3 billion These variations reflect the varying assumptions used to was added. determine the costs. The true magnitude of the differential between direct and indirect process can not It is too early to tell how these financial incentives will be determined until the operation of larger-scale plants. affect coal liquefaction. The goal of the $5.5-billion program is to have the most production in the near term GAO Questions Ability of Indirect Processes to Use from a balanced range of new domestic alternative fuel Caking Coals supplies. The three indirect liquefaction processes discussed in the GAO report would appear to be likely A factor, claimed by the GAO to be inhibiting indirect candidates for the program, since the commercialization liquefaction, is its inability to use caking coals from the of a range of technologies is one of the objectives of the eastern United States. Unlike direct liquefaction which program. They are also logical candidates for funding by potentially can process all U.S. coals, GAO stated that the Synthetic Fuels Corporation. Direct liquefaction indirect processes can currently operate only on western projects, however, may be less likely to receive funds noncaking coals. Unless modifications can be made to because of the risk inherent in attempting to commer- demonstrate technical success with eastern caking coals, cialize a process only operated to date on a small scale. indirect plants will probably be located in the West GAO is currently reviewing DOE's present and planned where they would have easy access to noncaking coals. commercialization efforts for the synthetic fuels tech- Otherwise, western coals would have to be transported nologies of coal liquefaction, coal gasification, oil shale, long distances at substantial cost to eastern plants. In and tar sands, including the $5.5-billion program.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-23 any event, according to GAO, eastern coals may not be used until improvements in technology occur. DOE'S RD&D gasification program emphasizes the development and demonstration of gasifiers that can process eastern coats. It is currently funding the design of two demons- tration plants in the area. Pace has to take exception to this GAO contention that caking coals cannot be used for indirect liquefaction. This claim, while made quite often, has been rebutted. R. B. Sherman (British Gas Corporation), speaking before the EPRI Conference on Synthetic Fuels in October 1980, stated that, "It has been claimed that the fixed bed gasifiers do not work well with swelling coals. Statements such as this can still be seen in the literature and are not true. In post-war years Lurgi has given much attention to the problem of stirrer design which has much benefited the Westfield Slagging Gasifier. Sub- stantial quantities of strongly caking and swelling coals such as Pittsburgh Sand Ohio 9, as well as the equivalent strongly caking British coals have been gasified." For a more complete description of the British Gas/Slagging Lurgis, see the article under "Technology."

1/1/111/

4-24 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 ENERGY POLICY AND FORECASTS

MARKET PENETRATION OF METHANOL AS A FUEL Florida Power Corporation, completed a full-scale test IS PROJECTED of a utility-class stationary gas turbine using methanol, in December 1974. Others involved in the program were Earlier this year, Badger Plants, inc., published the final Turbo Power and Marine Systems, Inc., and AMAX report, Vol. 1, Market Evaluations: Aspects of Com- Engineering and Management Service Co., suppliers of mercializing Coal-Derived Methanol Fuels in the United the 50,000 gallons of methanol. The methanol was States 1985 to 2000. Badger had previously completed burned in a FTC-I gas turbine rated at 24 MW which an engineering and economic assessment of a conceptual had been converted to a dual-fuel configuration to allow design for an integrated commercial facility to convert for a direct comparison with distillate. Results coal-to-methanol-to-gasoline for the Department of indicated that NO emissions were reduced 74 percent Energy. See Page 4-6, December 1979 Cameron Synthe- while CO emissions increased 100 percent when tic Fuels Report for a review of that study. compared with No. 2 distillate. Smoke emissions do not appear to be a problem with methanol, and general In the present study, an extension of the previous performance characteristics were equivalent to burning contract, Badger was commissioned to conduct a market natural gas. Almost twice the volume of methanol evaluation of coal-derived methanol fuel and methanol- needed to be burned, in comparison with conventional derived gasoline as related to the electric utility and gas turbine fuels, however. automotive sectors of the nation's economy. Only those segments of the utility and automobile industry most Another full-scale test using two FTC-i gas turbines likely to provide markets for for such fuels in the near driving a common generator was conducted by Southern term were evaluated. These were the simple-cycle California Edison Co. with assistance from the Electric peaking gas turbines and passenger vehicles, including Power Research Institute (EPRI) and the United Techno- government-owned fleet vehicles. In addition, the finan- logies Corporation. One turbine used methanol while the cial community (investment/commercial banks and insur- other used distillate fuel. Testing began in August 1978, ance companies) as related to private and public policy with the turbines simulating peak load conditions by that would have impact on commercialization of synthe- operating five hours a day, five days per week for a total tic fuels was examined. of five hundred hours. Originally, the test was scheduled for completion in February 1979. However, an explosion Survey agendas were prepared and forty-one interviews involving the distillate-fueled turbine delayed the com- were conducted with selected representatives of the pletion of the program until December 1979. utility, automotive and financial sectors. The data collected from each session were analyzed and presented Methanol appears to be an acceptable gas turbine fuel, in detail in the report and served as the basis for market and related technical problems should be readily solv- penetration forecasts. able. According to the study, the most important technical advantages of methanol as a turbine fuel are Overview of Methanol Research and Development in the low nitrogen oxides (NOx) emissions and no sulfur dioxide Utility Industry Given (s02) emissions. The wide flammability range and the low flash point, which produce a tendency to form The report includes a review of the electric utility explosive mixtures in storage, were considered to be the industry with an analysis of the problems facing the most serious technical disadvantages. industry. Also included is a review of methanol research and development. The industry has shown an interest in However, more data must be available before the methanol as a peak shaving fuel. In 1972, Vulcan- industry will make a commitment. Evidence from rela- Cinncinnati Corporation conducted a large-scale demon- tively long-term successful demonstrations including cri- stration at the A. B. Paterson Station of New Orleans tical information on operating and capital costs must be Public Service using a 50 MW capacity utility boiler. obtained. Adequate data on methanol's emissions and Southern California Edison Company and Consolidated corrosive characteristics are essential, as well as infor- Edison of New York also sponsored the test program. mation on distribution and storage practices. A demon- Methanol was able to provide a stable flame and good strated interchangeability with conventional fuels for burning effciency, and NOx emissions were less than flexibility of supply and fuel price would also be desir- those produced when burning natural gas or fuel oil. able. Without such data, long-term supply guarantees and price protection would be required. In addition, Early in 1974, the General Electric Company conducted regulatory and environmental roadblocks concerning tests at their Combustion Laboratories in Schenectady, methanol's use were considered to be of secondary New York, on a single combustor from their MS 7000 gas importance compared with the uncertain economic and turbine rated at 65 MW. The results of the test supply issues. indicated that methanol displays good combustion properties, provides low NOx emission levels, and Use of Methanol as an Automobile Fuel Is Also Investi- increases turbine output by six percent and efficiency by gated two percent. However, some of the fuel system com- ponents would require redesign, and it is essential that The report gave an analysis of the Automobile Industry methanol be kept free from contamination. in the U.S. as well as the fuel requirements. According

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-25 to the report, the automobile manufacturers in the for use in automobiles. By 2000, methanol United States have committed a very small part of their production reaches a high of 364 million research budgets to alternative fuels. However, suffi- barrels which is sufficient to allow 152 mil- cient new engine development has been completed by lion barrels per year for other uses. these firms to assure that the time to produce engines capable of running on methanol will be less than the time Rapid acceleration would result in 46 million to construct coal-derived methanol facilities and to barrels of methanol per year by 1985. It ensure an adequate and reliable supply of methanol. would be used exclusively for turbine fuel; availability for automotive blends would Three possiblities exist for methanol-based motor fuels commence in 1990 with the addition of new in the automotive industry: production facilities. By 1993, sufficient neat methanol is available for use in auto- Methanol can be added to regular unleaded mobiles. By 2000, methanol production gasoline to form a methanol /gasoline blend. reaches a maximum of 729 million barrels per This method is least favored by the automo- year; 315 million barrels of this total would tive industry, and it is believed that blends be available for the uses described under the containing more than ten percent methanol business-as-usual scenario. pose severe problems. Blends, however, appear to offer the best opportunity for ini- Table I summarizes the potential supply and demand tial use of methanol as an alternative fuel. forecasts for fuel-grade methanol by the year 2000. A range of low to high figures is given in millions of barrels Methanol can be used "neat" in engines per year under each of the three scenarios outlined designed to operate on straight methanol, above. taking advantage of methanol's higher octane number compared with regular gasoline. In each of these scenarios, methanol as a turbine fuel is given priority when a supply becomes available. This is Methanol can be converted to gasoline, using followed by use as a blend with gasoline which, after a process developed by Mobil. This is the consumer acceptance of methanol, would lead to neat- approach favored by the automotive industry. methanol-fueled automobiles. Once these demands are satisfied, any additional supply of methanol would be One of the major roadblocks to the use of methanol as a available for other uses, including conversion to gasoline, motor fuel is its distribution, i.e. how industry would get chemical-grade methanol, and feedstock for olefins. methanol to the consumer. However, the problem of Due to the relatively short lead times to manufacture methanol distribution was beyond the scope of the study, turbines or automobiles capable of using methanol com- which recommended further research into that area. pared with lead times for construction of coal-to- methanol facilties, the time frame for methanol's intro- Market Penetration of Coal-Derived Methanol is Deter- duction was determined by the supply in each scenario. mined ethanol Production from Traditional Sources is Determination of market penetration by coal-derived methanol depends on both the deployment of coal conversion plants and the anticipated demand for metha- The study recommended that market opportunities for nol. The production of methanol was investigated under methanol other than simple-cycle turbines and auto- three scenarios representing business-as-usual, moderate mobiles should be examined in a future in-depth study acceleration, and rapid acceleration programs. Only a which should take into consideration the methanol national emergency condition would be likely to demand markets that traditionally have been supplied by natural implementation of this last scenario. The methanol gas feedstocks as well as other potential markets for market penetration can be summarized as follows under methanol, such as combined-cycle turbines and fuel these scenarios: cells. Business-as-usual would result in 23 million Badger presented an analysis of methanol production barrels of methanol per year by 1988. It from traditional sources. The first commercial process would be used for turbine fuel and for blend- for synthetic methanol was developed in late 1920; until ing with gasoline. By 1993, neat methanol is the 1960's, all synthetic methanol was produced using a available for use in automobiles. By 2000, high-pressure (200 - 370 atm) synthesis process. In 1966, methanol production reaches 114 million Imperial Chemical Industries Ltd., started the first low- barrels per year; 54 million barrels of this pressure (50 atm) synthesis process for methanol at their total is available for other uses such as plant in Billingham, England, utilizing a very active conversion to gasoline, chemical-grade meth- copper oxide catalyst. Currently, the majority of meth- anol, and feedstock for olefins production. anol production facilities employ low-pressure (50-I00 atm) processes offered by such licensors as ICI, Lurgi Moderate acceleration would result in 46 Corporation, and Mitsubishi Gas Chemical Company, Inc. million barrels of methanol per year by 1987. It would be used preferentially for turbine In 1978, there were eight producers of methanol in the fuel; availability for automotive blends would United States with a total production capacity of 1.2 be limited by supply under the high forecast billion gallons per year as shown in Table 2. Capacities in 1990. By 1993, neat methanol is available range from 50 million gallons per year to approximately

4-26 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 250 million gallons per year, which is currently consi- dered the size limitation for single-train plants. The main feedstock for these plants is natural gas.

//il #11

TABLE 1 MARKET PENETRATION FORECAST FOR FUEL-GRADE METHANOL BY THE YEAR 2000 (Millions of Barrels per year range: low to high for year 2000)

Moderate Rapid Scenario Business-As-usual Acceleration Acceleration

Potential Supply 68 to 114 250 to 364 524 to 729 Demand Forecast Electric Utility 17 to 32 62 to 76 137 to 144 Auto Blends Ito 2 4 t 5 7 t 9 Auto Neat 13 to 26 104 to 130 208 to 260 Total Demand 31 to 60 170 to 211 352 to 413

TABLE 2 U.S. METHANOL CAPACITY -- 1978

Capacity (million gallons/year) Company Plant Location Present Future Total

Air Products Pensacola, Florida 50 --- 50 Borden Geismar, Louisiana 160 30(1980) 190 Celanese Bishop, Texas 145 --- 145 Clear Lake, Texas 230 --- 230 Du Pont Beaumont, Texas 221) --- 220 Deer Park, Texas _ 200 (1980) 200 Georgia Pacific Plaquemine, Louisiana 120 --- 120 Getty Delaware City, Delaware 150 (1983) 150 Hercofina Plaquemine, Louisiana 100 --- 100 Monsanto Texas City, Texas 100 --- IOU Tenneco Houston, Texas 80 30(1980) 110 New Producer Gulf Coast --- 200 (1983-1985) 200 1,205 410 1,615

The demand for methanol has traditionally come from the industrial petrochemical market with over 40 percent of the methanol utilized in formaldehyde production. Table 3 gives the current uses of methanol. The historic industrial demand and price for methanol are given in Table 4.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-27 TABLE 3 CURRENT CHEMICAL USES OF METHANOL Formaldehyde 43% General Process Solvent 10% Exports 10% DMT 7% Acetic Acid 5% Methyl Halides 4% Methyl Amines 4% Methyl Methacrylate 4% Miscellaneous 13%

TABLE 4 INDUSTRIAL METHANOL DEMAND Demand Price* Year (million gallons/year) (cents/gallon)

1930 8 40.5 1940 45 30.0 1950 136 26.0 1960 297 30.0 1965 433 27.0 1970 765 -- 1975 1,150 38-49 *FOB Gulf Coast Source: TRW

4-28 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TECHNOLOGY

THE BRITISH GAS WESTFIELD OPERATIONS ARE As a result of the Westfield trials, Conoco responded to DESCRIBED the U.S. Government's bid for a proposal to design and build a 60 MMSCFD SNG plant based on the British R. B. Sharman, Director, International Consultancy Ser- Gas/Lurgi slagging gasifier. The first phase of the vice, British Gas Corporation, presented a paper Conoco Project was entirely government funded, and entitled: "The British Gas/Lurgi Slagging Gasifier and involved a technical support program performed at West- Its Relevance to Power Generation" at the Electric field. During the program, Pittsburgh 8 and Ohio 9 Power Research Institute (EPRI) Conference on Synthe- coals, both having highly caking and swelling character- tic Fuels in October. istics and high sulfur content, were gasified. The Westfield program was completed in 1978. History of Gasifier Development Given In 1978, British Gas began a twenty year program to Included in the presentation was a brief history of the develop and demonstrate a range of processes to produce Westfield Development Center Operations. In 1953, SNG. The current cost of this program in 1980 dollars Lurgi, in collaboration with Ruhrgas, built a special (U.S.) is estimated to be $630 million. A significant part gasifier at 1-lolten to operate under slagging conditions to of the program continues to be the development of the widen the range of coals that could be gasified, as the Slagging Gasifier, leading to a second generation process fixed bed Lurgi was limited to gasifying reactive non- -- the composite gasifier. The program is currently caking coals. Excess steam had to be injected in the under review and may include full scale commercial gasification zone to prevent fusion by lowering the demonstration. A summary of operations at Westfield temperature of that zone. Operating under slagging between April 1975 and September 1980 is given in Table conditions avoids the necessity of using excess steam, 1. Performance data is given in Table 2, improves efficiency, and increases capacity. British Gas or the Gas Council purchased the experimental equip- The Westfield Slagging Gasifier Is Described ment in 1955, and work began at British Gas Midlands Research Station. A three foot diameter shaft, pilot Figure 1 shows a diagram of the Westfield Slagging scale gasifier demonstrated slagging gasification of coal Gasifier. An existing non-slagging Lurgi gasifier was at pressures of 20 bar and at high loads. Development converted to slagging operations. The shaft diameter was delayed because of availability of North Sea Natural was reduced from nine to six feet to match the total Gas but restarted at Westfield in the mid-701s. output of the existing oxygen plant; a second gas offtake was added, together with an associated downstream Development of the Slagging Gasifier was restarted cooling system, to match the greater output. Following principally due to the interest from the U.S. and was co- the installation of the slag tapping, hearth and tuyere ordinated by Conoco, funded and sponsored by 15 U.S. systems, the addition of a quench chamber, new instru- gas pipeline and oil companies, with EPRI participation. mentation and control equipment, and the elimination of This three year development marked the beginning of the grate, the remainder of the Lurgi gasifier continues formal co-operation between British Gas and Lurgi to in use to serve the previous role. The fuel bed is now develop the British Gas Lurgi slagging gasifier. Develop- supported on the refractory hearth, which is surrounded ment work was carried out on a commercial scale, six by a number of steam and oxygen inlets or tuyeres, with foot diameter gasifier, with 300-350 ton/day capacity. facilities for running off liquid slag, via a tap hole, into a chamber below where it is quenched in water. The Westfield became a development center with coal trials quenched slag is discharged from the pressure system for the American Gas Association on the existing dry ash through a lock hopper. Lurgi reactors. These were followed by the methanation trials for the Conoco.

TABLE 1 SUMMARY OF WESTFIELD SLAGGING GASIFIER PROJECTS Fuel No. of Hours on Gasified Project Runs Line (tons) Sponsors' Programme 27 1,508 19,444 DOE Programme 15 981 10,866 EPRI Trials 3 415 3,903 British Gas Programme 19 1,660 20,328 TOTALS 64 4,664 54,541

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 4-29 TABLE 2 Itfor,,nnce Dam for British sftnrRi Slain and Uar*i Dry-Ash Gasifiers at t-stfield

Scotland England USA USA USA Sire (in) f-i f-i f1 1/8-1k 1/8-U Proximate Analysis, (% w/-) tisowe 8.7 9.5 6.1 4.2 4.8 Ash 4.4 4.6 18.9 7.2 7.9 Volatile tter 22.9 31.2 33.6 35.4 37.4 Fixed Car, 54.0 54.7 41.4 53.2 50.3 Ultimate Malysis (% 4w) Carbon 83.0 83.5 79.6 82.4 84.9 Hydrogen 5.5 4.9 6.1 5.3 5.8 Oxygen 9.2 7.7 7.4 9.1 5.0 Nitron 1.4 1.7 1.2 1.5 1.6 Sulphur 0.5 1.7 5.6 1.6 2.6 Chlorine 0.4 0.5 0.1 0.1 0 B.S. S.pLlirg . 1 1/2 1 1/2 4 1/2 7 1/2 7 1/2 Caking Index (Cray King) B E C C8 G8

Overating Conditions Gasifier Pressure, (am) 24 24 24 24 24 Stea,i/0xyn ratio ('ii'.) 1.3 1.3 1.3 1.3 9.0 outlet Gas teractffe (°P) 896 896 770 950 1220

Crude Gas Composition, ( v/v) If, 28.6 27.2 28.7 28.9 O 57.5 58.1 53.2 54.9 17.9 014 6.7 6.8 6.9 7.1 8.4 C2,H6 0.4 0.5 0.3 0.6 0.7 C2.H4 0.2 0.2 0.2 0.2 0.3 N2 4.2 3.9 4.0 4.4 2.4 2.3 2.9 5.5 3.4 H2S 0.1 0.4 1.2 0.5 0.7 HIV, (Btu/ft-cu.) 375 375 362 375 298

Derived 03ta Coal Gasifttia, rate(lhe/ft2/hr) 852 848 664 666 140 Steam conststion, (lb/lb coal) 0.405 0.398 0.393 0.407 3.54 Oxygen Caiarptia, (lb/lb coal) 0.539 0.549 0.555 0.547 0.70 Liquor proaction. (lb/lb coal) 0.20 0.21 0.16 0.21 2.24 Gasifier Thermal outpu t,(therrs/ft2Thr1 106 78 83 17 Gasifier therl efficiency *, (t) 83.4 82.1 82.3 79.9 62.3 Coal coressed roisture and ash free" - fired as total product gas thermal output (based on FUN, ircludirg tar, oil, naphtha) divid by rrespcndir thenral input of coal feedstock and the fuel equivalent of the steam and oxygen used.

4-30 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 The gasifier operations were stable at all loads used between 30 percent and 100 percent of full load and -S could change rapidly from one load to another within this range. The gasifier can also be readily put on hot standby, from which it can return to full working load in ten minutes, if required. There were no significant gasifier transients during load changes and gas quality remained substantially constant at all loadings.

COAL LOCK HOPPER British Gas Plans for Commercialization Because of the uncertainty in the prospects for the GAS TO Conoco project, British Gas decided that it would carry . the project forward and the program at Westfield will PRIMARY CLEAN UP include the construction of a larger gasifier, one of 8 feet nominal diameter, which will gasify 600-800 tons per day. A three month run is planned to be completed in 1982 which will confirm the commercial status of the gasifiers of this size, which are smaller than that pro- STEAM & OXYGEN posed for the Conoco demonstration plant which will gasify 1000 tons per day. British Gas is now prepared to grant licenses for plants utilizing slagging gasifiers of sizes up to 8 feet in diameter and will provide full commercial guarantees. (Molten Slag) QUENCH WATER British Gas is supporting Florida Power Corporation in a IN-WATER Feasibility Study for the integration of a slagging gasi- fier with combustion turbines and exhaust heat recovery SLAG QUENCH CHAMBER steam generators to repower existing condensing steam turbine generators at the Higgins Plant in Pinellas County, Florida. This study will last twelve months and SLAG LOCK HOPPER is expected to be followed by detailed engineering and construction of the facility. A number of other feasi- bility studies are under consideration and these should ASH (Slag) lead to the construction of additional gasifiers.

FIGURE I ENHANCED OIL RECOVERY IS A POSSIBLE USE FOR BRITSH GAS/LURGI SLAGGING GASIFIER CARBON DIOXIDE FROM GASIFICATION PROCESS SCHEMATIC A study: "Feasibility of Utilizing Carbon Dioxide Pro- duced During the High-Btu Coal Gasification Process for Enhanced Oil Recovery' was prepared for the American Test Program Conducted for EPRI Gas Association by the MITRE Corporation. A preli- minary analysis of the feasibility of utilizing the vented A three run trial program was completed for EPRI in CO 2 emissions from high-Btu coal gasification plants for December 1979. The tests were aimed at demonstrating enhanced oil recovery was presented in the study. The the potential of the slagging gasifier for electric power suitability of CO produced for direct utilization, and generation in a combined cycle plant. costs of recovery and transportation was estimated, and a hypothetical least-cost pipeline network was identi- During the tests, Pittsburgh 8 coal with up to 25 percent fied. less than 1/4-inch was fed to the bed top without any significant change in gas analysis. More recent experi- The results of this study, however, are based upon a ence in the British Gas Company program at Westfield number of simplifying assumptions and, therefore, they has shown that the above figure can be extended to 35 should not be considered conclusive nor definitive. percent. Testing of the technique of injecting fine coal Major findings of the study are: directly into the reaction zone of the gasifier via the tuyeres, is now underway at Westfield. It is expected High-Btu coat gasification (HaG) plants that this will lead to even greater potential for fines would be a source of inexpensive, high quality intake into the stagging gasifier. CO 2* Approximately 6.8 billion barrels of oil, which would not otherwise be recovered, During the EPRI trials, tar and oils generated in the could be extracted over a 15-year period gasifier were recycled to extinction through the tuyeres. (1.24 million barrels per day) through use of The tests for EPRI were particularly oriented towards this CO9 for enhanced oil recovery. Added establishing the ability of the gasifier to respond quickly cost per tarrel would be $5.36. to toad changes and to run steadily at a variety of loads.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-31 Average cost of transporting the CO, to oil In this analysis, only 70 percent (7 Ed/day) fields amenable to c0 2 miscible frooding, of the total CO 2 demand of 10 Bcf/day in the including compression and pipeline construc- Permian Basin could be met, while demand at tion and operating and maintenance costs, is all other oil field locations (2.9 Bcf/day) estimated to be $0.67 per MCI of CO2. would be fully met.

Total CO available from thirty-three HBG There would be several gaseous waste streams containing plants which could be operating by the year CO., from high-Btu coal gasification. These streams 2000 would be a cumulative 100 Tcf over a would be from gas turbines, steam superheaters, fuel gas 30-year period, 2 to 4 times that available heaters, sulfur plant vent, sulfur plant incinerator, emis- from naturally occurring sources. sion stream lock, and exhaust gases and residual CO vent. A 250 MMcf/day coal gasification plant may emi Assuming a 15-year requirement period, daily over 19,000 tons/day of CO from process vents and CO 2 demand for enhanced oil recovery is 7,000 tons/day from boiler flues; another 18,000 tons estimated to be approximately 13 Bcf. The would be released at the point of combustion of the potential daily CO 2 supply from HBG plants product oils and gas. The weight percent of carbon in 2000 of 9.9 Bcf could meet 76 percent of dioxide in these streams would range from 10 to nearly this demand. Assuming a 30-year plant life, 100 percent. Since carbon dioxide miscible flooding for total CO 2 available would be 98 Tcf. enhanced oil recovery requires a CO Stream of 90 Possible locations of these plants are shown percent purity, for the purposes of the study it assumed in Figure I and listed in Table 1. that only those streams with CO composition approxi-

TABLE I LOCATION CODES FOR FIGURE I

code Location Nom of plants' Central North Dakota (e.g., Mercer & Dunn Counties) 6 3,3 Eastern Montana (e.g.. Mccone & Wilbaux counties) 7 Northeast Wyoming (e.g.. Campbell & Converse Counties) 9 Eastern Utah (e.g., Garfield & Emery Counties) II Northwest New Mexico (e.g., San ],tan County) I? Central Illinois Perry County) 19 western Kentucky (e.g., Henderson County) I) Eastern Texas (e.g., Houston County) I) western Tennessee (e.g., Shelby County) 21 Southern Ohio (e.g., Noble County) 23 southwest Pennsylvania (e.g., Westmoreland county) 130 MMcf/day Syngas -

FIOURe • PROPOSED SYNOAS PLANT LOCATIONS AND OIL FIELDS MOST AMENABLE TO CO2 MISCIBLE FLOODING

4-32 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 2

CO2-RICH CASES AVAILABLE CR159 TYPICAL LURGI iilCli"ITU COAL GASIFICATION PLANTS

(Dues not lncudecu.bustlon flue gases or low-concentrs C joel CO 2 vents)

Project Sponsor EPIC WESCO MR PAI1IL6I1DLE EASTERN Project Location New Mexiro New Mexico N. Dakota Wyoming 10d scrod 006 5KG PRODUCTION RATE 250 A 106 SCFD' 250 x 10 6 250 • .06 750: SCFD

TOTAL 00 2-RlOi Ci): 006 SCFD 362 o 10 124 x 106 36 K 337 x 10 Lbs/Hr 1,603,900 1.506000 1,693,400 1,592400 Short Tuna/Day 19,246 18,072 20.322 19,008

CCSIPOSITION:

set I t02 88.0 96.9 96.2 97.6 vol 2CO2 60.6 93.2 90.8 95.2 vol 2 Iiydro.arbons nil 1.1 2.1 2.2 vol 2 Water vapor 6.5 0.3 5.6 2.5 vol ZN2t inert, 02.6 5.0 0.0 0.1 vol 202 0.3 nil nil nil 49 vol PP1256 nil 6 000 vol pp. CDI nil 74 235 49 vol Pima CO oil 202 654 500 vol ppm SO2 74 nil all nil vol PPS 00 5 21 nil nil nil

CONTAINED 1001 CO2

19,550 18.650 Short Tons/Day 6956 17512 6 6 SCFII 292 s t0 302 m 10 136 a 00 020 i tO

a includes Nydrogen. It an,. bincludes other forms of organic sulfur. 6 CProrated from peak INC product Ion rate of 288 S ID SCFU. This streom has been rat alytically incinerated. and contains no 0075, COS or CO. tI.erefore 6 dprura t e A from peak SK production rates of 275 a 10 SCFD

Sources: Department of Interior. Final Environmental Statements for the WESCO project (January 1976), the EPNC project (February 1977) and the MR project (Nay 1977). Correspondence between the U.S. EPA and members of the ACA 'a Ad liar Ii ama colt tee which worked with the EPA during the development of the EPA' m eninston guidri inns for Lurfl roat gasiiieatio.. plants (1975-1977). Milton I. seyrhok, C—sulLina EngIneer, by report to the Aawrtcan Ca. Association, July II, 0980. mately 90 percent or greater were considered as sources Hydrocarbon (primarily hydrogen, methane, of CO. It is further assumed that these streams are of ethane and ethylene) gases are present in the sufficint purity so as not to require further treatment. range of nil to 2.4 volume percent. This very Tables 2 and 3 present the quantity and composition of probably presents no problems, but should CO -richgases available from typical Lurgi high-Btu also be confirmed. coar gasification plants. The data in those tables are based upon actual plant designs for five proposed pro- Carbon monoxide, carbonyl sulfide, sufur dio- jects to utilize Lurgi gasification technology. xide and nitrogen oxides, at levels in the ppm range (well below one percent), may or may In utilizing the CO from these plants, however, the H2S not present problems. There is no readily content of the gases should probably be limited to a available information from which to evaluate maximum of 100 ppm for pipeline safety. The plant the effects of these minor constituents. producing gasoline via the intermediate methanol route would require significant re-design to reduce the H2 There are several naturally occurring sources of CO content of the CO rich gas from 3500 ppm to 100 ppm. which are being considered for enhanced oil recovery, and these are shown in Figure 1. Total CO reserves, Water vapor should probably be reduced to well below excluding West Virginia (currently unknown), are 13 to 21 the water dewpoint of the CO 2-richgases in order to Tcf, 13 to 21 percent of that potentially available from avoid possible problems with corrosion and hydrate for- the HBG plants: mation. Conventional glycol dehydration could easily and inexpensively solve such problems. Total cost would Three pipelines have been proposed to transport CO to increase if the removal of water or H 25 was necessary the Permian Basin in Texas. Shell Oil has proposed building a 490-mile pipeline from the McElmo Dome area Three areas also need further confirmation: near Cortez, Colorado, to the Wasson field in San Andres, Texas. ARCO has proposed that a 420-mile, 20- The nitrogen levels of 0.1 to 12.6 percent inch pipeline to carry 300 MMcf/day be built from probably present no problems in terms of Heurfano County, Colorado (Sheep Mountain), to Yoakum using the CO,-rich gases for EOR, but this and Caine counties, Texas. Amoco has also targeted a point needs colifirmation. pipeline to be built from the Bravo Dome area in

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-33 southeast New Mexico (Quay, Harding and Union Research is now being sponsored by the U.S. Department counties) to west Texas (Oil and Gas Journal, March 31, of Energy to ascertain those areas most amenable to 1980; Renfro, 1979). CO, flooding, additional oil to be recovered, and amount of Co 2 required to effect that recovery. CO is also a by-product of several other industrial processes, including those of the petrochemical industry. The MITRE study also gave cost data for each possible One 200-mile pipeline (SACROC) has been constructed CO 2 pipeline from each of the possible high-Btu projects to transport 220 MMcf/day of waste CO, from a natural to identified EOR fields, as shown in Figure 1. A least- gas processing plant in the Val Verde Basin, Texas to cost network was also identified. Scurry County, Texas. The CO, is transported in a super-critical state with properties similar to the gas- Comment eous phase at pressures greater than 1400 psi. This is a particularly pertinent study, as American The trend towards use of CO for enhanced recovery has Natural Resources announced on October 20, 1980, that been steadily increasing. In 1974, there were six CO engineers for the Great Plains Project are looking at recovery projects; there are now seventeen, including ways to utilize the CO 2 produced at the plant. Please pilot projects, and twenty additional projects are planned refer to the article on Great Plains in the Project for beyond 1980. Activities section.

TABLE 3 I/ill CO2-ItICH GAS AVAILABLE FROM LURGI COAL GASIFICATION TO PRODUCE HIGH-Bit SNC PLUS GASOLINE (VIA INTERMEDIATE METHANOL PRODUCTION)

(Does not include combustion flue gases or low-concentration CO vents)

a,b Con. FEED RATE 21.820 Short Tons/Day

GASOLINE PRODUCTION RATEb 22,000 Barrels/Day

SNG PRODUCTION RATE 145 x 106 SCFD (High-Bt.)

TOTAL CO 2-RICHGAS 5cr) 306 x 106 Lbs/Mr 1,462,100 Short Tons/Day 17,545

COMPOSITION:

wt I CO2 98.4 vol 1 CO2 96.8 vol 2 IlydrocarbonsC 2.4 vol I Water vapor 0.1 vol 2 N2 + itierts 0.001 vol pp. H25d 3,500 vol ppm COS 56 vol pp. CO 2,343

CONTAINED 1002 CO2

17,265 Short Tons/Day 6 SG'D 296x10

attunof_mine coal fed to gasifiers (after crushing and sizing). Does not include coal for use in plant boilers. bProrated from peak (operating day) rates to annualized average rates. An annualized average rate of 21,800 short tons/day of coal is roughly equivalent to a plant producing 250 million SCFIJ of SNG. clncludes hydrogen, if any. dlncludes other forms of organic sulfur. *Conceptual design of one potential plant to produce syngas via Lurgi coal gasification and convert the syngas into methanol and SNG. The methanol is then converted into high-octane gasoline.

Source: Milton B. Beycholc, Consulting Engineer, by report to the American Gas Association, July 11, 1980.

4-34 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 DEVELOPMENT OF GAS TURBINES FOR USE WITH The success of these gas turbines will depend on satis- COAL-DERIVED FUELS DISCUSSED BY GE factory combustion emissions control and the dura- REPRESENTATIVE bility/reliability of gas turbine systems. With the variety of characteristics of synthetic fuels, the question The problems associated with the development of gas of compatibility of these fuels with gas turbines has no turbines capable of utilizing coal derived gaseous and single, simple answer. The choices of liquids or gases, as liquid fuels were discussed by W. J. Hefner of the with conventional fuels, will be based on the economics, General Electric Company in a paper entitled, "Gas and operating flexibility required of the electrical Turbines for Future Coal-Based Power Generation generating system. Gas turbines have already burned a Systems." The paper was presented at the Electric variety of fuels ranging from low Btu gases, around 100 Power Research Institute's Conference on Synthetic Btu/SCF, through medium Btu gases at 200-400 Btu/SCF, Fuels, which was held in October. to high energy gases, as high as 3000 Btu/SCF and a broad spectrum of liquid fuels. At the present time, large stationary gas turbines are available to the utility industry which have turbine inlet Problems with Coal-Derived Fuels Relate to Impurities temperatures in the range of 1800°F (982°C) to 2000°F in the Fuels (1093°C). These machines typically operate at 3600 RPM for 60 Hz generation driving two-pole synchronous Synthetic fuels will have a wide range of impact on generators. Single gas turbine power modules are avail- turbines just as petroleum fuels do. Corrosion results able in excess of 100 MW. Today's machines offer a when high temperatures and fuel which contains as little simple-cycle thermal efficiency generally around 32 per- as a few parts per million of sodium expose nozzles and cent and, in combined cycles, they are the most efficient buckets to sodium sulphate. Fortunately, gas cleanup option available to electric utilities using conventional systems, designed to remove the sulfur from low and oil and gas fuels, having a thermal efficiency well in intermediate Btu gases are also often effective in reduc- excess of 40 percent. ing alkali metal content as well.

Future trends will include higher turbine inlet tempera- Coal contains both sodium and potassium, usually in the tures. In the USA, programs funded both by EPRI and form of insoluble silicate and aluminosilicate minerals. the U.S. Department of Energy are underway to increase Experiments have shown that during combustion some of turbine inlet temperatures to the range of 2600°F these water insoluble compounds are converted to the (1427°C) to 3000°F (1650°C). This increase in tempera- soluble and corrosive sulphates. Moreover, the combina- ture will be made possible by applying advanced cooling tion of sodium and potassium has been found more technologies to current designs. An increase in turbine aggressive than an equivalent amount of sodium alone. inlet temperature of this magnitude will both improve The potassium-carbonate chemical cleanup system pro- the thermal efficiency and significantly increase the vided in the U.S. Department of Energy High Tempera- turbine output. ture Turbine Technology Program was effective in gasi- fication system tests in reducing the total alkali metal In the time frame that is required to develop a synfuels content to 0.1 ppm. On the basis of this and other industry, Hefner contends that it is possible that gas experiments, coal gas experience from the corrosion turbine technological developments will permit new viewpoint is likely to be good. designs that more than double the output of current-day hardware. In base load combined-cycle applications, Coal liquids may be another story. Research is being these machines will yield overall plant thermal efficien- directed towards understanding the problems of vanad- cies--fuel to kilowatts--of 46 percent. Field-proven ium, a characteristic contaminant of todays petroleum units of this capability could be available for commercial fuels, which will also play an important role in solving service to the electric utility industry by 1986. Inte- the problems of coal liquids in the future. Coal derived grated with an advanced coal gasification system, over- fuels generally do not contain vanadium, but coal- all plant efficiencies--coal pile to bus bar--in excess of derived liquids (CDL) as well as shale oils and tar sands 40 percent will be possible. Studies by GE show ad- may contain other metals which can form deposits. In vanced integrated combined-cycle plants will offer a 25 the DOE Fireside Corrosion I Program, deposition tests percent reduction in the cost of electricity, compared to were conducted with COED fuels and an H-Coal sludge- conventional coal-burning steam turbine plants with doped creosote. Deposits formed on the turbine nozzle stack clean-up equipment. Other benefits of the high consisted of iron, silicon, aluminum and some alkali temperature integrated gasification combined cycle over metals. Also, ash bearing fuels may not be compatible conventional plants are: with high firing tempertures, causing build-up of deposits, especially on water-cooled nozzles. • Sulfur and NOx emissions will be less by factor of 10 Work on achieving dry low NO (without water injection) may soon provide the ability 10 reduce NOx production • Coal usage will be 20 percent less from fuel bound nitrogen in addition to thermal NO Because of the high fuel bound nitrogen content of most • Water usage will be 50 percent less coal derived liquid fuels this capability could be impor- tant to the acceptable use of coal liquids. • Land usage will be I/S • Solid waste will be 113.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-35 Combustion System Design Must be Correct for Synfuels gasification plant (fractionation tower for example) by IS percent of the vapor loading. The resulting vessel Perhaps the most important impact of the new synthetic oversizing, with associated costs, would amount to about fuels on the gas turbine will be felt in the combustion 10 percent compared to designs based on more accurate system. Here heating value and other fuel characteris- data. Some component data could be off by an order of tics influence the complexity of the combustors in magnitude greater and could cause major increases in meeting stable, efficient energy release and controlled plant cost for conservation or result in equipment that emissions. Present day production combustors will burn fails to perform as designed, reducing plant capacity. all of the liquid petroleum fuels and a range of gaseous For the type of processing plants being proposed to fuels from 300 Btu/SCF and higher. Over this range of gasify coal, a capital investment component 10 percent fuels there are minor changes in fuel nozzles to meter higher would impact the calculated investors' rate of and atomize the fuel. However, such may not be the return by only about 5 percent. It is believed that this case as fuel properties depart farther from the standards small return impact would not be the determining factor of the past. Modified combustion systems have already in deciding the justification of these very large projects. been successfully laboratory tested on coal-derived gas However, the committee believes the potential invest- and await field experience. ment savings is large in comparison to the cost of obtaining better data. Whether fuels are natural or synthetic in gas turbines, sulfur dioxide emissions must be controlled by fuel One gasification plant equivalent in size to about 300 treatment to remove sulfur before combustion. The high million SCFD would cost 3 to 4 billion dollars in the 1985 excess air and thus large volume of exhaust flow charac- to 1990 time frame. The committee has estimated that teristic of all gas turbines makes stack gas desulphuri- 30 percent of the plant design is subject to the phase zation grossly uneconomical. equilibria and enthalpy data of questionable accuracy. The remaining 70 percent relates to gasification reaction In a program (Powerton) jointly funded by DOE, EPRI, (10 percent), offsites and utility supply (30 percent), and and the State of Illinois, GE claims to have successfully other equipment (30 percent) such as liquid and by- developed, using these facilities, a combustion liner to product recovery. If the 30 percent estimate is reason- bum low heating value gas from a Lurgi airblown gasi- ably accurate, then about one billion dollars (1985-1990 fier. This liner burns 108 Btu/SCF gas with composition $) is subject to closer design tolerances with Unproved 9.0 percent CO, 15.0 percent H 2 and remainder being data. From the earlier estimate that 10 percent of the mostly N 21 G0 and water vapor. This combustor uses a investment could be saved, the savings per plant would single fuel nozzle21 which has the extra gas tip area amount to $100,000,000. required to pass the larger volume of low heating value gas compared with natural gas as used in conventional The Supplemental Gas Committee estimated that about dual-fuel nozzle. 10 plants will be built by the year 2000. Beyond the construction period of 10 plants, data will be available Successful combustion of coal liquids will present a more from experience or special project data development significant challenge. CDL fuels tend to be highly whether or not any research is done now. For the data aromatic reflecting the complex aromatic carbon ring to be useful in the designs of the largest portion of the structures in the parent coal. Consequently, they have 10 plants, it would need to be available by 1995. There- relatively low hydrogen to carbon ratios, in the order of fore, the next 15 years is critical to the value and 1.0/1 or less, compared to 1.5 to I.E/i for petroleum- usefulness of the fundamental research program. The based fuel. They are also characterized by higher fuel- Committee recommended to the Gas Process Association bound nitrogen and fuel-bound oxygen. Some of the that funding for fundamental research be supplied. undesirable characteristics resulting from these proper- ties include: higher specific gravity, with potential At the same time as the fundamental data is being problems in sodium washing; lower heating values; obtained, process research will be occurring all during increased smoking tendency; higher radiation; an this decade. Based upon the history of such develop- increased rate of degradation; and increased NOx emiss- ments, process discoveries made in 1990 will be ions. Nevertheless, with the limitations on using petro- developed and commercialized over the next 30 years leum-based oils, CDLs are expected to develop as future when the industry buildup is in full swing and mature gas turbine fuels. Anticipating the day when they will be plant design underway after 2020. At that point, process economical to burn in gas turbine peaking and mid-range research will be minimal with research in support of operation, GE has a long term goal to develop combus- operations growing to meet the need. The fundamental tion that can use CDLs in an environmentally acceptable research would serve two purposes during this decade: way, with little or no upgrading. (I) to support plant design work and (2) to support process research. 1/111/1/ To justify the need for more research, the Supplemental ENTHALPY AND PHASE EQUILIBRIA DATA FOR Gas Committee noted that the earlier estimate of COAL GASIFICATION PLANT DESIGNS SAID TO BE $100,000,000 savings per plant multiplied by the 10 first INADEQUATE plants would yield a $1 billion overall savings for the fundamental research. With a research payout of 100 to The Supplemental Gas Committee has reported to the 1, $10 million could be spent in the next IS years. Gas Processors Association Board of Directors that the Alternatively, the typical research budgets for process- lack of enthalpy and phase equilibria data could result in ing industries is about 1/2 percent of revenue for fuel conservative overestimation of a typical design of a coal products to 2 percent for chemicals. If this new industry

436 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 spent 1 percent of the $1 billion (1985-1990 $) per year revenue per plant, the total research budget for 10 plants could reach $100 million per year. Spending $10 million on fundamental research would require only I percent of the research funds for 10 years. As an example of errors which will be encountered when using existing hydrocarbon thermodynamic property data and correlations in designing coal conversion processes, the Committee cited a project which was being designed for the synthetic fuels industry where coal was being slurried and hydrogenated. Because of the pressure and temperature (860°F, 2000 PSIA to 100°F, 1950 PSIA), the Grayson-Streed correlation was selected because it is applicable for a stream of hydrogen through heavy hydrocarbons.

The contractor worked closely with the client's R&D organization, who also was using Grayson-Streed, to obtain actual K and H data for this specific stream. The two firms developed a modified data base for the light hydrocarbons after they determined that the hydrogen (H ) carbon monoxide (CO), nitrogen (N 2), and methane (C?14)' K's differed from the petroleum based K's signifi- cantly; in fact the K for hydrogen was different by a factor of six (6).

Work by the R&D organization also determined that the enthalpy, latent heat of vaporization and specific heat of the liquids was different for the entire spectrum of components.

If the K and H data had not been determined experi- mentally, the following major equipment and processing areas would have been affected:

Several trains of large heat exchange Fractionation area Gasifier area Shift Conversion section Hydrogen plant Gas Treating and Purification area On a billion dollar project, errors in one section could easily cause oversizing by 5 to 10 percent or result in a facility that is undersized in other areas.

(/1111 1/

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-37 CORPORATIONS

UPDATE ON WESTINGHOUSE COAL GASIFICATION remainder of the incoming coal to form a char and to PROGRAM GIVEN react the char with steam to form hydrogen and carbon monoxide. As the bed of char circulates through the jet At the Electrical Power Research Institute's (EPRI) formed at the end of the central feed tube, the carbon in Conference on Synthetic Fuels: Status and Directions, J. the char is consumed by combustion and gasification, D. Holmgren presented, "The Westinghouse Gasification leaving particles that are rich in ash. The unique fluid Program'. dynamic design of the gasifier allows the ash-rich par- ticles to agglomerate with each other and form large, Westinghouse has been developing a coal gasification dense particles which defluidize from the bed because of process since 1972 under sponsorship of the U.S. Depart- their weight and size and collect in the ash annulus. ment of Energy, its predecessors agencies, and more These agglomerates are cooled and removed through a recently, in conjunction with the Gas Research Institute. lockhopper system.

The Westinghouse gasification system utilizes a single Raw product gas from the gasifier passes through stage, pressurized, fluidized bed gasifier followed by cyclones to recover entrained particulates, which are heat recovery and gas cleaning. The gasifier can utilize recycled to the gasifier. The gas next passes through either air or oxygen as the oxidant to produce a low or heat recovery heat exchangers and is then quenched in a medium Btu gas, respectively. By-products from the water venturi scrubber. The particulate-free gas is gasification system include sulfur, ammonia and an desulfurized in an acid gas removal system and the clean agglomerated ash residue that is non-toxic and can be product gas is then ready for use as a fuel or feedstock disposed by landfill. The gasifier is shown in Figure I. for subsequent processing. Sulfur is recovered as ele- mental sulfur and wastewater is treated and recycled. According to Holmgren, coal is pneumatically trans- ported from lockhoppers into the gasifier through a Westinghouse has operated a Process Development Unit central feed tube where it is combusted and reacted with (PDU) at Waltz Mill near Pittsburgh since 1975. Close to an oxidant stream of oxygen or air and steam. The 10,000 hours of hot operation have been achieved. Both partial combustion of a portion of the incoming coal air and oxygen at pressure of 130 psig to 225 psig have provides the heat necessary to devolatilize the been tested using the same gasifier vessel and configura-

Product Gas To Cyclone

( Gasitier Gasifier 5 DavolatlIl,., Coal Agglomerator • Combusts Char • Ossliles Char • Agglomerates Ash • Separate* Ash From Char

Char Fines Recycle

From Steam - Cyclone

Stripping Gas - Flow pr Steam Oxidant L Transport Gas Ash Coal or Char 5650-3

FIGURE 1 WESTINGHOUSE GASIFIER SCHEMATIC

4-38 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 lion for either oxidant. A wide variety of coals and date the larger low Btu fuel gas manifold piping and fuel chars has been tested at capacities ranging to 30 ton per nozzles. Liquid fuel capability ranges from light distil- day with oxygen and 15 ton per day with air. The late to heavy distillates, or even residual fuel types, with coal/char feedstocks are a nominal 114 inch by zero inch the associated fuel handling and fuel treating systems. material, with fines being readily utilized. Operating Combustor cylinder air bleed is provided for on the temperatures have been varied over a range of 1500°F engine, such that integration with a low Stu gasifier is to 1990°F. The gasifier is a refractory lined mild steel readily accomplished. shell with no special refractories or cooling systems. The composition of the product gas is dependent on the The following commercial applications are available for feedstock and the gasifier operating parameters. Waltz the Westinghouse gasification process: power generation Mill Gasifier operations have been conducted with a using combustion turbine combined cycle systems, re- variety of carbonaceous feedstocks using either oxygen powering of existing steam turbines, refueling of existing or air as the oxidant. Table I gives a list of the boilers, and fueling fuel cells; synfuels to provide indus- feedstocks which were readily gasified and the ash trial fuel gas or provide synthesis gas feedstock for fuels successfully agglomerated. and chemicals.

Feasibility studies for several commercial size plant TABLE 1 projects utilizing the Westinghouse gasification process are underway or proposed. These include: The NASA WESTINGHOUSE GASIFIER FEEDSTOCK Lewis Research Center Project, the United illiminating Company Project, the Keystone Project, and the Westinghouse Fairmont Lamp Division Project. Coal NASA Lewis Research Center Project is Underwa

Texas Lignite NASA retained Davy McKee Corporation to evaluate gasification and power generation systems for proposed Wyoming Sub-C - Subbituminous installation at the Center. A reference design was Montana Rosebud - Subbituminous selected to conserve natural gas and oil to increase energy utilization efficiency by use of a coal gasification Indiana No. 7- Bituminous system to fuel a combustion turbine-driven electric Western Kentucky - Bituminous power generator and a heat recovery unit to provide steam for building heating. After a review of 36 Ohio No. 9- Bituminous gasification systems, the Westinghouse gasifier was Pittsburgh Upper Freeport - Bituminous selected as the reference system. Pittsburgh No. 8- Bituminous United Illuminating and DOE Contract to Repower United Illuminating, a Connecticut utility, selected the Char Westinghouse process and Westinghouse turbines in a study performed by Dravo Engineers and Constructors under DOE contract to repower the Bridgeport and Steel Coke Breeze - from coking operations Point Generating Stations. The utility is considering the Pittsburgh No. 8- from Westinghouse devolatilizer next stage of design which would lead to a plant being constructed and started up in 1988. Indiana No. 7 - from Westinghouse devolatilizer Utah - from FMC COED Pilot Plant Keystone Project Proposes Indirect Liquefaction Tech- nology Kentucky - from FMC COED Pilot Plant A feasibility and preliminary design study for a nominal Significant environmental advantages, compared to con- 100,000 barrel-per-day methanol facility located in the ventional coal-fired generation, are achieved when the Cambria County area of western Pennsylvania has been Westinghouse coal gasification process is used with com- proposed. The objective of the Keystone Project is to bined cycle generation to produce electrical energy. produce methanol as a transportation fuel and fuel Atmospheric emission of sulfur dioxide and nitrogen supplement, a combustion turbine fuel for power genera- oxides will be about one-twentieth of maximum allowed tion, and a chemical feedstock. A 10,000 barrel-per-day values for conventional generation, and water use will be single-train module is planned to validate the commer- about 65 percent of the conventional facility because of cial applicability of the system. A feasibility and the low water requirement of the process. preliminary design study for this project has been proposed. Large Combustion Turbine Development Will Facilitate Construction of Combined Cycle Powerplants Lamp Division At Fairmont Proposes to Use the Westinghouse Gasifier The Westinghouse W501 combustion turbine has been designed with synfuel flexibility and combined cycle The Westinghouse Lamp Division at Fairmont, West applications specifically in mind. The combustors have Virginia, requires clean fuel gas, electric power, and been enlarged and space has been provided to accommo- steam for the production of electric light bulbs for

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-39

fluorescent and automotive use. To assure a fuel gas gasification process, which has been successfully tested supply, and to conserve energy, the Lamp Division in a pilot plant and in a 150 ton-per-day demonstration management chose a Westinghouse gasification system plant. Extensive pilot plant testing has been conducted to provide the clean fuel gas, power, and steam from a on some twenty solid fuels including lignites, bituminous, 13 ton-per-hour-coal-fed gasifier to fuel a 6-megawatt sub-bituminous and anthracite coals, coal liquefaction combustion turbine, with 50,000 pounds-per-hour of chars, petroleum coke, and other high ash coal-derived waste heat steam production, and 515,000 scf-per-hour materials. See page 4-22 of the June 1979, Cameron of medium-Btu fuel gas production. A feasibility and Synthetic Fuels Report for a description of the process. preliminary design study for this project has been proposed. Texaco is currently committing about $10 million to expansion and improvements of the Montebello Labora- II I/fill tory which will add a second train to the facility enabling additional studies to be performed. TEXACO INVOLVEMENT IN COAL GASIFICATION REVIEWED As part of an ongoing development program to improve the Texaco coal gasification process's performance and An update on Texaco's activities in coal gasification was efficiencyTexaco has the following projects underway: presented by W. Raymond Siegart in a paper entitled "Texaco Coal Gasification Technology," at the Electric • Optimizing coal/water slurry feed concentra- Power Research Institute (ERPI) conference in October. tions by improving the wet feed system, Texaco formed an Alternative Energy Department in • Optimizing gasifier operation for high mois- January 1980. James L. Dunlap was named Vice Presi- ture content coals such as lignite, dent of the Operating Department which brings together all the various alternative energy projects throughout • Continue a study program to increase the life the company. The Department is specifically charged of materials of construction, with the responsibility of converting non-petroleum raw materials to synthetic fuels, marketing the products, and • Improve the reaction heat steam generator commercializing technologies that are in the develop- (syngas cooler) design to maximize overall mental stage. thermodynamic efficiency, The Texaco Coal Gasification process (TCGP) converts a • Optimize the particle grind size as it relates solid fuel to synthesis gas. It developed from its to gasification efficiency and maximum predecessor, the Texaco Synthesis Gas Generation slurry concentration, Process (TSGGP) which converts mostly liquid fuels to synthesis gas. Various heavy residual oils, middle distil- • Evaluate the economic benefit of gasifier lates, and natural gas have all served as feedstocks to design features, the synthesis gas generation process and over eighty-five TSGGP plants have been installed worldwide. • Improve gasification instrumentation and control devices, By the late 1940's, Texaco recognized that coal could be used in the gasification process. Consequently, Texaco's • Investigate scale-up development to allow Montebello (California) research laboratory located east gasifier modules larger than 1,000 tons per of Los Angeles, California, initiated development work day. on a 15 ton-per-day coal gasification unit which resulted in the construction and operation of a 100 ton-per-day Texaco Has Two Fold Commercialization Plan demonstration plant in Morgantown, West Virginia, beginning in 1956. The Morgantown demonstration plant Texaco will utilize the coal gasification process in was supported by the Bureau of Mines. The synthesis gas synthetic fuels plants in two ways: first, equity involve- produced by gasification of an eastern coal was used to ment via Texaco, Inc., which is the responsibility of the make ammonia. The gasifier was a quench type with a Alternate Energy Department; second, marketing the water jacket between the pressure vessel shell and the technology to a broad number of end uses by licensing refractory; all the water in the coal slurry feed was the process directly from the Texaco Development completely vaporized in exchangers before entering the Corporation, a wholly-owned subsidiary of Texaco. gasifier which operated at 400 psig. Licensed Plants Briefly Reviewed The air blown Morgantown gasifier confirmed the follow- ing key design criteria for future gasifier scale-up: A 165 ton-per-day coal gasification unit was constructed burner design, gasifier volume and geometry, slurry at the Ruhrchemie Chemical Plant complex in Ober- pumps, grinding system, a Iockhopper system for slag hausen-l-lolten, West Germany, under license from removal, and materials of construction. Competition Texaco Development Corporation. This demonstration from low cost oil and gas, however, made the project plant which is jointly funded by Ruhrchemie A.G., Ruhr- uneconomical, and operations were discontinued. kohle A.G., and the West German Federal Ministry of Research and Technology began operation early in 1978. The oil embargo in 1973 heightened a renewed interest in The gasifier is used to convert coal into a Medium-Btu coal. Continued research and development, partially gas which is used as a feedstock for Oxo-Chemical supported by EPRI resulted in the present Texaco coal Manufacture. This demonstration plant which is about a ten-fold scale-up from the Montebello pilot unit, has also

4-40 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 provided information for the scale-up criteria to be The other award is for a IS month feasibility study for a considered when designing large commercial facilities. combined cycle, coal gasification project for Central An update of the operations at Oberhausen was given on Maine Power to generate 480 megawatts of power. This page 4-44 of the September 1980 Cameron Synthetic is a grass roots facility to be located at Sears Island, Fuels Report. Maine. This study has received full funding from the Department of Energy. This will be the first large-scale Two other licensed plants included the Tennessee Valley commercial application of the design which will evolve Authority's Project and the Tennessee Eastman Project. from the Cool Water Project. If, after the study, The TVA Project is designed to gasify 190 tons per day Central Maine decides to build the plant it is expected to of coal at 500 psig to produce feed gas for an ammonia- be operational in 1988 and save approximately 5 million synthesis plant. The plant began operation in October. barrels of oil per year using several 1,000 ton-per-day Texaco gasifiers. Tennessee Eastman Company will use the Texaco gasi- fier at its Kingsport, Tennessee facility. Industrial In addition to the Cool Water program cooperative chemicals, including acetic anhydride will be produced agreement, Texaco, jointly with other companies, is from coal. seeking Department of Energy grants for three feasi- bility studies under the second round solicitation for the Equity Projects Also Reviewed U.S. Government Synfuels Program.

The Cool Water Coal Gasification Project is Texaco's The first proposal for a IS month feasibility study most significant undertaking to date. (See page 4-22 of involves a 20,000 ton-per-day gasification facility in the June 1979 Cameron Synthetic Fuels Report for a Lucerne Valley, California to generate Medium-Btu gas review.) The project is a full scale development program to back out oil and natural gas in the Los Angeles Basin which includes the design, construction, start-up and area. The study will consist of using a coal slurry testing of a 1,000-ton-per-day coal gasification pipeline to transport the coal from a mine in the combined cycle demonstration plant near Barstow, Cali- Kaiparowits Coal Field in Utah to the plant site in the fornia in the high desert northeast of Los Angeles. Fuel Lucerne Valley where it will be gasified by a Texaco gas from the coal gasifier will primarily fuel a combined gasifier and distributed over a new Medium-Btu gas cycle facility where the gas will be employed as a gas transportation network. If the study proves feasible and turbine fuel and recovery heat will be converted to the plant is built, the plant would be operational in 1989 steam, producing a total of approximately 100 mega- and approximately 20 milion barrels of oil will be saved watts of electrical power through General Electric gas annually. and steam turbines. In an alternative mode the synthesis gas can fuel an existing 65 megawatt boiler at SCE's The second proposal involves a study of a cogeneration Cool Water station which will undergo burner retrofit to facility with Pacific Gas and Electric to be located allow efficient combustion. During September 1980, approximately 12 miles south of San Ardo, California, both Bechtel Power Corporation and the General This IS month study would evaluate the viability of Electric Company signed contracts to commit $25 mil- gasifying 4,000 tons per day of coal into Medium-Btu lion each. Bechtel and General Electric have been synthesis gas for generating steam and electricity. The involved with the other participants in the final proposed facility would generate 210 megawatts of elec- engineering design phase since early this year. tricity for Pacific Gas and Electric Company customers as well as providing operations in Texaco's oil producing The Cool Water Program submitted a cooperative agree- leases in the San Ardo Field. If this plant is designed and ment proposal to the U.S. Department of Energy in constructed it would be operational in 1987 and the net September, seeking a $25 million grant as part of the oil savings would be 14,860 barrels per day. In addition, second round solicitation offered by DOE to promote a petroleum coke will be evaluated as an alternate feed- national synfuels program. It is expected that Pacific stock for the coal gasification plant. Gas and Electric will become a participant after the California Public Utility Commission has given positive The third proposal investigates the feasibility of a com- consideration to their proposal. Serious negotiations are mercialized module design for an integrated industrial also underway with an oxygen supplier and others. synfuel combined cycle cogeneration plant at two General Electric plants. Each plant would produce Texaco has received two awards for feasibility studies, power, thermal energy (steam) and synthesis gas for each over $3 million, from the Department of Energy as industrial applications. If either plant is built, commer- part of DOE's first round grants for synfuels tech- cial operation would be expected in 1987. A total oil nologies. One of the grants is for a 14 month feasibility savings of 4,940 barrels a day would be realized from study for producing methanol from coal to be conducted gasification of 1,300 tons of coal per day. jointly by Texaco and Houston Natural Gas Corporation. Both companies have contributed substantial equity In addition to these projects, Texaco and Transwestern toward this study. The Medium-Btu gas of approxi- Coal Gasification Company submitted a proposal to DOE mately 300 Btu-per-cubic-foot produced from coal via in September, to evaluate the feasibility of constructing the Texaco Coal Gasification Process will produce about a commercial scale synthetic fuels plant near Lake 25,000 barrels per day of methanol, about 11,400 barrels DeSmet, Wyoming. This represents a modification of a per day of oil equivalent, for fuels or petrochemical previously announced study by the two concerns, which plant feedstocks. The capacity of the coal gasification now propose to become joint participants in the facility facility will be 6,000 tons of coal per day. It will be itself. Texaco would be the sole owner and operator of located adjacent to Texaco's oil refinery on the the mine that would supply the coal to the plant. Mississippi River at Convent, Louisiana.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-41 Approximately 38,000 tons of coal per day would be converted to approximately 127 million cubic feet of synthetic natural gas and 55,000 barrels per day of methanol. 11,/fill

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 LAND

FEDERAL COAL LEASE SALE To BE HELD IN between now and 1984. At this point, preliminary field JANUARY; INCLUDES SMALL BUSINESS SET ASIDE analysis indicates that lease applications which are likely to be found to meet the criteria for lease issuance in the The first long-term coal lease sale to be held under the next few years involve potential production rates of Department of Interiors new program for leasing approximately II million additional tons per year in the Federal coal will be held in three parts beginning in later 1980's. January 1981, and continuing with additional offerings in April and October of 1981. The first sale will be held January 13, 1981, at 2:00 PM, at the Bureau of Land Management's State Office in The sale, in the Green River-Hams Fork Region of Denver. Three tracts, all in Colorado, will be offered as northwestern Colorado and southern Wyoming, is follows: Danforth Hills No. I, in Moffat County 22 miles designed to yield approximately 13 million tons of new southwest of Craig, a maintenance production tract; coal production a year by 1987. The sale will be the first Empire, in Moffat County 8 miles south of Craig, annual offering of long-term coal leases that the Department production of 0.5 million tons; Grassy Creek, a small has held under a permanent leasing program since a business set aside tract in Routt County 10 miles south moratorium on Federal coal leasing was issued in 1971. of Hayden, annual production of 0.1 million tons. The leases selected for sale are the recommendations of the Regional Coal Team as accepted by the Secretary of The small business tract, the Grassy Creek tract, con- the Interior, Cecil D. Andrus, with the stipulation that tains 720 acres of land with an estimated 2 million tons the lessee shall comply with all valid and applicable laws of in-place Federal coal reserves which could be mined and regulations of Federal, State and local governmental by surface methods. The decision to offer a small authority. business tract for sale is provided for in the Federal coal management regulations and a memorandum of under- This language is a rewording of the stipulation originally standing between the Interior Department and the Small proposed by Governor Richard Lamm of Colorado. This Business Administration. The cooperative effort to set rewording is the result of discussions which have aside such a tract is to ensure that small business involved aides to Governor Lamm, Wyoming Governor Ed concerns are provided with an opportunity to lease I-Ierschler, and Assistant Secretary Guy Martin. See Federal coal as part of the overall Federal coal manage- page 4-43 of the June 1980, Cameron Synthetic Fuels ment program. Only small businesses, as defined in 43 Report for the latest overview of the new Federal Coal CFR 3420.1-4 and 13 CFR Part 121, will bid against each Management Program. other at this sale. Small businesses, however, are not precluded from bidding on any other tracts that will be The Regional Coal Team (RCT) recommended leasing ii offered for sale on the same day. tracts with about 450 million tons of reserves. Seven of the tracts should result in new mines with the production A sale January 14, 1981, at the BLM State Office in potential of 12.8 million tons per year. Four tracts Cheyenne, Wyoming, will offer three tracts, all in Car- containing 98 million tons of reserves were recom- bon County, Wyoming, as follows: Medicine Bow, 25 mended in order to maintain or expand existing opera- miles northeast of Rawlins, maintenance production; tions. In addition to recommending II tracts for sale, Rosebud, 40 miles east of Rawlins, annual production of the team also recommended that 5 tracts not be offered. 1.5 million tons, and Seminoe II, 35 miles east of Rawlins, maintenance production. "The tracts to be offered for sale," Secretary of Interior Cecil D. Andrus said, "were found by the team to be In April, on a date to be determined, four Colorado environmentally suitable for mining, to be economic for tracts will be offered: Danforth F-hIs No. 2 in Moffat coal production and to be consistent with social and County 24 miles southwest of Craig, 1.8 million tons of environmental needs of the region. On the other hand, annual production; Danforth Hills No. 3, in Rio Blanco the team recommended that three tracts be dropped County 12 miles north of Meeker, 2.2 million tons of because of adverse social, economic, and environmental annual production; Hayden Gulch, in Routt County 8 impacts." The RCT also recommended that a fourth miles south of Hayden, 2.8 million tons of annual produc- tract be deferred to permit study of impacts on the tion; and Pinnacle, in Routt County 13 miles southeast of winter antelope range (Red Rim in Wyoming), and that a Hayden, maintenance production. fifth be dropped from the sale to be offered in a later sale in combination with a larger tract to permit greater In October, also on a date to be determined, a Wyoming and more efficient coal production from the same area. tract will be offered: China Butte, in Carbon County 25 miles southwest of Rawlins, 4.0 million tons of annual If the antelope winter range study on the Red Rim tract production. As noted previously, the Red Rim tract may in Wyoming confirms that the tract is suitable, the also be offered in October. Regional Coal Team intends to recommend it for lease in October 1981. This would add 2 million tons per year of new production potential. Moreover, there are over 20 preference right lease applications in the Green River- Hams Fork Region which will be considered for issuance

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-43 Secretarial Issue Document Gives Background on the required, and, if the spur were not completed Lease Sale prior to the beginning of production, truck hauling on a major U.S. highway would be In October 1980, the Department of Interior released a required. The tract is divided by what may Secretarial Issue Document "Coal Leasing in the Green eventually be found as an alluvial valley River-Hams Fork Region." The Document contains the floor. Tract development would seriously Secretary of Interior's decision to lease the coal as well affect the small community of Maybell, as the Regional Coal Team's recommendations, and the where there is currently a moratorium on Bureau of Land Management's analysis of these recom- new building permits because a high water mendations. table is interfering with the existing sewage system. The development of the new rail The efforts leading to the decision of the Secretary to spur would likely encourage more coal deve- set the first sale began in July 1979, with adoption of lopment in the vicinity of the Lay tract, the land use plan supplements by the Bureau of Land extent of this development has not been fully Management that identified coal lands acceptable for analyzed in the EIS. Note that the rail spur further consideration for teasing, followed by a 5-week may be built to serve these other coal call for expressions of interest in leasing. See page 4-33 properties even if the Lay tract is not leased; of the December 1979 Cameron SyntheticFuels Report however, leasing the Lay tract now could for a detailed listing of those expressions. Using info r- only accelerate pressures for rail develop- mation from that solicitation and other geologic and ment. mining data, the U.S Geological Survey (GS) delineated 16 tracts. Based on site-specific analysis, the tracts "The RCT also recommends deleting the Bell were ranked by the RCT according to attributes of the Rock tract from this round of leasing because tracts in three categories: coal economics, impacts on it could be delineated as part of the larger the natural environment, and socio-economic impacts. and more productive tract once additional The overall ranking of each tract is presented in Table 1. geologic data are acquired. Development of this underground tract in its current con- Based on this ranking, the RCT selected five alternatives figuration would waste coal in barrier pillars, in the form of various combinations of tracts for cumu- which would not be the case if the tract were lative environmental analysis. Public meetings were incorporated into a larger unit. held in the region to identify issues for special attention in the environmental analysis. The Draft EIS was "The RCT recommends adding the Pinnacle published in April 1980. Over sixty people or organiza- tract to the maximum alternative. The tract tions provided comments on the Draft EIS. See page 4- was originally ranked low because it con- 41 of the June 1980 Cameron Synthetic Fuels Report for tained 80 acres of sharptail grouse habitat. a review of the Draft. These comments were used to This acreage has since been deleted from the prepare the Final EIS, which was published in August tract, and the RCT now finds leasing to be 1980. acceptable based on the revised boundaries. Following a review of the analysis contained in the DEIS, "Throughout this round of coal activity plann- and an analyses of the public comment received by the ing in the CR/HF region, the Red Rim tract DEIS, the RCT, at its meeting on July 22, 1980, reviewed has been designated 'acceptable for leasing, and confirmed its previous decisions concerning ranking pending further study.' This designation was and alternative composition. They made no changes in made because of the possible presence on the alternative rank or composition, and they reaffirmed the tract of winter range critical to antelope; High Alternative as the Preferred Alternative. At the these lands may therefore be unsuitable for meeting, the RCT also recommended a coal lease sale. all or certain stipulated methods of coal mining according to Criterion 15 of the coal On September 17, 1980, after the Final EIS was pub- management regulations in 43 CFR 3461. It lished, the RCT formulated a new recommendation based would be contrary to those regulations to on the analysis in the EIS and on their reconsideration of schedule the Red Rim tract for lease sale the leasing target. The RCT recommended a target of without resolution of this question of unsuita- 406 million tons (based on an annual production require- bility. Therefore, the RCT has recommended ment of 14.4 million tons) plus leasing 5 tracts to allow that scheduling the Red Rim tract be existing operations to extend production. deferred until July 1981, to allow acquisition and analysis of an additional ID months' data In its September 17 recommendation, the RCT revised on the critical nature of the antelope their preferred alternative by recommending deletion of habitat." the Lay and Bell Rock tracts and adding the Pinnacle tract, all in Colorado, and deferring a decision on the The tracts in the RCT's recommendation together with Red Rim tract in Wyoming, using the following rationale: their recommendation for sale schedule are presented in Table 2. "The Lay tract, with 82 million tons of in- place Federal coal and an estimated annual The decisions on the extent of new leasing must be production potential of 2.7 million tons, was reviewed with reference to the leasing target. The deleted because of transportation concerns-- Secretary adopted a target of 520 million tons of in- at least 25 miles of new rail spur would be place Federal coal in January 1980, including a 25

14..44 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 1 TRACT ALTERNATIVES

In-Place Federal Overall Hew Annual Map coal RCT Production No. (MM Tons) Rank 1/ (MM Tons) . - Comments

LOW ALTERNATIVE

Wyoming China Butte 5 74 High 4.0 Medicine Bow 12 27 High mp Red Rim 13 41 Medium 2.0 Would be ranked high if leased with China Butte. Rosebud 14 17 High 1.5 Seminoe II 15 28 High np

Colorado Bell. Rock 6 47 State:High isp Logically part of larger 8124: Medium tract. Leasing now may commit development of the larger tract.

Empire 16 52 High 0.5 Underground mine. Logical extension of two adjacent nines. Would beâome by- pass tract if not leased.

Grassy creek 10 2 High Small tract, possible set aside. No particular problems evident.

Danforth Hills I 7 40 High Northeast part of tract may become bypass if not leased.

Danforth Hills 3 9 72 High 2.2 About 30 percent of popu- lation resulting from Danforth tracts would be expected to go to Meeker. Only tract in Rio Blanco County to contribute to tax base there. Totals 400 10.2

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4.45 TABLE I (continued) TRACT ALTERNATIVES

In-Place Federal Overall New Annual Map Coal RCT Production No. (MM Tons) - Rank 1/ (MM 'lbna) Comments MEDIUM ALTERNATIVE: The above tracts plus Colorado Hayden Gulch 2 94 State:Medium 2.8 Significant wildlife range- 8I.M: High more easily mitigated than Williams Fork Mountain. - - High competitive interest. Totals 494 13.0 HIGH ALTERNATIVE: The above tracts plus Colorado Lay 1 82 State:L.ow 2.7 State ranked as least desir- BLM:Medium/ able of Colorado tracts Low because of transportation systems concerns. Possibility of population impacts to Maybell. ELM believes rail- road will be extended from the east. One of the most competitive tracts due to its isolation from existing opera- tions. Alluvial valley floor divides tract. Danforth Hills 2 8 54 Medium 1.8 Cumulative impacts would be severe if Danforth II were developed concurrently with Danforth 2 and 3, and the colowyo mine. Concern with wildlife impact if all Dan- forth tracts are developed. Totals 630- 17.5

4-46 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE 1 (continued) TRACT ALTERNATIVES

In-Place Federal Overall New Annual Map Coal RCT Production -- No. (MM Tons) Rank 11 (MM Tons) Comments MAXIMUM ALTERNATIVE

Colorado Pinnacle 4 I State:High rip As delineated, contains 80 13UI:Me4ium/ acres of eharptail grouse Low habitat that was determined "unsuitable" in land use planning. Unsuitable area has since been deleted from tract.

Isle Mountain Ii 39 Low 1.7 High air quality impacts. (Assessment has since changed.) tow coal recovery. Eagle habitat in Sections 3, 10, tI.

Williams Fbrk 3 41 Low 1.2 Relatively low coal yield. Mountain No railroad access. Critical winter range area. Totals 711 20.4

1/ Ranking as of December I), 1979. The RCT's final recommendation represents a shift in ranking.

2/ RIP : maintenance of productions no increase in annual production expected from this tract. Coal would likely be used to extend life of adjoining operation.

NOTE: In-place Federal coal and new annual production for the Danforth 2 and 3 tracts have lowered since the RCTs September 17, 1980, recommendation, based on updated figures from the USGS.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 4-47 TABLE 2 FINAL REGIONAL COAL TEAM RECOMMENDATION

In-Place New Annual. Federal Production Coal for 1987 Sale Month Map No. (MM Tons) (MM 'ibne) in 1981

Wyoming

China Butte 5 74 4.0 October Medicine Bow 12 27 mp 1/ January Rosebud 14 17 1.5 January Seminoe II 15 28 UP January

Colorado

Empire 16 52 0.5 January Grassy Creek 10 2 np January Danforth Hills 1 7 40 mp January Danforth Hills 3 9 72 2.2 April Hayden Gulch 2 94 2.9 April Danforth Hills 2 8 54 1.8 April Pinnacle 4 1 MP April TOTALS 441 12.8

Note: The Grassy Creek tract in Colorado is recommended for leasing under the set-aside program for small businesses. The in-place Federal coal and new annual production for Danforth 2 and 3 have been lowered since the RCT's September 17, 1980, recommendation, based on updated figures from the USGS.

1' mp: maintenance of production: no increase in annual production expected from this.tract. Coal would likely be used to extend the life of adjoining operation. percent security factor, to satisfy a then perceived 1987 At the First Federal-State Coal Advisory Board Meeting shortfall in annual production of 18.5 million tons. The in Denver in July, DOE presented a draft report on the Secretary also authorized additional leasing above the targeted production of the coal- leasing program. A 520 million tons to allow existing mines to extend their review of these goals is presented on page 4-47 of the operating lives; these tonnages would not count toward September 1980 Cameron Synthetic Fuels Report. The meeting the target. The 520 million ton coal target was final coal production goals were to be issued before based on the 18.5 million-ton-per-year difference bet- November 7, 1980, but were rescheduled before mid- ween the Department of Energy's (DOE's) 1979 projec- December publication because DOE was revising the tion of a production goal of 85.2 million tons for 1987 assumptions used in their determination including the and DOl's estimate at that time of production not synfuels requirements. This will undoubtedly result in a dependent on new Federal leasing of 66.7 million tons. higher requirement. In January 1980, Land and Water recommended that final The goals presented at the Coal Team meeting and leasing decisions be based on the best available coal released in a report in August, lowered the 1987 demand demand information, recognizing implicitly that the estimate for the Green River/Hams Fork Region from assumptions used by DOE in their 1979 production goals 85.2 to 76.2 million tons per year. were already obsolete.

4-48 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 In January 1980, the leasing target was expressed in two supply, environmental, socio-economic, and other legal ways, i.e., 520 million tons of in-place Federal coal and or policy criteria, but also on demand factors. 18.5 million tons of new annual production. The 520 million ton in-place figure was derived from the 18.5 In the current report GAO presents a background to the million ton annual production figure by factoring in new Federal Coal Management Program, including the average mine life, estimated recovery of coal, and legal constraints affecting Interior's coal leasing efforts. average Federal ownership of coal lands within the The court order mandating the environmental impact region, and adding a 25 percent cushion to address statement was noted as was the court order that GAO uncertainty ("security factor"). sees as even more far reaching: At their September 1980 meeting, the RCT recom- Natural Resources Defense Council, Inc. vs. mended a target of 406 million tons, which was calcu- Andrus, 448 F. Supp. 802 (D.D.C. 1978), modifying lated by applying the averages noted above to an annual Natural Resources Defense Council, Inc. v. Morton, production requirement of 14.4 million tons. This annual 388 F. Supp 829 (D.D.C. 1974). figure is the difference between DOE's updated 1987 goal of 76.2 million tons and BLM's estimate of 61.8 The constraint imposed by this 1978 order requires BLM million tons of annual production not dependent on new to complete over 200 environmental impact statements leasing. on livestock grazing lands by 1988 and to establish a schedule for compiling the statements. See the following article for a detailed discussion of the leasing goals. According to GAO, "Instead of doing separate environ- mental impact statements for coal and livestock, BLM decided it would be more efficient to do the environ- mental impact statements in conjunction with its land DOE'S PRODUCTION GOALS CRITICIZED BY THE use planning efforts. However, this may delay the GENERAL ACCOUNTING OFFICE timing for future lease sales because an Interior official estimated that about 80 percent of BLM's planning effort In August, The General Accounting Office (GAO) pub- was being directed to satisfy the court order. Lease lished a report "A Shortfall in Leasing Coal from Federal sales have been further delayed because BLM estimates Lands: What Effect on National Energy Goals?" The it will take about four years to complete each land use report concentrated on the Department of Interior's plan and environmental impact statement. Conse- implementation of the Federal Coal Management quently, land use planning where coal leasing is con- Program, with particular attention to the establishment cerned must be closely coordinated with the grazing of leasing targets (how much should be leased), the work requirements." selection of areas for land use planning (where to lease), and the delineation of lease tracts (how much can be GAO Makes Recommendations to the Secretaries of leased). Energy and the interior The proposed Green River-Hams Fork lease sale (see The following recommendations of the GAO are previous article) was selected for review because it is presented in their entirety. the first sale proposed by Interior under the new Federal Coal Management Program. GAO hoped to identify and "Limited tract delineation efforts in Green River-Hams evaluate problems relevant to the program and recom- Fork will preclude Interior from making available at this mended actions to improve its effectiveness in future late date sufficient quantities of additional coal to make efforts. up for the 1981 leasing shortfall. Therefore, the Secre- tary of the Interior should initiate immediate plans for a GAO contended that certain assumptions being used by follow-on sale--possibly in 1982--to meet the region's Interior in deriving its leasing targets are questionable projected coal demand. In re-calculating the regional and/or invalid. As a result--for the 1981 Green River- leasing target, he should: Hams Fork sale--at least three times more coal needs to be leased than is presently called for in the leasing • "Exclude production from the Cherokee mine. target. • "Allow for a more realistic lead time for The report is a follow-on to GAO's 1979 report, "Issues leases to reach full production. Facing the Future of Federal Coal Leasing," which identified many issues that could impede the develop- • "Require estimates for coal recovery, mine ment of sound Federal coal management and the use of life, and Federal coal ownership based on the Federal and non-Federal western coal in meeting the most recent, site-specific analysis. Nation's energy needs. • "Include a margin of error for the Geological In that report GAO recommended that Interior use Survey's coal reserve estimates. regional coal production goals as well as demand esti- mates for non-coal resources, as a regular part of its "Even more basically, however, Interior needs to improve evaluation of land use alternatives. Interior rejected the its target-setting process related to other future lease recommendation. GAO stressed that the application of sales. Because of its criticality, GAO recommends that resource demand to all resources would encourage com- the Departments of Energy and the Interior jointly prehensive land use decisions that are based not only on review the assumptions used in establishing leasing tar-

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-49 gets, including the factors indicated above, to assure Recommendation to the Secretary of Agriculture Also that sufficient coal will be leased to satisfy national Given energy goals, as well as to promote healthy competition. The review should be documented with a written report "The Secretary of Agriculture should require that the submitted to the respective Secretaries. Chief of the Forest Service: "To insure that areas of high-quality coal are not ignored "Direct his staff to rely on the Geological in future lease sales, the Secretary of the Interior Survey's standards for coal reserve estimates should: to be used for land use planning—as well as for tract delineation. "Add a requirement that the Bureau of Land Management formally and periodically "Coordinate with the Geological Survey as request, through the Federal Register, early as possible concerning proposed sites expressions of interest in possible lease for drilling so that the Geological Survey can tracts for all land use planning areas that plan drilling and other exploration activities contain Federal coal. needed to prepare for any future leasing---as well as for the preparation of land use plans." "Insure that land use planning for coal is not limited to so-called Known Recoverable Coal Comments on Leasing GAO Report Included in Secre- Resource Areas when development interest is tarial Issue Document indicated by industry and coal data is avail- able elsewhere. In addition to the Department of Interior submitting comments to the GAO in reply to the draft of that "Decide on whether, and if so how, threshold report, Interior also discussed the GAO report at length development levels will be used so that in the Secretarial Issue Document released in October present - uncertainty over how much leasing accompanying the decision to schedule the first sale in can actually occur in given areas is January 1981. eliminated. In that report, Interior pointed out reasons for disagree- "The new coal program requires substantial amounts of ment between GAO's and Interior's assumption. coal data for use in numerous analytical and decision- making steps. To meet this need, the Secretary of the Regarding the Cherokee mines production figure, the Interior should require the Director of the Geological Secretarial Document explains Interior's reasons for Survey to including production from that proposed mine in the updated baseline figures. According to Interior: "Develop long-range plans, at the field level, for coal exploration activities in direct "This operation would be a joint venture of support of tract delineation, and obtain NERCO, which holds coal leases on the Federal formal public input on potential exploration sections in this checkerboard area, and Rocky areas. Mountain Energy (RME), owner of the mineral estate in the private sections. In their August 1980 "Appoint permanent tract delineation team report GAO suggests that the five million ton per leaders for all coal regions where leasing is year production from Cherokee should not be anticipated. included in the baseline, based on information GAO obtained from RME that the coal at the Cherokee "Clarify procedures for making reserve esti- property would begin production only in 1990. If mates and establish formal procedures for GAO's assertion were true, the annual production quality controls in the reserve estimate com- requirement for 1987 would increase by 5 million putation process. tons per year. However, there are mixed signals on Cherokee start-up date. NERCO, in its written "In addition, the Secretary of the Interior should require comments on the Draft EIS maintains that Chero- the Director of the Bureau of Land Management to kee would start production in 1986. NERCO's coordinate with the Geological Survey before determin- statement tends to indicate that inclusion of ing the time to be allotted for the Geological Surveys Cherokee's production in the baseline is, in fact, work in activitiy planning—allowing, if possible, at least appropriate, and that the production requirement one drilling season for the tract delineation process. from new Federal leasing need not increase." "To promote drilling by the private sector, the Secretary Rocky Mountain Energy commissioned ICF to analyze of the Interior should: the DOE's production goals. The next article reviews that report. As ICF prepared the national coal model "Develop explicit procedures under which used as the basis for determining the targeted goals, land exchange applicants could drill candi- ICF's comments are especially significant concerning the date exchange tracts. model. "Inform companies or others when they 111/111/ obtain an exploration license that they will or will not be allowed to bid on the tract if it is offered for lease."

4-50 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

INDUSTRY ALSO CRITICAL OF DOE'S COAL ICE was commissioned to examine these issues by PRODUCTION COALS developing forecasts of future national coal supply and demand, exploring the sensitivity of the forecasts to key The "Preliminary National and Regional Coal Production uncertainties, and analyzing the forecasts embodied in Goals for 1985, 1990, and 1995' released by DOE in the DOE coal production goals. August was of concern to the GAO as reported in the previous article, and also to industry. ICEIncorporated was chosen to prepare these analyses because of the firm's expertise in the development and The draft of these goals were presented at the State- use of mathematical models of coal and electric utilities Regional Coal team meeting in July and reviewed on market interactions. The National Coal Model (NCM) page 4-47 of the September 1980 Cameron Synthetic used by DOE for its coal production forecasts was Fuels Report. Except for minor editorial changes which originally developed by ICF in 1976, and refined by the did not affect any of the numbers, the preliminary report firm in 1978. ICE has continued to refine and expand its was indentical to the draft report. The final report, own version of that model, now referred to as the ICE scheduled to be released November 7, was rescheduled Coal and Electric Utilities Model (CEUM). for release in December as the Department of Energy was revising its assumptions. Table I gives the produc- Three tasks were conducted by ICE Incorporated, for tion forecast by DOE supply region. Rocky Mountain Energy Company:

Because of its concern about the amounts and types of • forecasts of future national coal supply and federal coal to be leased, Rocky Mountain Energy asked demand for 1985, 1990, and 1995, using the ICE, Incorporated, to examine two important questions CEUM; regarding the goals released in August: • analyses of the sensitivity of projected pro- • Do the DOE production goals accurately duction and consumption patterns to changes reflect future demand for coal from specific in key parameters (e.g., the level of demand producing regions? for coal, the structure and cost of coal transportation networks, or the quantity and • How should DOE production goals be inter- quality of coal available from supply regions), preted in making federal coal leasing also using the CEUM; and, decisions? • an analysis and critique of DOE's preliminary regional coal production goals.

TABLE I DOE PRELIMINARY COAL PRODUCTION FORECASTS FOR 1985, 1990, AND 1995 BY SUPPLY REGIONS (Million Tons)

1905 1990 Actual Lou Redo, 1976 Medium High Low Medium High Low Medium High

Northern Appalachia 162.7 153.9 166.4 170.2 177.4 232.7 279.0 220.6 303.7 399.7 Central Appalachia 106.6 209.2 214.1 223.5 200.7 210.2 224.2 176.4 186.9 202.7 Southern Appalachia 20.7 17.0 17.7 16.4 11.1 11.1 13.6 9.7 12.1 13.9 Total 370.0 360.1 399.2 412.1 309.2 454.6 516.0 408.7 502.7 616.3

Midwest 112.2 165.1 192.2 201.4 203.0 201.1 343.9 248.7 374.7 428.2

Total East 492.2 545.2 503.4 613.5 592.2 735.7 860.7 657.4 077.4 1,044.5

Eastern Northern Great p lains 14.3 22.7 22.7 26.3 31.3 49.1 72.6 49.1 68.9 102.5 Western Northern Great Plains 05.4 175.0 211.2 277.7 243.2 336.0 503.7 449.3 705.9 Total 99.7 197.7 233.9 306.0 274.5 394.1 576.3 331.1 510.2 086.4

Central west 13.9 7.6 0.5 ,9.3 8.4 13.3 16.4 11.0 21.3 28.3 Gull 10.0 31.4 32.4 33.5 03.4 90.5 140.1 101.0 140.7 181.4 Rockies 22.2 54.6 62.2 66.9 76.1 01.8 94.0 01.4 98,6 107.9 Southwest 21.7 39.0 41.2 47.2 $1.3 65.3 69.7 52.9 59.7 63.7 Northwott 4.7 3.7 4.0 4.0 2.9 4.1 4.0 1.4 1.6 7.52/ Total 02.5 136.3 146.3 160.9 222.1 255.0 325.0 209.3 321.9 380.0

Total Went 182.2 1 334.2 382.2 466.9 496.6 639.1 901.3 560.4 840.1 1,277.2

TOTAL U.S. 664.4 079.2 962.6 1,060.4 1,088.5 1,374.8 1,762.0 1,237.0 1,717.5 2,321.7

Includes Alaska

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-51

Rocky Mountain Energy released a report presenting the • "overly restrictive specification of regional results of the third task in October. The findings of non-utility coal demands, further distorting Tasks I and 2 are presented in the ICE report entitled coal demand and production patterns. Forecast and Sensitivi ty Analysis of Western Coal Pro- duction, also prepared Rocky for Mountain Energy Com- "If the NCM is to be used to make more credible pany in October 1980. Relevant portions of that report absolute forecasts of regional coal production, then the are incorporated into the critique of DOE's regional data inputs will need substantial improvement. How- production goals. ever, even if all known errors are corrected, uncertainty will remain that can significantly affect the forecasts. AS ICE developed the NCM, their report to Rocky These uncertainties include the following: Mountain Energy is especially significant. ICE reviews many of the key inputs and structural elements used by • "market uncertainties such as electricity load DOE to develop the coal production goal forecasts. • growth, steel demand, demand for industrial NCM weaknesses and errors are defined in the report. steam, etc.; "Among these problems are: • 'policy uncertainties such as coal slurry pipe- line legislation, restrictions on oil and gas • "inaccurate assessment of regional coal use, tax policies, etc.; and, reserves, in both the type and quantity of coal; • "data uncertainties such as coal reserve quantities and qualities, remaining physical • 'erroneous specification of mining costs in life of existing capacity, etc. some regions, affecting the relative attractiveness of coal from competing supply "These uncertainties severely compromise the utility of regions and within regions; any forecasts of absolute levels of production. Since these uncertainties clearly exist, the effects of these • "distortions in the absolute and relative costs uncertainties on regional coal production forecasts of the coal transportation network, affecting should be rigorously evaluated." relative delivered prices of coal from various supply regions; As part of ICF's analysis, they made several forecasts using runs of ICE's Coal and Electric Utilities Model • 'outdated estimates of planned coal and (CEUM). These forecasts included a base case forecast, nuclear power generating capacity, affecting and explored the sensitivity of these forecasts to several regional coal demands; and key uncertainties. Table 2 shows the changes in 1990

TABLE 2

SENSITIVITY OF 1990 COAL PRODUCTION IN GREEN RIVER-HAMS FORK REGION Increase In Increase Increase Reserves (Decrease) (Decrease) As Percent 1990 / From InReserves Of 1981 Production!I' Base Case Needeo Leasing Scenario (106 Tons) (lO6Tons) (106 Tons) " Target

Base case 51.95 - - - Low Demand 44.03 (7.92) (238-475) V.6-91%)

High Demand 77.03 25.08 752-1505 145-289%

Low Transportation Rates 61.31 9.36 281-562 54-108% Constrained Powder River Basin and Southwest Production 79.15 27.20 816-1632 157-314%

8/ Source: ICF Incorporated, Forecasts and Sensitivity Anal ysis of Western coal Production (October 1980).

Assumes 30 to 60 tons of reserves per ton of annual production.

s/ Based upon Green River-Hams Fork 1981 leasing target of 520 million tons.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 production in the Green River-Hams Fork region as a • "Green River-Hams Fork production appears result of changes in key parameters. In some cases, the high, reflecting data input inaccuracies with 1990 production is forecasted to be half again as much as respect to rail rates and the heat content of the base case forecasts. The corresponding increment in the coals in this region. reserves needed to support this production can be as much as three times the planned 1981 leasing target for • "Uinta-Southewest Utah production appears that region. high in 1985, generally consistent in 1990, and low in 1995. This reflects changes DOE In addition, ICF found additional problems relating to the made to the Utah reserve base data without structure of the model that significantly limited the making similar changes for the competing value of the NCM forecasts as inputs to the preparation regions. of regional coal production goals. The most significant problem is that the geographic regions used in the NCM • "Denver-Raton Mesa production appears low, do not correspond to the coal leasing regions used by because this is not an NCM forecast but an Do'. assumption DOE made based on incomplete data. Furthermore, the coal supply regions used in the NCM are not geographically delineated in a manner which • "San Juan River production appears high in permits conversion to the 001 leasing regions for the key 1985, generally consistent in 1990, and low in Western states where the bulk of federal coal leasing 1995, reflecting problems with the reserves will occur. While the state of Montana is properly split data and transportation rates. into Fort Union (Montana East) and Powder River (Mon- tana West) and the states of Utah and North Dakota can "In other regions or states, the DOE forecasts sometimes be included as entire supply regions in their respective appear to be consistent with new mines survey data and leasing regions (Uinta-Southwest Utah, and Fort Union), other forecasts. However, examination of the com- three other Western states are not geographically ponents of the production and distribution of those modeled in the NCM to be aggregated into leasing regions' production indicates that the agreement may regions. These states are: Wyoming, which is modeled only be the coincidental result of several overstatements as one region but is split into the Green River-Hams and understatements in the NCM inputs which tend to Fork and Powder River Basin regions; Colorado, which is cancel each other out. modeled as Colorado North and South but is split into four leasing regions (Uinta-Southwest Utah, Green "The range of production estimates among different River-Hams Fork, Denver-Raton Mesa, and San Juan modeling efforts and within the scenarios examined River); and New Mexico, which is modeled as one region within a single modeling effort make it clear that but leased in the regions of San Juan River and Denver- uncertainty in key data inputs results in substantial Raton Mesa. The conversion problem is further compli- uncertainty in the production forecasts. In many regions cated because the reserve data upon which the NCM is the range of the production forecasts is so wide that a based do not accurately reflect the types and quantities "best estimate" within this range cannot warrant a high of coal found in each of the leasing regions -- this leads level of confidence. It is not clear that any middle point to distortions in the model results which affect both coal within such a broad range is necessarily more reasonable production levels and the types of coal produced from than the extremes of the range. the supply regions. "The uncertainty reflected in DOE's national production The following comments were contained in the summary estimates for 1990 show a high case nearly 400 million of ICF's report and relate to DOE's 1990 forecasts unless tons more than the medium case. If these production otherwise noted. goals are translated into tons of reserves needed to support production, the high case would indicate a need "Appalachian production appears low while for an additional 12 to 24 billion tons over that implied Midwest production appears high. These by the medium case. somewhat offsetting discrepancies reflect such data input problems as transportation "Models such as the NCM can be very helpful in indicat- rates, coal reserves, mine costing, and sulfur ing the amount of coal demanded from certain aggrega- emission limitations. tions of regions, particularly when the models are used to conduct sensitivity analyses that indicate the relevant "Aggregate production in the Powder River range of uncertainty in the production forecasts. But Basin appears somewhat high, reflecting the such models cannot be responsibly used independently of assumed low rail rates. Within the Powder other considerations to develop point-estimate produc- River Basin, Montana production appears low, tion forecasts of particular coal-types from particular reflecting such data input problems as sulfur regions. content of reserves and mine costing. "Regional coal production goals should also indicate the "Fort Union production appears high, reflect- quality of the coal demanded (e.g., Btu and sulfur ing the assumption of a lot of synfuels pro- content). Setting production goals on the basis of duction in that area, and also a structural tonnage alone may not cause needed coal-types to be problem in which NCM perceives the North made available, restricting the supply of desired coal- Dakota lignites as being locally available in types. The NCM produces regional forecasts by type of Minnesota. coal, and these outputs should not be ignored in formula- ting coal production goals.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4_53 "At the same time, it should be recognized that in a GREEN RIVER-HAMS FORK FINAL ENVIRONMENTAL model such as the NCM (and in the real-world), the IMPACT STATEMENT RELEASED assignment of the last increment of production to a coal- type and region is made on knife-edged trade-offs, where The Final Environmental Impact Statement (FEIS) for the model is in essence indifferent between particular the Green River Hams Fork Coal Production Region was regions or types of coal. Hence, the production goals released in September. A review of the Draft EIS should also reflect considerations such as: appeared in the June 1980 Cameron Synthetic Fuels Report. The final EIS differs from the Draft because of • producer's expressions of interest, adjustments in the baseline (or no Action Alternative) and changes to some of the assumptions and data used • consumer's indications of potential demand, for the original analysis. These changes are: • regional land use patterns, • A decrease of the projected coal production • environmental concerns, from the study region without new Federal • socioeconomic concerns, and coal leasing. See Figure I for projected cumulative coal production. • regional patterns of coal industry competi- tion. • Earlier anticipated dates for construction and mining for the proposed coal lease tracts. "In developing production goals based upon model fore- casts and other considerations, the principal objective • Refinement of the coal reserves and should be to lease enough coals of the right types in the projected production from the coal lease aggregate. The markets can respond to shortages in tracts. some regions by substituting similar coals in nearby regions, provided that adequate reserves of coal are In Colorado, the annual coal production projections available in those other regions. Accordingly, the (baseline) were reassessed and lowered by 6.59 million leasing program for a region should not only be able to tons in 1987, 7.79 million tons in 1990, and 8.79 million meet that region's goal but also be able to offset tons in 1995. For Wyoming, population projections from unexpected shortfalls in other regions." the anticipated baseline coal production did not include three proposed mines (Hanna South, Carbon Basin, and // II II ft Cherokee) and a portion of the production from the existing Rosebud mine. The Wyoming population projec- tions and related impact analyses in the FEIS were

Coal production million tons - p .. ysr

Not.: To d.t.rmin. thu production tron, 'fly Federal action .lt.rn.tivu, subtract tln* No Action production Iron, thu d.sir.d Federal Action •It.rnati,w.

70

6705, MaximumAIt.n,.tivs 64 55 62.65 pr.t.rr.d or I41uh Aiternitiva 60

56 33 Mudium Att.m.tit. 55.05 If / 53.55 Low Aituntitin. $2.!!

No Action Ait.rr,.tin 40 40.15

30- I I 1965 5967 1990 5915 tin.. Frsnua

FIGURE 1 PROJECTED CUMULATIVE COAL PRODUCTION

4-54 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 corrected to include these omissions. Also, there was a The following is the summary of fbi's Environmental reassessment of the estimated acres disturbed in the No analysis from the Secretary issue Document. Action Alternative. Tables 1 and 2 show the revised projected coal production from the study region and "The region will likely experience severe estimated acres disturbed without new Federal leasing. population growth under the no-action alter- native. This growth results largely from The analysis in the DElS was based on the assumption development of oil shale tracts C-a, C-b, and that construction on the tracts would begin in 1987 with the Superior property; from an increase in oil production following in 1989. This did not conform to and gas drilling activity; from recreation the Department of Interior's projection that assumed developments; and from increases in coal production would need to be underway by 1987. To be production not dependent on new Federal consistent with this approach, the FEIS analysis was leasing. New Federal leasing would exacer- adjusted to assume that construction on the tracts would bate the attendent problems of rapid popula- begin in 1985 and production would occur in 1987. tion growth.

The Secretarial Issue Document supporting Secretary of • "Impacts to big game species--deer, elk, and Interior Andrus' decision to offer teases for sale in the antelope--would be locally severe as a direct Region refers to certain environmental analysis in the result of mining disturbance of habitat. This EIS that were of special significance. is especially true with the simultaneous development of the three Danforth Hills

TABLE 1

PROJECTED COAL PRODUCTION FROM THE STUDY REGION WITHOUT NEW FEDERAL LEASING

Production(million tons) State - Company 1985 1987 1990 1995

Wyoming

Medicine Bow 2.5 2.5 2.5 2.5 Seminoe I 2.3 2.3 0 0 Semi noe II 3.5 3.5 3.5 3.5 Energy Development 1.3 1.3 1.3 1.3 Rosebud 2.0 2.0 2.0 2.0 Carbon County Coal 2.2 2.2 2.5 2.5 Hanna South 0.5 0.6 0.6 0 Carbon Basin 0.0 1.5 5.0 5.0 Cherokee 5.0 5.0 6.0 6.0

Subtotal 19.4 20.9 23.4 22.8 Colorado

Colowyo Coal Company 4.3 4.3 4.3 4.3 Empire Energy 2.4 2.4 2.4 2.4 Energy Fuels Corporation 4.0 4.0 4.0 4.0 Energy West, Inc. 2.0 2.0 2.0 2.0 Northern Minerals Company 1.2 1.2 1.2 1.2 Peabody Coal Company 2.0 2.0 2.0 2.0 Pittsburg 8 Midway 1.2 1.2 .9 0 Rockcastle Company .25 .25 .25 .25 Sun Coal Company 0.5 0.5 0.5 0.5 Sunland Coal Company 0.1 .10 .10 .10 Utah International, Inc. 2.3 2.3 2.3 2.3 W. R. Grace & Company 0.5 0.5 0.5 0.5

Subtotal 20.75 20.75 20.45 19.55

Total 40.15 41.65 43.85 42.35

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-55 TABLE 2 CUMULATIVE REGIONAL SURFACE ACRES TO BE DISTURBED WITHOUT NEW FEDERAL LEASING

1985 1987 1990 1995

COLORADO

COAL-RELATED

Mine Area Disturbed 7,310 8,051 12,977 12,977 1,850 2,500 2,500 2,500 Mine Facilities and Related R/W 1/ 1' Powerlines 1,880 1,880 1,880 1,880 Powerplants 3/ 380 380 380 380 Railroads 3r 500 990 1,090 1,090 Total DlstuFbed 11,920 13,801 18,827 18,827 Acres Reclaimed 2/ 3,480 4,067 9,203 9,203 Total Permanently Removed 4/ 980 1,420 1,525 1,525

NON COAL-RELATED

Oil Shale Superior (project) 435 438 447 463 Superior (housing) 990 990 990 990 Ca 1,215 1,517 1,970 2,725 Cb 897 935 992 1,087 Oil and Gas 5,593 6,645 8,606 13,242 Uranium - 623 623 623 623 Population (total) 3,706.8 3,830.1 3,995.1 4,001.0

WYOMING

COAL-RELATED

Mine Area Disturbed 7,700 10,600 15,000 22,300 Mine Facilities and Related R/W 1/ 850 900 900 900 Ancillary Facilities 5/ 1,050 1,150 1,250 1,250 Facility Relocation 67 400 500 500 500 Total Disturbed 10,000 T3, 150 17,650 24,950 Acres Reclaimed 6,200 7,900 10,350 14,500 Total Permanently Removed 1,450 1,650 1,750 1,750

NON COAL-RELATED

Total 7/ 1,500 1,900 2,400 3,300

Population 2,573 3,449 3,574 3,357

TI Includes haul roads, access roads, and coal exploration trails. 27 Includes acres reclaimed for mine areas and powerlines. 11 This acreage considered removed from production for time frames indicated. long term 47 This acreage considered permanently removed from production over - (includes acreage for access roads). 5/ Includes access roads, rail spurs, and powerlines. / Includes powerline, telephone line, and Highway 789 relocation. 1' Includes acres disturbed by oil and gas production, uranium, sand and gravel, prison construction, etc.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 tracts, with development of the Red Rim Comment: tract, with the simultaneous development of the Hayden Gulch and Williams Fork Moun- Figure I appeared as Figure 2-2 in the Final Environ- tain tracts, and with development of the Lay mental Impact Statement and was entitled: tract. "PROTECTED CUMULATIVE COAL PRODUCTION." While the figure shows the projected production, we are "Transportation impacts would be locally inclined to agree with what might be the best Freudian severe in Colorado as a result of hauling coal slip we have seen in a long time. Indeed it does appear by truck on the public road system, and that the Federal Coal Land Management Program and increased vehicular traffic associated with especially the EIS is 'protecting' the coal. population increases. f/fill,, "With respect to the socio-economic and transportation impacts, three points bear highlighting. First, oil shale U.S. DISTRICT COURT RULES ON ALLUVIAL VALLEY development may not proceed on the relatively acceler- FLOOR ISSUES ated schedule suggested in the EIS. Second, there is some indication that the model used to predict popula- On August 15, 1930, Judge Thomas Flannery of the U.S. tion dynamics overestimated oil shale population effects. District Court for the District of Columbia ruled on a Finally, the identification of these impacts has resulted suit affecting land exchange provisions for alluvial valley in consultation with the State of Colorado to develop floor lands and unsuitability criteria applied under both lease stipulations, that would aid in mitigation of socio- the Surface Mining Control and Reclamation Act and the economic and coal transportation impacts. (See the Federal Land Policy and Management Act. The suit was article on the announcement of the Green River-Hams was filed by Texaco, Inc., and the National Coal Associa- Fork coal lease sale for a discussion of the lease tion, et al. against Cecil Andrus, Secretary, Department stipulations). of Interior, et al. Originally, the plaintiffs had requested that the suit be combined with the permanent program "The RCT has recommended that the Lay tract be litigation over the Surface Mining Act (See Surface deferred and has not recommended any leasing for the Mining article, this section). However, since the suit Williams Fork Mountain tract. These actions would addressed both FLPMA and SMCRA, this request was minimize the localized impacts to critical wildlife denied. The settlement of the suit will affect alluvial habitat. The RCT has recommended offering all three valley floor issues and unsuitability criteria for mining Danforth Hills tracts; again, as a result of identification on Federal lands under both programs, as Judge Flannery of the severe impacts in the EIS process, the Colorado largely upheld charges by Texaco and the National Coal State Office of BLM and the State of Colorado Division Association that the Interior Department overstepped its of Wildlife have developed a lease stipulation which will statuatory bounds. aid in the mitigation of the impacts to deer and elk habitat. The suit addressed several issues. A short summary of the Court's findings is presented below: "Over 60 people and organizations provided numerous comments on the Draft EIS. These comments and The Court found that the Department of the responses are presented in Volume If of the Final EIS. Interior is mistaken in its belief that it has a While no summary can substitute for a review of the discretionary authority to exchange federal actual comments and responses, common themes can be coal lands for private coal lands when alluvial identified. Generally, commentors representing environ- valley floors exist on that land, making it mental groups and some individuals thought an adequate unsuitable for mining. Congress meant this case for new leasing has not been presented and that the land exchange to be mandatory under these coal management program has not been faithfully conditions. applied, especially in the area of application of the lands unsuitability criteria. Comments from members of the The Bureau of Land Mangement may not coal industry generally expressed concerns about the disqualify for an exchange, a private owner environmental analysis of their unique geographic areas of a coal deposit located in an alluvial valley of concern and suggested that additional leasing is floor, if the owner has surrounding deposits needed beyond that contemplated in the EIS. which can still be mined without substantial loss in value because of the alluvial valley Federal agencies provided specialized comments in their floor prohibition. area of expertise which generally supported analysis in the EIS. State and local government agencies also In considering lands unsuitable for mining, provided specialized comments. Of special note are the the Court found that material incorporated in concerns of State and local governments for the effects the regulations on unsuitability which pro- on the community services and social structure that vides the statuatory basis for the regulations, would be generated from rapid population growth. Some does not need to accompany the regulations local governments suggest that DOl's leasing actions be when published. The NCA had contended structured in such a way to phase development at a rate that the Secretarial Issue Document had not that would allow for less rapid growth.' accompanied the regulations and was also not specific enough on statutes. The Court found in favor of the Department of Interior.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-57 The Court found in favor of Texaco and the SURFACE MINING ACTIVITY REVIEWED NCA in regard to exemption of land from unsuitability criteria when the operator has Highlights of activity under the Surface Mining Act for expended substantial legal and financial this quarter include the acceptance by the U.S. Supreme commitments before the date of the Surface Court of both the Virginia and Indiana suits and the OSM Mining Act, January 4, 1977. The Act says rulings on state plan approvals. Several new court suits that all criteria will be exempted for these were also filed on aspects of the permanent program operators. Under Department of Interior during the quarter. The major activities in the surface regulations, there is no provisions for an mining for the months of August, September and October exemption under endangered plant, bird, and are summarized here under five categories: Regulations, animal species criteria. The Court found Legislation, Litigation, Policies, Studies and Programs, that Interior must provide this exemption. and State Programs.

When considering lands unsuitable for mining, Regulations the Department of Interior has included all lands under study for inclusion within a Federal Register, August I: national park, forest, or wildlife refuge. The An interpretive rule is proposed under the permanent Court found that only those lands now regulatory program that an operator of a long duration included within these areas may be desig- underground coal mining operation may apply for nated as unsuitable. approval of an alternative postmining land use through permit revision procedures towards the end of the mine The Court found that Interior had only life rather than in the initial permit application. The included two categories of exemption in original permit application must demonstrate that the regard to mining within 100 feet of a public land will be returned to its pre-mining land use capa- road right-of-way. A third exemption, man- bility. dated by the Act must be included. This exemption reads where "the interests of the Federal Register, August 4: public and the landowners affected thereby will be protected." Interior conceded this Suspends regulations challenged in court under the point. Permanent Surface Mining Regulation Litigation. Twenty-five sets of regulations are suspended and are The Court found that the Interior regulation listed by section. OSM intends to propose appropriate declaring land unsuitable for mining which is revisions to these rules in the future. located on riverine, coastal, and special floodplains unless mining will not threaten Federal Register, August 6: people or property, lacks statuatory support, Promulgates final bonding regulations. Operators will be in that, the correct regulation requires the able to pledge high-rated securities as collateral to Secretary to demonstrate a substantial secure bonds. A new procedure will allow the combining danger of life and property before obtaining of surety bonding and escrow account bonding. The an unsuitability ruling. surety/escrow plan would permit surety companies to issue bonds for periods as short as two years. For self- In addressing regulations which require that a bonding, OSM reinstated a requirement that operators municipality or responsible government show a net worth of six times the bond amount in order agency concur in the granting of a lease on to qualify for self bonds. OSM plans to issue guidelines land which has been set aside for a municipal to states on when to accept operator self-bonds and how watershed, the Court found that local to judge the value of the collateral. government veto power is not authorized by the Act. Federal Register, August 15: The Court found that the Department of Reopening of the comment period on Pennsylvania's Interior may apply unsuitability criteria to all program for fifteen days for comments on the anthracite non-producing leases issued prior to the provision in that program. Surface Mining Act and to all future leases under the Federal Coal Management Act but Federal Register, August 25: that he may not apply criteria under the Extends the comment period for the interpretive rule on FLPMA to the leases issued when only durable rock fills at the request of industry for the SMCRA was in force. purpose of submitting additional technical data. The Department of Interior clarified a regu- Federal Register, August 25: lation that requires that all applicable unsuit- ability criteria be tested to see how many Reopens the comment period for the proposed rule apply. After this, all exceptions and exemp- revising the grandfather exemption as applied to prime tions will be applied to determine if there are farmland in light of recent court decisions. circumstances under which the area may still be considered suitable for mining. Federal Register, August 27: Proposes amendments to rules on the date of submission I/I/il II of applications by mineral institutes for grants to con- duct instruction and research in mining and mineral extraction.

4-58 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Federal Register, September 3: Federal Register, October 10: Notice is issued by OSM of the intent to enter into a Notice of approval of the permanent regulatory program cooperative agreement with Montana for the regulation submissions from the State of Louisiana. of surface coal mining and reclamation operations on federal lands under the permanent regulatory program. Federal Register, October 10: Federal Register, September 4: Final rules to clarify OSM authority to impose admini- strative sanctions against permittees found to be in Final rules concerning assessments of penalties in cases violation of any requirements of the Surface Mining Act of non-abatement of violations. These rules modify under the interim regulations. amounts of penalties, mandate case history reviews and provide appropriate enforcement actions. Federal Register, October 30: Federal Register, September 12: OSM requires amendment and seeks public comment in the evaluation and study of self-bonds. Because previous Notice of availability of the draft combined petition self-bonding rules were found to be unacceptable, the evaluation and environmental impact statement evaluat- subject will be studied before further amendment. This ing whether certain lands in Southern Utah are suitable plan of action proposed to reevaluate the basic criteria for coal mining and reclamation operations. of self-bonds, analyze financial parameters, and develop rules governing self-bonding for proposal. Federal Register, September 15: Revision of one portion of the interim regulations Federal Register, October 31: program clarifying the scope of exemption available for Notice of partial approval /disapproval of the permanent anthracite operation in the Commonwealth of Penn- program submission from the State of Illinois. sylvania. Legislation Federal Register, September 23: A proposed rule to amend regulations which require In August, Senate Majority Leader, Robert Byrd (D- filing of financial and performance reports under the W.VA.) proposed amendments to a House-passed bill State Reclamation Grants on a quarterly basis and to entitled the "Vessel Tonnage Measurement Act" which identify specific forms for grant applications for the would amend the Surface Mining Act. The amendments abandoned mine reclamation program. were similar to S. 1403, the so-called "Rockfeller amendment," which would give the states more flexi- Federal Register, October I: bility in setting up reclamation programs. The purpose of this move was to circumvent the House Interior Final interpretive rule on post-mining alternative land Committee, headed by Morris Udall (D. Arizona) who is use for a long-duration underground coal mine. opposed to any changes in the Surface Mining Act. (See the March 1980 issue of the Cameron Synthetic Fuels Federal Register, October 1: Report, page 1-28). The Vessel Tonnage Measurement Amendment of procedures for approval of state Act had already been passed by the House and therefore programs by changing time limitation for approval of re- served as an appropriate vehicle for passage of the submitted programs. Disapproval of the State of Ohio's Surface Mining amendments. However, it is felt that the permanent program submission. bill would be vetoed by the President if it was passed by both houses of Congress because the Vessel Tonnage Act Federal Register, October 1: is of little concern to the administration. It is also felt that a more appropriate bill would have been one of Notice of proposed rulemaking, public hearing and exten- more importance. sion of public comment period on the Wyoming Coopera- tive Agreement. In August, the Senate voted to limit debate on the bill and thus eliminate the possibility of a filibuster. The Federal Register, October 3: Senate then voted to pass the bill and send it to the Notice of receipt of the abandoned mine lands reclama- House floor for a vote. The House rejected the Senate tion plan submission from the State of New Mexico and amendments and requested a conference. The text of request for public comments on the program. the bill as it passed the Senate included the Surface Mining Act amendments to: Federal Register, October 6: Extend the deadline for submission and Reopening of the comment period on the proposed approval of state programs, amendment to the permanent program dealing with the definition of a public road. Delay implementation of a federal lands regulatory program until state programs are Federal Register, October 6: implemented, Announces receipt by OSM of a proposal from Consumer Dynamics Inc., to develop a nationwide Citizens Partici- Eliminates the requirement that state pation Plan. The proposal recommends 12 target areas, regulations be identical to the Office of identifies citizens groups to participate in the program Surface Mining requirements, and includes a proposed action plan for conducting public meetings.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 . 4_59 Requires the states to adopt OSM regulations from requiring more permit information than on prime farmlands and sets August 3, 1982 that listed in the 1977 Surface Mining Act. as the cut-off date for grandfather protec- The ruling means that OSM may resume tion of operations on prime farmlands, requesting detailed information for permit applications. Requires states to adopt OSM regulations on alluvial valley floors, and Texaco, Inc., National Coal Association vs. Interior Allows cross-sectional maps or plans of affected land to be prepared by or under the In August, several portions of the Interior direction of land surveyors. Department's unsuitability regulations were overturned by U.S. District Court Judge House officials, led by Interior Committee chairman, Thomas Flannery. Judge Flannery found that Morris Udall (ID. Arizona) refused to consider the amend- the Interior Department had overstepped its ment in a conference committee called to resolve the statutory bounds iii its leasing regulations. differences between the two versions of the bill. It The Judge specifically stated that the appears unlikely that the bill will pass this year. Interior Department has a mandate to ex- Congressmen in favor of the bill's passage vow to try change Federal coal lands for private coal again next year. lands when alluvial valley floor areas are threatened. Flannery also stated that coal Litigation operators who have made substantial finan- cial and legal commitments prior to January Second Round Permanent Program Litigation: 4, 1977, are exempted from all of the Interior's unsuitability criteria. (See previous In August, U.S. District Court Judge Thomas article in this section for further details of Flannery issued a stay of his May 16 decision the suit). allowing states to seek inclusion of suspended or remanded regulations through voluntary Interior vs. Virginia Underground Coal Mining requests. (See September issue of the Companies: Cameron Synthetic Fuels Report). In his stay, Flannery said that the Department of A new suit was recently filed in Virginia in the Interior must notify the states of those the U.S. District Court in Abingdon, Virginia provisions that incorporate suspended or by 24 companies that allege that they have remanded regulations and that without been deprived of their rights to due process further action the Secretary will delete those under the 5th Amendment. The suit concerns sections from the state program. The stay the definition of the two-acre exemption and allows the Secretary, upon request of the OSM's new interpretation that the surface state, to allow inclusion of regulations that area above all underground works must be the Secretary is without the independent included as part of a mine's total acreage. authority to require. The change is therefore only a minor departure from the original AMC/NCA Durable Rock-Fill Suit: procedure. In September, the Joint Committee of the Interior vs. Virginia Surface Mining and American Mining Congress and the National Reclamation Association Suit, and Interior Coal Association filed a ,notion for summary vs. Indiana Coal Association, et.al suit: judgement in the durable rock-fill litigation started in June of this year. The motion, In October, the U.S. Supreme Court agreed to filed with Judge Thomas Flannery of the U.S. review the two lower court decisions on the District Court for the District of Columbia, constitutionality of several portions of the requests the Court to declare that the OSM's Surface Mining Act (see September issue). "final interpretive rule" is merely an Both cases are appeals from the U.S. District announcement of the agency's explanation of Courts. The Supreme Court will probably its rock-fill regulation and asks that it be hear the appeals in one consolidated hearing, remanded for revision. with a ruling following in the spring. Although the cases will be argued together, AMC/NCA Bonding Regulations Suit: they may not be consolidated in regard to the total time for each plaintiff's presentation of In October, the Joint Committee of the arguments. American Mining Congress and the National Coal Association filed suit in the U.S. Dis- U.S. Court of Appeals, Peabody Coal Suit: trict Court for the District of Columbia challenging the Office of Surface Minings In August, the U.S. Court of Appeals granted revised performance bonding regulations. a hearing before the full 11-judge panel at Although the bonding regulations were the request of the Department of Interior. In revised in August resulting from the perma- September, the full court overturned the nent program suit contested earlier, several previous 3-judge ruling which barred OSM areas of contention still remain. These include:

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

I. OSM's failure to promulgate a workable Policies, Studies and Programs self -bonding program, In September, the General Accounting Office released a 2. OSM's mandatory requirements for report on lobbying efforts by the Office of Surface bonding underground operators' subsi- Mining against amendments to reform the 1977 Surface dence control plans, and Mining Act. The report was forwarded to the Justice Department. The report was inconclusive in its review 3. OSM's requirement that if a surety be- and although the GAO reported that the agency was comes insolvent, an operator must be actively involved in trying to defeat the original amend- issued a notice of violation that will not ments, most activities did not, in their opinion, violate be vacated even if the operator gets the lobbying restrictions. The GAO was faced with substitute bond coverage. conflicting stories and poor memories during its investi- gation of OSM. Administrative Cases: The Office of Surface Mining is currently working on The Interior Board of Surface Mining Appeals drafting of amendments that will give Indian tribes the (IBSMA) ruled during the quarter on another option of running and operating their own strip mining case involving federal jurisdiction over programs on reservation land. Under the current pro- tipples and prep plants. The case was posal most of the recommendations of the report issued brought by Virginia Iron, Coal & Coke Com- last summer by the Council of Energy Resource Tribes pany (vICC) and involved a tipple located in will be incorporated. These include: Wise County used for crushing and removing slate from coal mined on VICC property. • Mines on tribal lands would meet the same VICC has leased the mineral rights to the performance and bonding standards as opera- property to independent firms that have tion on state lands, taken out their own mining permits but who sell some of the coal back to VICC. The • Tribes would get 100 percent funding for IBSMA ruled that OSM has failed to prove the developing, implementing and enforcing their tipple was operated "in connection with" the programs, while state governments get 100 mines. In the same case, IBSMA held that a percent the first year, 75 percent the second VICC prep plant in the same county did fall year and 50 percent each year thereafter, under OSM jurisdiction. This plant was located about one mile from the mine. • Technical assistance would be authorized for the tribes plus a $10 million, 10-year scholar- In a case involving Hayden & Hayden Coal ship program for Indian students in energy Company, the IBSMA issued a decision favor- careers, ing the Office of Surface Mining in regard to multiple reasons for closing a coal mine. The S Tribes would have the same authority to hear Hayden mine, located in Breathitt County, appeals of enforcement actions as state Kentucky was closed by an inspector for governments and for the first time, they failure to abate a previously cited violation could take criminal and civil action against and for being an imminent threat to the non-Indian violators, environment but when the inspector admitted that the violation wasn't an imminent threat, • Still unresolved is the question of OSM com- an administrative law judge vacated the pensation to a tribe that cannot (nine its coal cessation order. The IBSMA overruled the because of an alluvial valley floor designa- law judge in September. tion.

In a case involving the definition of an inter- In September, OSM announced the release of mittent stream, Sunbeam Mining won a a Handbook on Rights of Coal Mine Operators reversal of a previous ruling in which Sun- under the Interim Regulations. The handbook beam was cited for diverting what OSM had describes operators' rights under the interim defined as an intermittent stream without program if they are cited for violations. In permission from the regulatory authority. addition, appeal procedures available to a Sunbeam argued that no stream had existed mine operator if penalties are ordered are prior to mining at the Pennsylvania mine and outlined. The handbook, entitled, "Rights of that water diverted from the mining area had Operators and Permittees" is available at the increased flow in what was a ephemeral nearest OSM office at no charge. stream. Therefore the Board ruled that an intermittent stream created as a result of The first report in a series of assessments of reclamation activities by a strip mine existing water resources in selected areas of operator is not necessarily covered by the present and proposed coal mine development Surface Mining Act and does not require has been published by the U.S. Geological permission of the regulatory authority. Survey. The reports are designed to aid in the preparation of permit applications by providing hydrologic information as required by the Surface Mining Act. Nineteen reports

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-61 will be published within the next year. The first report, available for public purchase, describes water conditions and problems in an area of central Alabama. The report is available from the U.S. Geological Survey, 1317 McFarland Blvd., East, Tuscaloosa, Alabama 35405. A new study by the U.S. Geological Survey, released in October, is a detailed geologic study of the Sheridan, Wyoming area subsi- dence problems caused by old coal mines. The report finds that under some conditions strip mining of coal, followed by proper reclamation, can cause less environmental damage over long periods of time than under- ground mining. Although strip mining is a major disturbance at the time of mining, it is temporary in nature, while underground mining may cause subsidence which may not occur until years, decades or even centuries after mining. State Programs Several state programs have been approved fully or in part by the Office of Surface Mining. The current status of the state programs is contained in Table I.

I/fill

4-62 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 TABLE I STATUS OF STATE PROGRAMS

1979 Production State 1/80 3/80 Fall 80 (1,000 tons)* Region I

Maryland x A 2,453 Pennsylvania X PA 97,300 Virginia X PA 35,000 West Virginia X PA 111,600 Region 11

Alabama X NA 24,300 Georgia Federal Program 485 Kentucky X Not Announced 142,450 Tennessee X PA 11, 700 Mississippi X PA X A Region III

Illinois X PA 58,500 Indiana x PA 27,850 Ohio X PA 42,900 Region IV

Arkansas X A 500 Iowa x PA 600 Kansas X A 800 Louisiana x A Missouri X A 5,820 Oklahoma X PA 5,500 Texas X A State Program in Effect 22,600 Region V

Alaska Awaiting Outcome of NAS Study 700 Arizona Mining Operations Only On Indian Coal 11,800 Colorado X A 18,000 Montana X A State Program in Effect 32,870 New Mexico X A 12,900 North Dakota X A 14,600 Oregon Federal Program - Exploration Utah X PA 12,240 Washington Federal Program 5,000 Wyoming X PA X A 75,000

*production from 1980 Keystone Director A = Approved PA = Partial Approval NA = Not Approved X Date of Submittal

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-63 WATER

WATER ASSESSMENT REPORT FOR SRC-11 scheduled for completion by 1987, although the project is PUBLISHED BY WATER RESOURCES COUNCIL presently under litigation. On July II, 1974, the Upper West Fork River Watershed Association filed suit in the The Water Resources Council (WRC) published the water U.S. District Court for the Northern District of West assessment report in August 1980, for the Solvent Re- Virginia seeking an injunction against further prosecution fined Coal (SRC-11) Liquefaction Demonstration Plant to of the project base, primarily on alleged inadequacy of be built near Morgantown, WVA. the project EIS. On May 3, 1976, the Federal District Court dismissed the action by the Upper West Fork River Under a Memorandum of Agreement with WRC, the Ohio Watershed Association. The Plaintiff appealed before River Basin Commission (ORBC) performed the technical the U.S. Court of Appeals (Fourth Circuit) on January phases of the assessment and prepared the technical 13, 1977. The U.S. Court of Appeals (Fourth Circuit) report. The technical report was completed and affirmed the decision of the District Court on May 9, approved in June, and is the basis of the WRC Report. 1977. The Upper West Fork River Watershed Association ORBC formed a study committee including representa- and other environmental interest groups filed suit on tion from the states of West Virginia and Pennsylvania, April 21, 1980, in the U.S. District Court of the District U.S. Army Corps of Engineers, U.S. Environmental Pro- of Columbia, alleging that the Corps used the wrong tection Agency, and the U.S. Department of Energy. interest rate for the project, and wrongfully included The ORBC Citizens' Advisory Council and the Pittsburg water quality benefits. The 75,000 acre-foot storage and Midway Coal Mining Company also participated. reservoir is to be located in northern West Virginia on the West Fork River, upstream of the proposed SRC-II Assessment data were provided as follows: the descrip- site. The reservoir project is authorized for flood tion for the proposed plant was provided by DOE, hydro- control, water supply, water quality maintenance, and logy and navigation data were provided by the Army, and recreation. Up to 80 cis will be released during low-flow water use and water quality information was assessed by periods for water quality augmentation. the ORBC staff, with input from the States, EPA, and The Ohio River Valley Water Sanitation Commission Figure 2 illustrates the site plan of the proposed project. (ORSANCO). Data were obtained from existing informa- The project site is bounded on the southeast by the Fort tion, adjusted to a common base and format. The Martin Power Plant (Monongahela Power Company), on Assessment will be used by the DOE as input to the the north by the West Virginia-Pennsylvania State line, Environmental Impact Statement for the proposed syn- and on the west and south by land in private or corporate fuel plant. Please refer to page 4-36, of the September ownership. Except for a narrow floodplain along the 1980 Cameron Synthetic Fuels Report for a review of river, the site is hilly and is at an elevation of about the Draft SRC-lI EIS. I LOS feet mean sea level or 311 feet above the river.

The proposed SRC-II Synfuel Site is located in West The water consumption figures in the WRC assessment Virginia along the Monongahela River approximately of the proposed SRC-11 (solvent-refined coal) demonstra- two-miles south of the West Virginia - Pennsylvania tion project are approximately 50 percent greater than state line. Figure I shows the Monongahela River Basin those in the draft Environmental Impact Statement (EIS) where the proposed project is to be located. Potential prepared by the Department of Energy. The lower EIS impacts are assessed along the Monongahela River down- figures resulted from design modifications that had not stream to Lock and Dam 2, near Pittsburgh, Penn- yet been defined when the assessment data analysis was sylvania. The assessment considered the source of water conducted. In addition, the SRC assessment is based on supply for the plant to be the Monongahela River, as a "worst case" condition for water availability for the augmented by releases from Tygart Lake (with and SRC-II project. without Stonewall Jackson Lake Project). Groundwater was also considered. Coal for the synfuel plant is According to WRC, "Under most flow conditions, the expected to come from Moundsville, West Virginia. For Monongahela River has enough water to support the the purpose of this assessment it was assumed that the combined effect of the SRC-II demonstration project and coal would be barged up the Ohio and Monongahela the increased consumption by other sectors of the Rivers to the proposed site. economy through 1990 without reduction of streamflow below that projected to meet navigation requirements The U.S. Army Corps of Engineers (Corps) maintains and (including SRC-II barge traffic) and to meet water operates a series of locks and dams along the Ohio and quality standards in West Virginia and Pennsylvania." Monongahela Rivers. Presently, seven locks and dams in Pennsylvania (including Emsworth on the Ohio River) and Exceptions were cited during various low-flow condi- three in West Virginia provide a minimum 9-foot depth tions. "For example, during minimum navigation flow for navigation along the Monongahela River from Pitts- (i.e., recurrent drought of record with low-flow augmen- burgh, Pennsylvania, upstream to Fairmount, West Vir- tation), the total increased consumption will reduce ginia. The proposed project site is located in the streamflow 12 percent below 1990 navigation needs at navigation pool of Lock and Dam 8. Maxwell lock and dam. Half of this deficit would be due to the SRC-II demonstration project. Stonewall Jackson Reservoir under construction (i.e., primarily land acquisition) by the Corps, is presently

4-64 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

e Pittsburgh -

Of 3

WVAiPA

I Mixwe4IUD • t' J •..Jfr%V.4St - • MoundsviIIo ,. t.t . . - • . •" Yougliloghen ). Ft.Mertln 7 ' "j k -

jPropoaed Lotetynn - • . MD SRCa It Project organtown Site Morgant&vn LID t . ( Deep Creek Lake

/ Nb

- 2 _... Monongahela Basin ci- Stonewall. Jackso,fLak&. (under construction). LEGEND: B I— :LocFjDarn No .8 - SlaleLine • - / ID a '0 20y. OH PA. 'rrD. A (CA v.

FIGURE 1 MAP OF MONONGAHELA RIVER BASIN AND SRC-II PLANT LOCATION

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-65 Meterological Tower (existing)

Greene County PA, I Monongalla Count; W.VA.

I I I I) Power Company I Ic Fort Marlin I Power Station I ::' (exist! ng) I Railway Company. MainLine (existing) Kill Barge Unloading I

it C It Ot C 0 C —Power Lines 0 (existing)

-way 53 Product Storage

LEGEND:

- - - Proposed Project Site • PA. 0 I 1

ssr I ' I A I Proposed Project Area A ( W,VA. /' / VA.

FIGURE 2 SITE PLAN OF PROPOSED SRC-II PROJECT

4-66 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 "In addition, the Monongahela River at Lock and Dam 4 ject (and ultimately the commercial project) to allow for in Pennsylvania does not currently have the estimated reduced water consumption and/or alternate water streamflow necessary to achieve the total dissolved sources during critical low flows in the Monongahela solids standard during 7-day, 10-year low-flow condi- River. Offstream storage and conjunctive use of ground- tions. The SRC-11 demonstration project would contri- water are two options to consider." bute only about one percent to the projected streamflow deficit by 1990. "Unless substantive action is taken during critical flow periods," says WRC, "projected river flow under present "The projected increase in new offstream consumptive basin conditions will not be sufficient to meet the West uses in the basin will be approximately 18 cubic feet per Virginia dissolved oxygen standard in 2020 at Lock and second (cfs) by 1990. The SRC-I1 demonstration project Dam 8, the Pennsylvania total dissolved solids standard will account for half of this increase. The 8.7 cfs, for 1990 and 2020 at Lock and Dam 4, and the projected however, is only 7 percent of the total 133 cfs consump- navigation flow required at Maxwell Lock and Dam in tion (existing and new uses including SRC-II) projected 1990 and 2020. for 1990. "To resolve the basin's present and future water "The 8.7 scf represents 2.4 percent of the 7-day, 10-year problems, West Virginia and Pennsylvania need to low flow (360 cfs) at Lock and Dam 8 and 1.3 percent of develop a coordinated water management program for the present 7-day, 10-year low flow (650 cfs) down- the Monongahela River Basin. Under a basin-wide plan, stream at Lock and Dam 4. the impacts of competing water uses during the critical low-flow conditions could be reduced (or offset) by "The economic capacity of Lock and Dam 7 (Pennsyl- various water management options. The options include: vania) is projected to be exceeded by 1988 if coal for the Low-flow augmentation from Stonewall Jackson Reser- SRC-II demonstration project is transported by barge. voir; water conservation; temporary curtailment of off- Economic capacity is determined by factors such as stream uses; additional storage and/or of fstream uses; congestion at the lock, competing traffic modes, etc., additional storage and/or reallocation of storage at basin rather than the availability of water. reservoirs, including Stonewall Jackson, Tygart, and Stonecoal; additional water storage sites; and develop- "Groundwater at the site is insufficient to meet project ment of supplemental groundwater resources. water requirements. Further investigation should deter- mine whether groundwater can be used as a supplemental "The water management program should balance all source of water during low-flow conditions." competing uses against available water supplies. Parti- cular attention should be given to providing critical A Followup Water Assessment Will Be Performed for A flows at key points along the river. A predictable water Commercial Plant - budget would help provide for beneficial economic, social and environmental conditions throughout the During low flows, the SRC-II commercial project, to- basin. gether with other increased consumptive uses projected for the basin by 2020, will worsen the streamflow "In addition to developing water budget, West Virginia, deficits at Maxwell lock and dam, without further aug- Pennsylvania, the Ohio River Sanitation Commission, and mentation. Moreover, the Monongahela River at Lock the U.S. Environmental Protection Agency (EPA) should and Dam 8 near the plantsite will not have sufficient establish a water quality program that would provide for flow to meet the dissolved oxygen standard in West additional water quality monitoring and analysis (parti- Virginia for the 7-day, 10-year low flow. The project cularly total dissolved solids) along the Monongahela would contribute less than two percent to the estimated River. The monitoring and analysis should provide the deficit in the flow required to meet Pennsylvania's total information needed to identify and characterize water dissolved solids standard at Lock and Dam 4 under the 7- quality problems in specific stream reaches. This effort day, ID-year low-flow conditions in 2020. can also lead to further coordination of water quality policies between West Virginia and Pennsylvania. The projected new consumptive uses in the basin will need 52 cfs by 2020. The SRC-II commercial project will "The instream needs of fish and wildlife must be included account for 23 cfs or 44 percent of the increase. This 23 in a water management program. Under a Section 13(c) cfs, however, is only 10 percent of the total 167 cfs assessment, a streamflow management study should be consumption (existing and new uses including SRC-11) conducted to assess the SRC-II commercial project and projected for 2020. This 23 cfs is about six percent of other consumptive uses of their combined effects on fish the 7-day, 10-year low flow at Lock and Dam 8 and and wildlife habitat in the Monongahela River." about four percent of the 7-day, 10-year low flow downstream at Lock and Dam 4. fl/Il/fl A followup water assessment will more accurately assess RESOURCES FOR THE FUTURE, INC. REPORTS the water availability and related water impacts of the ON WATER RIGHTS AND ENERGY DEVELOPMENT proposed SRC-II commercial projects. IN THE YELLOWSTONE RIVER BASIN

WRC Report Outlines the Need For Further Action The Yellowstone River Basin encompasses the southwest quarter of the Fort Union Coal Region, and represents a The WRC report suggested that, "A plan of operation major source of water for use in future coal develop- should be developed for the SRC-I1 demonstration pro- ments. In this area, water is not present in abundance, and conflicts will arise over uses of it.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-67 Resources for the Future, Inc. (Rn') has published "Water Rights and Energy Development in the Yellow- stone River Basin: An Integrated Analysis". C. M. Bans and J. V. Krutilla, the authors, are senior fellows in the Quality of the Environment Division of RFF, and repre- sent the disciplines of engineering and economics. They present an analysis of the legal, institutional, and hydro- logic aspects of the region and describe a method for evaluating the likelihood of meeting the conflicting claimants' demands for water. The authors conclude that Montana water law tends strongly to favor allocation of natural (unregulated) flows to support an agrarian oriented society. This means that transfer of water rights in sizable quantity among owners is prohibited if it results in a change from agricultural to industrial uses. However, increased dependable yields from storage regulation provided by federally built projects can be transferred to the state for a consideration equal to the costs to the Federal government, and, in turn, subject to allocation by auction. If an unfettered market develops for new supplies (that is, increases in dependable yield), then they see a two-tiered allocative mechanism with industry legally able to compete for water on the same terms as agriculture; namely, for a price up to the value of the marginal production of water in the more produc- tive application. This would provide a source of supply to the industrial sector, provided that new projects are built, although such construction is not a forgone conclu- sion. The authors review of the legal issues arising out of the federal reserved rights doctrine, however, suggests a challenge to the primacy of the western states in their traditional right to allocate water within their boundaries. This problem has two aspects. In several recent cases, the Federal government has asserted, under the Federal Reservation Doctrine, a right to the waters necessary to carry out the purposes for which the various federal land withdrawals such as national forests, national wild and scenic rivers, national parks, and the like were set aside. (In some areas there have been federal withdrawals for coal extraction purposes, but this does not appear to have been a problem of any real importance in Montana.) What appears to be of much greater significance are the Indian reserve water rights that have their legal basis in the same doctrine and refer to Indian rights of access to water for economic activi- ties on their reservations. Because these rights have existed since the establishment of the reservations, they are senior to the rights of most individuals in the non- Indian community.

4-68 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF COAL PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

Acurex Aerotherm Corporation Acurex Aerotherm Low-BTU Gasifier for Commercial Use ...... 4-76 AGIP Exxon Donor Solvent Process Development 4-81 Airco, Inc. Medium BTU Synthesis Gas Study 4-89 Air Products and Chemicals, Inc. Solvent Refined Coal Pilot Plant (SRC-1) 4-93 Alberta Research Council Underground Coal Gasification, Canada 4-98 Allis-Chalmers Kilngas Project ...... 4-87 American Natural Resources Great Plains Gasification Project ...... 4-85 ANG Coal Gasification Company Great Plains Gasification Project ...... 4-85 Appalachian Regional Commission Pike County Low-BTU Gasifier for Commercial Use 4-91 ARCO Underground Coal Gasification - Rocky Hill Project 4-100 Underground Coal Gasification - University of Texas 4-98 Ashland Synthetic Fuels, Inc. H-Coal Project 4-86 Atlantic Richfield Exxon Donor Solvent Project 4-81 Baltimore Gas and Electric Kilngas Project ...... 4-87 Basic Resources, Inc. Underground Coal Gasification -University of Texas 4-98 Underground Gasification of Texas Lignite- Tennessee Colony Project ...... 4-101 Basin Electric Great Plains Gasification Project ...... 4-85 Circle West Project ...... 4-78 Bechtel Inc. Cool Water Coal Gasification Project ..... 4-79 Medium BTU Synthesis Gas Study ...... 4-89 Bell Aerospace Textron Bell High Mass Flux Gasifier 4-76 Bethlehem Steel Co. Low/Medium BTU Gas for Multi-Company Steel Complex 4-88 Billings Energy Corporation Forest City Coal Gasification Project. 4-83 Bituminous Coal Research, Inc Tr-Gas Project ...... 4-95 British Department of Energy Composite Gasifier Project ...... 4-79 National Coal Board Liquid Solvent Extraction Project ...... 4-90 National Coal Board Supercritical Solvent Extraction Project ...... 4-91 British Gas Corporation Composite Gasifier Project ...... 4-79 Brookhaven National Laboratory Flash Hydropyrolysis Project 4-83 Burlington Northern Circle West Project ...... 4-78 C. F. Braun Southern California Synthetic Fuels Energy System 4-94 Caterpillar Tractor Company Caterpillar Tractor Low Btu Gas From Coal Project ...... 4-76 Central Illinois Light Co., Inc ICGG Pipeline Gas Demonstration Plant Project. 4-87 Kilngas Project ...... 4-87 Central Illinois Public Service ICGG Pipeline Gas Demonstration Plant Project. 4-87 Central Maine Power Central Maine Power Co.'s Sears Island Project 4-76 Central Power and Light Chemically Active Fluid Bed Project ..... 4-77

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-69 Company or Organization Project Name

Cities Service CS/R Process Development ...... 4-80 LC Fining Processing of SRC Extract ...... 4-88 Medium BTU Synthesis Gas Study ...... 4-89 Two Stage Liquefaction ...... 4-96 Cleveland Electric illuminating Co. Lewis Research Center Gasifier - Alternative Power Plant ...... 4-88 COGAS Development Company COGAS Process Development ...... 4-78 ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 Columbia Gas System Inc. Columbia Coal Gasification SNG Project ...... 4-78 Columbia Gas Transmission Corp. Great Plains Gasification Project ...... 4-85 Combustion Engineering Two-Stage Entrained Gasification System ...... 4-96 CONOCO Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Emery Coal Conversion Project ...... 4-SI H-Coal Project ...... 4-86 Medium BTU Synthesis Gas Study ...... 4-89 Underground Coal Gasification - University of Texas . . . 4-98 Zinc Halide Hydrocracking Process Development ..... 4-97 Consolidated Gas Supply Corp. COGAS Process Development ...... 4-78 Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Consolidation Coal Company Underground Coal Gasification, Pricetown Project ..... 4-99 Consumer Energy Corporation Combined Cycle-Coal Gasification Energy Centers ..... 4-78 Consumers Power Company Kilngas Project ...... 4-87 Curtiss-Wright Corporation Gas Turbine Systems Development ...... 4-83 Department of Energy Acurex - Aerotherm Low-BTU Gasifier for Commercial Use ...... 4-76 Bell Nigh Mass Flux Gasifier ...... 4-76 BI-GAS Project ...... 4-76 Cities Service/Rockwell Process Development ...... 4-78 Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Exxon Catalytic Gasification Process Development ..... 4-81 Exxon Donor Solvent Process Development ...... 4-SI Fast Fluid Bed Gasification ...... 4-82 Firing of Iron Ore Pelletizing Furnace with Low-BTU Producer Gas ...... 4-82 Flash Hydropyrolysis Project ...... 4-83 Gas Turbine Systems Development ...... 4-83 Grace Ammonia From Coal Plant ...... 4-84 Grace Coal-to-Methanol-to-Gasoline Plant ...... 4-84 Grand Forks Liquefaction Process for Low Ranked Coals . . 4-85 H-Coal Project ...... 4-86 HYGAS Demonstration Plant ...... 4-86 ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 LC Fining Processing of SRC Extract ...... 4-88 Low-Medium BTU Gas For Multi-Client Steel Complex ...... 4-88 Lummus Coal Liquefaction Development ...... 4-89 Memphis Industrial Fuel Gas Demonstration Plant ..... 4-89 Minnegasco Peat Biogasification Project ...... 4-90 Minnegasco Peat Gasification Project ...... 4-90 Molten Salt Process Development ...... 4-90 Pike County Low-Btu Gasifier for Commercial Use ..... 4-91 Riser Cracking of Coal ...... 4-92 Slagging Gasifier Development ...... 4-92 Solvent Refined Coal SRC-1 ...... 4-93 Solvent Refined Coal - SRC-II ...... 4-93 Tr-Gas Project ...... 4-95 Two-Stage Entrained Gasification System...... 4-96 Two-Stage Liquefaction ...... 4-96

4-70 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Company or Organization Project Name

Underground Coal Gasification Manna Project ...... 4_99 Hoe Creek Project ...... 4_99 Pricetown Project ...... 4-99 Steeply Dipping Bed Project ...... 4-100 University of Texas ...... 4..98 University of Minnesota Low-BTU Gasifier for Commercial Use ...... 4-98 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-97 Dow Chemical Dow Coal Liquefaction Process ...... 4-go Dreyer Brothers Circle West Project ...... 4-78 du pont Underground Coal Gasification - University of Texas . . . 498 Dynatech R/D Company Minnegasco Peat Biogasification Project ...... 4-90 Electric Power Research Institute Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Cool Water Coal Gasification Project ...... 4-79 Exxon Donor Solvent Process Development ...... 4-SI H-Coal Project ...... 4-86 Two Stage Entrained Gasification System ...... 4-96 El Paso Natural Gas Company Burnham Coal Gasification Project ...... 4-77 Enrecon, Inc. Enrecon Coal Gasifier ...... 4-81 Environmental Protection Agency Chemically Active Fluid Bed Project ...... 4-77 Underground Coal Gasification - University of Texas . . . 4-98 Extractive Fuels Inc. Underground Coal Gasification ...... 4-98 Exxon, USA Catalytic Gasification Process Development ...... 4-81 Donor Solvent Process Development ...... 4-81 Exxon Texas Project ...... 4-82 Exxon Wyoming Project - Coal Gasification ...... 4-82 Underground Coal Gasification - University of Texas . . . 4-98 FMC Corporation COGAS Process Development ...... 4-78 Ford, Bacon & Davis Mountain Fuel Supply Company Coal Gasification Project . . 4-90 Forest City, Iowa Forest City Coal Gasification Project ...... 4-83 Foster Wheeler Energy Corporation Chemically Active Fluid Bed Project ...... 4-77 Gas Research Institute Bell High Mass Flux Gasifier ...... 4-76 Exxon Catalytic Gasification Process Development ..... 4-81 HYGAS Pilot Plant Project ...... 4-86 Minnegasco Peat Gasification Project ...... 4-90 General Electric Company Central Maine Power Co.'s Sears Island Project ...... 4-77 Gas Turbine System Development ...... 4-83 GEGAS-D Project ...... 4-84 Integrated Industrial Synfuel Combined Cycle Cogeneration Plant ...... 4-87 Gilbert/Commonwealth Associates, Inc. Kilngas Project ...... 4-87 Glen-Gery Corporation Acurex Aerotherm Low-BTU Gasifiers for Commercial Use ...... 4-76 W.R. Grace and Company Grace Ammonia From Coal Plant ...... 4-84 Grace Coal-to-Methanol-to-Gasoline Plant ...... 4-84 Grace Synthetic Fuel Liquefaction Plant ...... 4-84 Grand Forks Energy Technology Center Grand Forks Liquefaction Process for Low Ranked Coals . . 4-85 Slagging Gasifier Development ...... 4-92

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-71 Company or Organization Project Name Great Plains Gasification Associates Great Plains Gasification Project ...... 4-85 Gulf Mineral Resources Company Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Gulf Oil Corporation Solvent Refined Coal Pilot Plant SRC-11 ...... 4-93 Gulf Research & Development Corp. Underground Coal Gasification - Steeply Dipping Beds . . . 4-I00 4-98 HEW Underground Coal Gasification - University of Texas . . . Houston Natural Gas Corp. Medium BTU Gasification Project ...... 4-89 Howmet Aluminum Corporation Howmet Aluminum Project ...... 4-86 Hydrocarbon Research, Inc. Fast Fluid Bed Gasification Project ...... 4-82 H-Coal Project ...... 4-86 Illinois Coal Gasification Group ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 Illinois Power Company Kilngas Project ...... 4-87 Illinois, State of Kilngas Project ...... 4-87 Inland Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex ...... 4-88 Institute of Gas Technology HYGAS Demonstration Plant Project ...... 4-86 Riser Cracking of Coal ...... 4-92 International Coal Refining Co. Solvent Refined Coal Demonstration Plant (SRC-1) ..... 4-93 Iowa Power Company Kilngas Project ...... 4-87 Iowa, State of Forest City Coal Gasification Project ...... 4-83 Japan-SRC, Inc. Solvent Refined Coal Demonstration Plant (SRC-11) ..... 4-93 Japan Coal Liquefaction Development Company Exxon Donor Solvent Process Development ...... 4-81 Jones and Laughlin Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex ...... 4-88 JVCO Solvent Refined Coal Demonstration Plant (SRC-11) ..... 4-93 Kentucky, Commonwealth of H-Coal Project ...... 4-86 Ken-Tex Project ...... 4-87 Pike County Low Btu Gasifier for Commercial Use ...... 4-91 Solvent Refined Coal Pilot Plant - SRC-1 ...... 4-93 Krupp-Koppers GmbH S. K. Gasification Process ...... 4-92 Laramie Energy Technology Center Underground Coal Gasification - Hanna Project ...... 4-99 Lawrence Livermore Laboratory Underground Coal Gasification - Hoe Creek Project 4-99 Lone Star Gas Underground Coal Gasification - University of Texas 4-98 Lummus Company Lummus Coal Liquefaction Development ...... 4-89 Two Stage Liquefaction ...... 4-96 Memphis Light, Gas and Water Memphis Industrial Fuel Gas Demonstration Project 4-89 Michigan Wisconsin Pipe Line Co. Great Plains Gasification Project ...... 4-85 Minnesota Gas Company Minnegasco Peat Biogasification Project ...... 4-90 Minnegasco Peat Gasification Project ...... 4-90 Mississippi Power and Light Company De Soto County, Mississippi Coal Project ...... 4-80 Mississippi, State of Dc Soto County, Mississippi Coal Project ...... 4-80 Mobil Oil H-Coal Project ...... 4-86 Underground Coal Gasification - University of Texas 4-98 Mono Power Company Emery Coal Conversion Project ...... 4-81 Monongahela Power Company Kilngas Project ...... 4-87 Morgantown Energy Technology Center Underground Coal Gasification - Pricetown Project ..... 4-99

4-72 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Company or Organization Project Name

Mountain Fuel Supply Company Emery Coal Conversion Project ...... 4-81 Mountain Fuel Supply Company Coal Gasification Process . . 4-90 NASA Lewis Research Center Lewis Research Center Gasifier Alternative Power Plant ...... 488 National Coal Board Liquid Solvent Extraction Project ...... 4-90 Low-BTU Gasification Project ...... 4-91 Supercritical Gas Extraction Project ...... 4-91 National Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex ...... 4-88 Natural Gas Pipeline Co. of America Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 Nokota Company Dunn Nokota Methanol Project ...... 4-80 North Shore Gas Company ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 Northern Illinois Gas Company ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 Northern Indiana Public Service Co. Low/Medium BTU Gas For Multi-Company Steel Complex ...... 4-88 Ohio Edison Company Kilngas Project ...... 4-87 Pacific Gas and Electric Co. Emery Coal Conversion Project ...... 4-81 San Ardo Cogeneration Project ...... 4-92 Pacific Lighting Corporation Southern California Synthetic Fuels Energy System ..... 4-94 Panhandle Eastern Pipe Line Co. COGAS Process Development ...... 4-78 Conoco Pipeline Gas Demonstration Plant Project ..... 4-79 WYCOAL Gas Inc., Coal Conversion Project ...... 4-97 Peabody Coal Company WYCOAL Gas Inc., Coal Conversion Project ...... 4-97 Peoples Energy Company Great Plains Coal Gasification Project ...... 4-85 Peoples Gas, Light & Coke Co. ICGG Pipeline Gas Demonstration Plant Project ...... 4-87 Phillips Petroleum Corporation Exxon Donor Solvent Process Development ...... 4-81 Pittsburg and Midway Coal Mining Company Solvent Refining Coal Pilot Plant (SRC-l!) ...... 4-93 Potomac Edison Company Kilngas Project ...... 4-87 PPG Industries Medium BTU Synthesis Gas Study ...... 4-89 Public Service of Indiana Kilngas Project ...... 4-87 Public Service of New Mexico Underground Coal Gasification - New Mexico ...... 4-98 Public Service of Oklahoma Chemically Active Fluid Bed Project ...... 4-77 Kilngas Project ...... 4-87 Ralph M. Parsons Co. De Soto, County Mississippi Coal Project ...... 4-80 Resource Sciences Corporation Circle West Project ...... 4-78 Rockwell International CS/R Process Development ...... 4-80 Cities Service/Rockwell Process Development ...... 4-78 Molten Salt Process Development ...... 4-90 Rocky Mountain Energy Company Underground Coal Gasification - Hanna Project ...... 4-99 Ruhrkohle AG Exxon Donor Solvent Process Development ...... 4-81 H-Coal Project ...... 4-86 Solvent Refined Coal Demonstration Plant (SRC-II) ..... 4-93

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-73 Company or Organization Project Name Page Sandia Laboratories Underground Coal Gasification- Washington State 4-100 Sasol Limited Sasol Two (Proprietory) Limited 4-92 Shell International Petroleum Co. S.K. Gasification Process 4-92 Shell Oil Company Zinc Halide Hydrocracking Process Development 4-97 Southern California Edison Cool Water Coal Gasification Process. 4-79 Southern California Synthetic Fuels Energy System 4-94 Southwestern Electric Power Chemically Active Fluid Bed Project 4-76 Standard Oil of Indiana H-Coal Project 4-86 Standard Oil Company of Ohio Beacon Process ...... 4-76 Stearns-Roger Incorporated BI-Gas Project 4-76 Slagging Gasifier Development ...... 4-92 Stone & Webster Engineering Group Central Maine Power Co.'s Sears Island Project 4-77 Sun Gas Company Conoco Pipeline Gas Demonstration Project 4-79 Tenneco, Inc. SNG from Coal 4-94 Tennessee Eastman Co. Chemicals From Coat 4-77 Tennessee Gas Pipeline Company COGAS Process Development ...... 4-78 Conoco Pipeline Gas Demonstration Project 4-79 Great Plains Coal Gasification Project 4-85 Texaco, Inc. Central Maine Power Co.'s Sears island Project 4-77 Cool Water Coal Gasification Project 4-79 Integrated Industrial Synfuel Combined Cycle Cogenerating Plant ...... 4-87 Lake DeSmet SNG From Coal Project. 4-88 Medium BTU Gasification Project ..... 4-89 San Ardo Coal Generation Project ..... 4-92 Southern California Synthetic Fuels Energy System 4-94 Texaco Coal Gasification Process Development 4-94 Texas A&M University Underground Coal Gasification of Texas Lignite 4-101 Texas Eastern Corporation Conoco Pipeline Gas Demonstration Plant Project 4-79 New Mexico Lurgi Coal to Gas/Methanol Plant 4-91 Tri-State Project 4-95 Texas Gas Transmission Corp. Ken-Tex Project ...... 4-87 Tri-State Project 4-95 Texas Mining and Mineral Resources Research Institute Underground Coal Gasification - University of Texas 4-98 TOSCO Corporation TOSCOAL Process Development 4-95 Transcontinental Gas Pipe Line Co. Conoco Pipeline Gas Demonstration Plant Project 4-79 Great Plains Coal Gasification Project 4-85 Transwestern Pipeline Company Lake DeSmet SNG From Coal Project ..... 4-88 TRW, Inc. Beacon Process ...... 4-76 TRW Coal Gasification Project 4-95 TVA TVA Ammonia-From-Coal Project ...... 4-95 TVA Medium BTU Coal Gasification Plant 4-96 Union Carbide Corp. Low/Medium BTU Gas For Multi-Company Steel Complex 4-88 Union Electric Company lcilngas Project ...... 4-87 United Energy Resources Inc. Medium BTU Synthesis Gas Study ...... 4-89 University of Minnesota University of Minnesota Low-BTU Gasifier for Commercial Use ...... 4-97 University of New Mexico Underground Coal Gasification - New Mexico 4-98

4-74 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 Company or Organization Project Name Page

University of North Dakota Grand Forks Liquefaction Process for Low-flanked Coals 4-85 University of Texas Underground Coal Gasification ...... 4-98 USBM - Twin Cities Metallurgical Firing of Iron Ore Pelletizing Furnace with Low-BTU Research Center Producer Gas ...... 4-82 Utah International New Mexico Lurgi Coal to Gas/Methanol Plant 4-91 West Penn Power Company Kilngas Project ...... 4-87 West Texas Utilities Company Chemically Active Fluid Bed Project ...... 4-77 Westinghouse Electric Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-97 Whee labra to r - Frye Solvent Refined Coal Pilot Plant - SRC-I ..... 4-93

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-75 STATUS OF SYNFIJELS PROJECTS (Underlining Denotes Changes Since September 1980) SYNTHETIC FUELS FROM COAL COAL CONVERSION PROJECTS ACUREX-AEROTI-IERM LOW-BTU GASIFIER FOR COMMERCIAL USE --DOE, Acurex-Aerotherm Corp., Glen-Gery Corp. DOE awarded a three-year cost-sharing contract to Acurex-Aerotherm Corp. in November 1976, for design, construction and operation of a 24 TPD Wellman-Galusha gasifier located at York, PA. The low-Btu gas is used to fire a brick kiln at the Glen-Gery Co. plant. Architectural and engineering firm is the Acurex-Aerotherm Corp., Mountain View, California. Gasifier was placed in operation in October 1977. Hot raw gas from anthracite gasification is used directly in kilns. Detailed operating data based on the years operation showed costs of low-Btu gas from new gasifier is below $2.50/MM SW including cost of capital.

Project Cost: $1.6 million (50/50 DOE/participant funding) 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 Stu gas from air blown coal gasifiers or underground coal gasification to SNG and electricity. DOE is funding a modeling study of fixed and fluid-bed reactors for the process. Development is currently at the bench-scale stage and will be ready for PDU scale-up in the near future. A cooperative agreement was recently signed with the DOE which Drovides for DOE cost sharing during a thirty month development period.

Project Cost: Not available BELL HIGH MASS FLUX GASIFIER - Bell Aerospace Textron, Gas Research Institute, and DOE Bell Aerospace was awarded an ERDA contract in January 1976 to investigate the feasibility of gasifying coal in an entrained flow gasifier having the superficial residence time on the order of lOU milliseconds. A 0.5 ton-per-hour air blown reactor is being used for process evaluation. Reactor nominally operates at 15 atm, 2,400°F, and mass throughputs of 10,000 pounds-per-hour cubic foot of reactor volume. Process includes option for secondary coal injection and methane enrichment. Sixty-six gasifier tests have been conducted with three types of coal feed. Initial oxygen-blown operation was demonstrated on company funds. As part of the current DOE/GRI program, the PDU has been upgraded to incorporate a pressurized product gas handling system and improved product material collection and measurement capability. Current contract with DOE/GRL began September 1979. Design, fabrication and erection of PDU is complete. Checkout gasification tests were initiated during July 1980.

Project Cost: I.) million Phase I 81-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 8CR the prime contractor. Both functions, in addition to operation, were assigned to Stearns-Roger in November of 1979. Research on a fluid bed methanation process is being continued at BCR's Monroeville, Pennsylvania laboratory in a separate contract with DOE; however, such a unit is integrated into the pilot plant facilities for testing. 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 SNG. Efforts are currently directed to solving operating problems using Rosebud subbituminous as test coal and to improving operability of equipment systems. 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 plant has had continuous runs of 120 and 100 hours on Rosebud coal with allsystems operating satisfactorily and reliably. Major thrust of the program in FY 1931 will be to achieve further safe, stable, controlled, continuous operation and to test a candidate Eastern coal. The Program includes development of a mathematical model of the BI-GAS process, as well as establishing a data base for the process.

Pilot Plant cost: $79 million. FY 1980 cost: Not Available.

4-76 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) BIJRNHAM 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 gasifier is also being considered for East Peoria, Illinois plant, assuming success at York. 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. Gas is currently bein2 Droduced with modifications to ecuinment and nrnceedinp ac nerecsarv

Project Cost: $5- 10 million.

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 combined-cycle coal gasification project on Sears Island, Maine was chosen by DOE for funding. A 480 Mw plant would use 4,600 tons of coal in a combined-cycle operation, using the Texaco Coal Gasification Process. General Electric Co. would provide the turbines, Stone & Webster Engineering Corp., the design work. Status: Preliminary engineering design work underway. 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 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 Btu 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 21,000 lb./h. at the 22 MWe load. During the periods of operation, the ?rod.t.jom..the gasifier has produced 4.472 x 10— Kw hours of electricity. Measured stack

Project Cost: $13.5 million CHEMICALS FROM COAL - Tennessee Eastman Co. In a privately funded project, Tennessee Eastman Company, a manufacturing unit of the Chemicals Division of Eastman Kodak Company, is planning construction of 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 anydride. Other chemicals, including methyl alcohol and acetic acid will also be produced. Bechtel Inc., will be in charge of the process design, engineering, and procurement. Construction is scheduled to begin late in 1980 in Kingsport, Tennessee with start-up planned in mid-1983. Locally mined coal will be used. Status: Engineering has proceeded as planned. Daniel International unit of Fluor Corp. has been selected as general construction contractor while Bechtel, Inc., Houston, Texas, will provide construction management. Project Cost: Unavailable

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 477 STATUS or SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) CIRCLE WEST PROJECT-- Burlington Northern, Dreyer Bros., Inc., Basin Electric, and Resource Sciences Corporation Burlington Northern (SN) has studied the feasibility of locating a proposed commercial plant for fertilizer and liquid fuels from coal on SN-owned Dreyer Brothers ranch near Circle, McCone County, Montana. SN 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 NH1 plus 2,174 TPD fuel-grade methanol. Basin Electric Power Cooperative joined SN- Dreyer Bros. in September, 1977 to evaluate alternate Montana sites. Basin would build power plant having common coal mining facilities with BN plant. Burlington Northern and Resource Sciences formed Northern Resources, Inc. which will develop mine on Dreyer Bros. ranch. Lignite may be used in synthetic fuels or fertilizer plant or for Basin Electric plant. Project Cost: Undetermined

CITIES SERVICE/ROCKWELL PROCESS DEVELOPMENT-- DOE and Rockwell International (Energy Systems Group) Rockwell to develop coal liquefaction and gasification using the Cities Service/Rockwell (CS/R) Flash Hydro- pyrolysis Process (FHP). Technique involves the near instantaneous and thorough mixing of streams of pulverized coal and hot hydrogen in a compact coal conversion reactor derived from Rocketdyne aerospace rocket technology. Rockwell received $3.2 million contract in September 1979 for additional liquefaction PDU and process economic studies. Experimental work has been done at the 1/4 and 1 TPH throughput levels. DOE awarded Rockwell an $18 million contract to design, construct, and operate an IS TPD integrated gasification PDU, capable of continuous operation, to be build near the liquefaction PDU at Rockwell's Santa Susana field laboratory near Canoga Park, California. C-E Lummus, a subsidiary of Combustion Engineering, Inc., has been selected by Rockwell International Corporation to develop the commercial design concept for a 250-billion Btu/day high-Btu coal gasification plant, which is equivalent to approximately 250 million standard cubic feet per day. In addition to synthetic natural gas, the plant will be designed for production of light aromatic liquids. Lummus will also develop capital and operating cost estimates for the commercial-scale plant and provide input to the IS-ton/day integrated process development unit test program currently being undertaken by Rockwell International. Project Cost: $3.2 million (PDU Studies) $18 million pilot plant

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, 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 in the pilot plant and cold models is completed. The pilot plant with a feed capacity equivalent to 100 tons of coal per day is located at the Coal Utilization Research Laboratory (CURL) of the National Coal Board in Leatherhead, England. Process development is now primarily under the DOE/ICGG Pipeline Gas (SPG) from Coal Demonstration Plant Program. Demonstration plant process design is completed and detailed engineering is in progress. Commercial Project feasibility studies for locations outside of Illinois have been proposed. Project Cost: CDC has spent $20 million developing process COLUMBIA COAL GASIFICATION SNG PROJECT - Columbia Gas System Inc. Columbia is evaluating the feasibility of constructing a commercial gasification facility in Illinois. Plant would process Illinois coal to produce 300 million SCFD of high-Btu gas. SNG would supplement general gas supply in Columbia system. Gasification technology has not been selected. Columbia Gasification and Exxon Coal have entered into an agreement relating to Columbia's Illinois lands which concerns the mining and gasification of coal from those lands. Project Cost: Undetermined

COMBINED CYCLE COAL GASIFICATION 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 Reger, 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/D of methanol,

4-78 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) 321 MW power generation and 220 ST/n 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 oro ject team consists of the followin g: Consumer Enerv Cornoration. Associated Flectric. Connerativp

Project Cost: 416.4 million (each plant) COMPOSITE GASIFIER PROJECT -- British Gas Corporation, British Department of Energy British Gas Corporation (BGC) plans to construct an experimental gasifier which will couple an entrained flow gasifier to the base of a fixed bed gasifier. This composite gasifier will have the capability to process run of mine coal, with fines being fed to the entrained gasifier, and lump coal being fed to the fixed bed. Pulverized coal is reacted in steam and oxygen at very high temperature, resulting in substantially complete gasification. The molten slag produced is removed by tapping, using the technique successfully developed for the Slagging Gasifier. The very hot product gas passes into the fixed bed to yield its heat to the descending lump coal. A feasibility study for a ISO tonne pilot plant was completed by Humphreys and Glasgow, Limited. Worley Engineering, Ltd. has been awarded the detailed engineering design contract for the gasifier. Operation is scheduled to begin in 1983 at the site in Westfield, Fife, Scotland. Project Cost: 20 million British pounds (April 1980 prices)

CONOCO PIPELINE GAS DEMONSTRATION PLANT PROJECT -- DOE and Conoco Coal Development Co.(CCDC), with co-offerors Consolidated Gas Supply Co. Electric Power Research Institute, Gulf Mineral Resources Co., Natural Gas Pipeline Co. of America, Panhandle Eastern Pipeline Co., Sun Gas Co., Tennessee Gas Pipeline Co., Texas Eastern Corp. and Transcontinental Gas Pipeline Corp. CCDC was awarded a contract in May 1977 to begin work on the first phase of a three-phase project to design, construct, and operate a coal gasification facility under the government's high-Btu gasification program. The DOE, however, decided that ICGG and Conoco would compete for available funds for one high Btu project and stopped work on some of the tasks in Phase I for both projects, while reviewing the separate efforts in an attempt to make a decision on which project should proceed to construction. After review, DOE decided that both projects should continue through Phase I, design, because more information was needed to make a decision. Currently the design phase is scheduled to be completed in June 1981. DOE has continued to delay a decision which is currently scheduled for early 1981. Construction is scheduled for 30 months and operation for 42 months. Original plans were to produce 59 MMSCFD of SNG from 3,800 TPD of coal in four British Gas/Lurgi Slagging gasifiers (one a standby). Currently, plans are for 2 gasifiers (one a standby) to process 1532 TPD of coal to produce 19 MMSCF of SNG. Ohio No. 9 coal was originally selected as feedstock for the process, however, severe operating problems encountered when processing this coal have led to selection of Pittsburgh No. 8 coal as the preferred feedstock. An environmental scoping meeting was held in Caldwell, Ohio in December 1979. A Draft Environmental Impact Statement (DEIS) was delivered to EPA in October 1980. A final EIS is scheduled to be available in mid-May. Status: The design phase is 2/3 complete. A 60 percent design review was held in November. Environmental permits are presently being acquired for the project. All process licenses necessary for construction have been acquired. DOE requested that Conoco prepare and submit a proposal to start the construction engineering prior to completion

Project Cost: Design Phase -- $37 million

COOL WATER COAL GASIFICATION PROJECT-- Southern California Edison, Texaco, EPRI, Bechtel Corporation Sponsors plan a 1,000 TPD demonstration plant using oxygen-blown Texaco coal gasification process. During initial shakedown, medium-Btu fuel gas from gasifier will be fired in existing 65-megawatt boiler at SCE's Cool Water generating station near Barstow, California. Subsequently, 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. Start-up is planned for late 1983 with operation of the integrated facility expected to begin early 1984. The design coal is to be Western, but a variety of coals, both Eastern and Western, are to be tested. Texaco and SCE, who are contributing $25 million each to the effort, signed the joint participation agreement on July 31, 1979. The Electric Power Research Institute (EPRI) executed an agreement to provide $50 million funding for the project in February 1980. General Electric signed an agreement in September 1980, to participate in the funding at the $25 million level and will be the supplier for the combined cycle equipment. Bechtel Power Corporation has been selected as the prime engineering contractor and also executed an agreement in September to contribute $25 million to the project.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-79 STATUS OF SYNFIJELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) was submitted to DOE for

Project Cost: $300 million CS/R HYDROPYROLYSIS PROCESS DEVELOPMENT -- Cities Service Research and Development, Rockwell Inter- national Cities Service has been evaluating a short residence time hydropyrolysis process in a bench-scale unit since 1974. The process produces pipeline quality gas and light aromatic liquids. Reactor is of entrained flow type with short residence time (< 2 sec.) and rapid quench of the reactor products. Cities Service holds patent No. 3,960,700 on the process. Cities has entered into a working agreement with Rockwell International for Joint Development of the process. See also Cities Service /Rockwell Process Development. Cities Service has been granted a DOE contract //DE-AC22-79ET 14943 to investigate the CS/R process using promoters on agglomerating Western Kentucky No. 9 Bituminous Coal for the applicability and potential to enhance conversion to liquid hydrocarbons in the gasoline and heating oil ranges.

Project Cost - $500,000 DE SOTO COUNTY, MISSISSIPPI COAL PROJECT -- State of Mississippi, Mississippi Power & Light Company, and Ralph M. Parsons Co. The State of Mississippi, with the cooperation of Mississippi Power & Light Co., N. Bunker Hunt, and the Ralph M. Parsons Company, submitted an unsolicited proposal to the DOE in June to perform a feasibility study for a Demonstration Coal Gasification Facility in De Soto County Mississippi. Ralph M. Parsons would perform the study to determine the best technology to be used to provide the energy requirements for a new town and industrial center to be built on 13,000 acres of undeveloped land owned by N. Bunker Hunt. Mississippi Power & Light Co. (MP & U plans to build one or more coal plants near the site and would take the output from the gasification facility until such time as the community would need it. Project Cost: $1.25 million for the feasibility study.

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 underflow is extracted with paraffinic solvent in a counter- current 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 plans to rebuild the 200 pound per day mini-plant. The skid-mounted mini-plant will be operational by late 1980 and able to 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 In February 1980, Nokota filed a "Prevention of Significant Air Quality Deterioration Permit Application" for construction of a coal-to-methanol facility in Dunn County, North Dakota. Nokota holds leases on coal lands in the area containing 3 billion run-of-mine tons of recoverable lignite. Preliminary feasibility studies have been completed. Fluor Engineers & Constructors has completed preliminary design of a commercial scale plant using Lurgi gasifiers and methanol synthesis units and producing 11,618 short tons per stream day (ST/SD) of fuel grade methanol (99.00% methanol) plus by-products from 28,346 ST/SD of sized lignite coal fed to the gasifiers. Among other by-products, 3,050 barrels per stream day (BPSD) of gasoline blending stock will be produced. 8,119 ST/SD of lignite coal fines will be fed to the boilers for production of the steam and power required to operate the plant and mine. Ninety percent of the environmental baseline studies are complete, and all critical permits are expected to be obtained by Spring, 1982. Mechanical construction is scheduled to begin during Spring, 1983; and mechanical completion is scheduled for Spring, 1986, with full production by Fall, 1986. Nokota was selected in July 1980, by the DOE to receive a $4 million grant to fund further engineering, environmental, marketing, financial, transportation and related coal-to-methanol project studies under the "Alternate Fuels Program' (Public Law 96- 126). Project Cost: $1.8 billion (mid-1980 dollars) exclusive of financing charges and mine capital costs.

4-80 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

EMERY COAL CONVERSION PROJECT -- Mountain Fuel Supply Company, Inc., Pacific Gas and Electric Company, Mono Power Company, and Conoco Coal Development Company Mountain Fuel Supply Company (MFSC) 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 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 125 billion Btu's per day of substitute natural gas and methanol, initially, increasing to 250 billion Btu's in an equal mix. Mountain Fuel Resources, Inc., together with Pacific Gas and Electric Company, Mono Power Company, a subsidiary of Southern California Edison Company, and Conoco Coal Development Company is conducting a feasibility study of the technical, economic, regulatory, and business assets of the project. Completion of the study is scheduled for November 1981.

Project Cost: Undetermined ENRECON COAL GASIFIER -- Enrecon, Inc. Enrecon is developing a fluidized bed, medium-Btu coal gasification process in Golden, Colorado. The process will utilize a proprietary catalyst to improve gasifier performance. The 60 TPD pilot plant began start-up in December 1979. The first campaign was completed February 28, 1980; the second campaign was completed May I. A total of 200 hours of operation were completed to establish the ability of the process to produce medium Btu gas at 215 psig. Campaign 3 started the first week of June and was completed at the end of August. Preliminary design work is underway for a scaled-up 600 TPD demonstration plant, in addition to a preliminary economic assessment and Phase II pilot plant design. Enrecon predicts over 80 Dercent cold ens effiri pnrvntnunr '71, ntIcr

Estimated Cost: $,.o million for 60 TPD Phase I pilot plant, $10 million for Phase If integrated Pilot Plant EXXON CATALYTIC GASIFICATION PROCESS DEVELOPMENT-- DOE, GRE and Exxon Exxon Research and Engineering Company was awarded a contract by DOE in September 1978 for a Catalytic Coal Gasification (CCG) process development program continuing through 1980. The Gas Research Institute (GRI) has also funded the project since January 1979. The development program includes 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 first fully integrated test was completed in July 1980. The process uses a potassium catalyst (K,CO 3) which promotes both the steam-carbon gasification and methanation reactions when added to the feed coal. bperating at 1,300°17 and with the promotion of the K,CO 3 catalyst, the gasification rate is high enough to yield a high CH concentration. Since the amount of CO and I-T 2 recycled back to the gasifier balances, the amount of CO and H 7 leaving the gasifier, the net products of gasification are mainly CH 4 with lesser amounts of CO 7, H 2 S, and NH 3. Since methane is produced directly in the gasifier, the need for ware r shift and methanation reactors and for an oxygen plant are eliminated. Exxon Corporation's Dutch affiliate, Esso Nederland,. plans to construct and operate a 100 ton-per-day pilot plant at Rotterdam, Europort, Holland, and operation is expected to begin in mid-1985. The new plant, is expected to cost more than $500 million and is part of an 8-year pilot project. DOE participation in 1981 and beyond is bein g negotiated. Project Cost: $16.8 million (DOE contract)

EXXON DONOR SOLVENT PROCESS DEVELOPMENT -- Exxon Company, USA, DOE, Electric Power Research Institute, Japan Coal Liquefaction Development Co., Phillips Petroleum Co., Atlantic Richfield, Ruhrkohle A.G., and AGIP Exxon and DOE entered into a Cooperative Agreement in July 1977, for a fully integrated development program involving a 250 TPD coal liquefaction large pilot plant (ECLP) and parallel small pilot plants, bench scale research, engineering research, and engineering design study activities. The $296 million program runs for 8.5 years 0976 to mid-1984). The overall costs of the project are proportioned as follows: DOE - 50 percent, Exxon - 22 percent, EPRI - 12 percent, JCLD - 8 percent, Phillips - 2 percent, Atlantic Richfield - 2 percent, Ruhrkohle - 2 percent, and AGIP percent. Contracts for the pilot plant were awarded in September 1977: Arthur G. McKee and Co., design; Daniel Construction Co., construction. Pilot plant start-up began in March 1980; coal-in operation began June 24, with Illinois No.6 coal. The first run lasted 128 hours, the second run, 21 da ys. The unit has loeeed over IOU hours

A program to operate a FLEXICOKING* prototype on EDS vacuum bottoms feed is now underway. Part I, engineering design studies, (5.6 M$) was approved by the project sponsors. Part II of this program, revamp and operation of the 750 B/D FLEXICOKlNG unit, is being supported by the U.S. Department of Energy - 50 percent,

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-81 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes since September 1980)

COAL CONVERSION PROJECTS (Cont.) Exxon - 36 percent, JCLD -8 percent, Atlantic Richfield - 2 percent, Ruhrkohle - 2 percent and AGIP - 2 percent. Field construction is projected to begin second quarter 1981 with mechanical completion during third quarter 1982. Exxon USA will operate the plant for 18 months on vacuum bottoms generated in ECLP. The first bottoms run in the Prototype will be from Illinois No. 6 coal. Pilot plant evaluation of partial oxidation as a second bottoms process is also being considered. *Service Mark Project Cost: million - Phases lIlA-V $5.6 million - Part I: FLEXICOKING 4 Engineering Design Studies $59 million - Part II: FLEXICOKING* Prototype

EXXON EAST TEXAS PROJECT - Exxon Coal, USA Exxon is studying the possibility of constructing a 42,000 ton/day coal gasification plant. The project would be located at a mine to be constructed in the East Texas counties of Cherokee and Rusk. The plant would produce 800 MMCFD of 400-Btu 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 $10 million agreement with Lurgi Kohle and Mineraloltechnik of

Project Cost: $20i- million for detailed design $2+ 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 on 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 (FFB) Gasification process. The FF6 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 locatedat 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 next phase, scheduled for early 1981, will be on bituminous coal with char recycle.

Project Cost: $4 million (Phase I contract) $1.8 million (Phase II contract) FIRING OF IRON ORE PELLETIZING FURNACE WITH LOW-BTU PRODUCER GAS --U.S.B.M. - Twin Cities Metal- lurgical Research Center, DOE, and 17 corporations with interest in iron and steel, coal gas, and industrial engineering. 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 but 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 coat fines was started October 1979, but was aborted after 10 hours.

4-82 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

Phase I of the contract has been completed and Phase II is underway. Modifications to the gasifier facility were completed and testing began in October 1980. A four (4) week continuous test with North Dakota "Indian Head' lignite to determine maximum lignite gasification rate and to evaluate the raw low-Btu lignite gas for high temperature induration of magnetite pellets was completed in November 1980. The test used approximately 1000 tons of lignite, and included pellet testing. A IC-day gasification test with briquettes (2 1/4 x 2 1/4 x I 3/8 pillow shape) made from a mixture of coking coal and a refuse derived fuel (RDF) via the Simplex Process was scheduled for the first week in December. The Phase I and II reports are scheduled for completion sometime in the third quarter of 1981.

Project Cost: $2.5 million

FLASH HYDROPYROLYSIS PROJECT - DOE and Brookhaven National Laboratory This project is an experimental study at the bench-scale to investigate flash hydrocracking of lignite and other coals. A tubular reactor is used with hydrogen flow rates to two pounds-per-hour at up to 4,000 psig and 900°C. The purpose of the study is to determine the effects of reaction variables and the process chemistry on the conversion of coal to liquid and gases. It was found that for lignite, maximum yields occur at 775°C and 2000 psi with conversion of 65 percent of the carbon in lignite to liquids (10 percent benzene + 10 percent oils) and gases (SI percent CH4, 10 percent CH, 4 percent co). Maximum conversion to gases occur at 875°C and 2500 psi with 90 percent conversion to all gases (89 percent CH 4 + C 2 and I percent co). Yield data for subbituminous coal have been obtained. Benzene yields are up to 15 percent wA 5 percent oils. Bituminous coal data are in the process of being analyzed. Kinetic expressions for the lignite yields have been derived. Project Cost: $300,000

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 powergeneration 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.

Project Cost: Phase 1 - 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 (HTTT) Program, whose 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, burning 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 HTTT 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 Curtiss-Wright ($2 7 .4 million) in August 1977. General Electric is developing the technology for a water- cooled gas turbine while Curtiss-Wright is pursuing a transpiration air-cooled gas turbine approach. Phase III of the HTTT Program (Technology Readiness and Verification Testing) will entail the final design of the selected gas turbine and the verification testing of the machine prototype. Project Cost: Phase I - $9 million Phase II - $58 million Phase III - Undetermined

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-83 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) GEGAS-D PROJECT -- General Electric Co. G.E. is developing a 24 TPD, 23 atmosphere fixed bed coal gasifier producing low-Btu gas. The plant is located at G.E.'s Research and Development Center at Schenectady, New York. Checkout runs began in February 1976. The unit is equipped to study gasification of highly caking fuels at reduced steam/air ratios under clinkering conditions. Test results on a wide range of coals in a 50 pound-per-hour atmospheric gasifier provided many of the design bases. Coal extrusion feeding and tar balance closure are to be developed and tested on the 24 TPD reactor. An overall objective of this facility is to provide a realistic simulation of an integrated gasification, gas turbine combined cycle system. G.E. has operated the gasifier at rated conditions on Pittsburgh I/S and Illinois //6 caking coals. Recent tests have been completed with the gasifier, physical gas cleanup and combustion systems in operation. A chemical cleanup (H,S removal) system has been added to the facility and check out tests have been completed. The total gasificatiort, gas cleanup, turbine simulation is now in operation. It is being utilized to evaluate gas turbine compatibility with this coal derived fuel class. The fuel plant simulator will also evaluate the critical component integration features. A test series has recently been completed in which the gasification gas cleanup fuel plant was utilized to supply a realistic coal derived fuel to a turbine simulator operating at advance gas turbine firing conditions, turbine inlet temperature 2600°F, pressure ratio 12 to 1.

Project Cost: $3.1 million -GRACE AMMONIA FROM COAL PLANT - (DOE, W. R. Grace and Co.) Contract No. ET-77-C-01-2577 (Currently DE-ACO2-77ET13042) was awarded to W.R. Grace and Co. in the amount of $10.2 million in August 1977. The contract consisted of a three-phase coal-to-ammonia plants and, if warranted by an evaluation of the technical, economic and environmental aspects fo the Demonstration Plant design, the construction of the demonstration-sized plant, and the operation of such plant during a demonstration period. The demonstration-size plant would use the Texaco Coal Gasification Process (TCGP) to gasify approximately 1850 tons per day of West Kentucky No. 9 coal to produce sufficient synthesis gas for the production of 1200 tons per day of ammonia. The proposed site for construction of the plant is Baskett, Kentucky. Ebasco Services, Inc., has provided architectural engineering services with process engineering and technical support supplied by Humphreys & Glasgow International Ltd. of London and Texaco Development Corporation. Status: All Phase I documents were completed and submitted to DOE in December 1979. As was required by the contract with DOE, Grace indicated that due to current market conditions in the fertilizer industry, it did not desire to go forward with construction of the ammonia from coal facility. DOE has since selected a competitive project to proceed into construction and the Grace/DOE contract is in the process of being closed out. Project Cost: Phase I (previous contract) $12.2 million. Present contract 12.6 million

-GRACE COAL-TO-METHANOL-TO-GASOLINE PLANT - (DOE, W. R. Grace & Co.) Cooperative Agreement No. DE-FCOI-80ET14759 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, financing investigation for a 50,000 barrels per day coal-to-methanol-to-gasoline plant to be located in Baskett, 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 to produce approximately 16,000 tons of methanol with subsequent conversion into 50,000 barrels per day of gasoline plus by-products C 3 and C 4 LPG streams. The preliminary design effort is to span a period of 24 months during which time Grace will approach the Synthetic Fuels Corporation for financial backing of the construction costs.

Project Cost: Preliminary design - $12.6 million (DOE) Construction cost - $3.0 billion (1980 dollars) GRACE SYNTHETIC FUEL LIQUEFACTION PLANT -- W. R. Grace & Co. W. R. Grace & Company is studying the feasibility of building a liquefaction plant using coal reserves in northwest Colorado to produce methanol and carbon dioxide to be used as the slurry in a coal-slurry pipeline. Energy Transition Corporation (ETCO) will determine the feasibility of separating the methanol, carbon dioxide and coal. The coal would then be used for electric power generation, the carbon dioxide for tertiary oil recovery from heavy sands, and the methanol for gas-turbine power generation or conversion to automotive fuel. Koppers technology would be used to produce 5,000 tons of fuel grade methanol and 6,000 tons of carbon dioxide per day. Grace was awarded $786,477 for Stage Ill of the feasibility study as part of the Government's 96-126 a feasibility awards.

Project Cost: $500 million *New or Revised Projects

4-84 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980

STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

GRAND FORKS LIQUEFACTION PROCESS FOR LOW-RANK COALS --DOE, Grand Forks Energy Technology Center, University of North Dakota At the Grand Fork; Energy Technology Center, research on coal liquefaction is directed toward development of a scientific and engineering data base for low-rank coals. Response to liquefaction conditions for low-rank coals differ from those of bituminous coal. These data are required to apply techniques of the major developing liquefaction process to the distinctly different low-rank coals. Initially, process development at the Grand Forks Energy Technology Center was concerned with the reaction of carbon monoxide with full moisture lignite and solvent to produce a "low-ash" solid or heavy liquid. Presently, the research emphasis has shifted toward obtaining a distillable liquid product using synthesis gas -- a mixture of carbon monoxide and hydrogen -- instead of pure hydrogen. A continuous process unit of 10 lb/hr coal slurry capacity is currently in operation employing a continuous stirred tank or a tubular reactor. Conditions for operation are 2,000 to 4,000 psig at 400 to 500°C. In recycle operation unfiltered product slurry (BP 300°C. @ 2000 psi) including ash and unreacted coal, serves as the vehicle solvent for fresh lignite. Yields (at 2000 psi with pure hydrogen) of soluble oils of better than 60 oercent of the MAP lipnite

or

Under a subcontract, the University of North Dakota is investigating the catalytic effect of the diverse mineral matter in low-rank coals in liquefaction and the progressive conversion of heavy organic liquids and coal solids during recycle using batch autoclaves.

Project Cost: $1.24 million, FY 1980

GREAT PLAINS GASIFICATION PROJECT Great Plains Gasification Associates, (Subsidiaries of American Natural Resources Company, Peoples Energy Corporation, Columbia Gas System, Inc., Tenneco Inc., Transco Companies, Inc.) Michigan Wiconsin Pipe Line Company, a subsidiary of ANR, initiated design work for the Mercer County, North Dakota project in 1973. ANG Coal Gasification Company was formed in 1975 to construct and operate the facility. An application to the Federal Power Commission (now FERC) was filed in 1975 for a 250 million cubic feet/day plant. However, the project could not be financed under terms acceptable to the FERC, the financial community and ANR. The size of the plant was reduced to 125 million cubic feet/day in 1976, and Peoples Gas Company (now Peoples Energy Company) joined the project as an equal partner in 1977. Financing still continued to be a problem and in 1978, at the recommendation of the DOE, the ownership concept was expanded to include three additional partners. Consequently, Great Plains Gasification Associates (GPGA), a general partnership, was formed which consisted of affiliates of Columbia Gas Transmission Corporation, Tennessee Gas Pipeline Company, and Trans- continental Gas Pipeline Corporation, in addition to the two original project sponsors. GPGA holds title to the Mercer County Project. ANG will act as the project administration for Great Plains, and the consortium members will equally share the gas produced. Engineering work continued, with some disruptions, while the above financial and regulatory activities proceeded. Beginning in 1973, major engineering work was performed with the assistance of engineering firms, such as C-E Lummus Company, Kaiser Engineers and Lurgi Kohle and Mineraloltechnik GmbH (Lurgi). To date, over $40 million has been spent on the project which has resulted in a complete process conceptual design, the start of detailed engineering and a control cost estimate suitable to initiate construction. On November 8, 1978, Great Plains announced the postponement of detailed engineering design work which would have allowed start of construction in the Spring of 1979. To meet an early 1979 construction start date, the project faced accelerating costs for final design work. In the face of continued uncertainty at FERC the project could not prudently undertake those costs and work on the project halted. The record before the FERC was closed on February 20, 1979, and the Administrative Law Judge's initial decision denied application on June 6, 1979. FERC reversed the decision on October 22, 1979, but only addressed the issue of passing the plant costs to the customers involved, delaying further action until a hearing on November 15. At the hearing, FERC issued a Certificate of Public Convenience and Necessity to Great Plains, but with a modified package of conditions. On February 4, 1980, Great Plains accepted certification with the condition of commission approval for various tariff documents. On March 20, 1980, appeals were filed in the U.S. Circuit Court of Appeals, Washington, D.C., by the New York Public Utilities Commission, the State of Michigan, General Motors Corporation and the Ohio Consumer's Counsel, effectively placing another temporary obstacle to the construction of the Great Plains project, which had been expected to begin in April, 1980. Thus, final financing arrangements and construction have been delayed until the issues raised by these appeals are resolved. Court proceedings were expected to be completed within six months.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-85 STATUS OF SYNFIJELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) As a result of the delay, ANG requested a $250 million loan to cover costs for the first year of construction. The White House announced approval of a conditiol commitment for the loan on July 18, 1980. On November 19, DOE announced conditional approval foi -antee of uo to 1.5 billion of Drolect costs. This new commitment incorporates the $250 million bar million to the project sponsors under a cooperative agreement for the planning and mobilization of the architec and engineering team and completion of the development of project schedules, as well as other preparatory engineering activity. Site grading and preliminary construction activities on the project began July 25.

Project Cost: plant (137.5 MMCFD) $1.6 billion Mine (Gasification Plant Share) $150 million Escalated to 1983 H-COAL PROJECT -- DOE, Ashland Synthetic Fuels, Inc., Conoco Coal Development Co., Mobil Oil Corp., Standard Oil Co. (Indiana), Commonwealth of Kentucky and Electric Power Research Institute, Ruhrkohle AG (West Germany), Hydrocarbon Research Inc., (subsidiary of Dynalectron Corporation) - During June 1980, coal liquefaction operations began on the 600 TPD H-Coal pilot plant located near Ashland's Catlettsburg, Kentucky oil refinery. A two year operating program on coal from Kentucky, Illinois and Wyoming is planned. 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 hydrocboned 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 underf low could be gasified for hydrogen production. Project funds have been proportioned -DOE (80 percent) and industrial participants (20 percent). Ashland has initiated program for construction of a $3 billion, 50,000 BPD commercial scale plant to DOE, with Airco Cryoplants, Inc. participating. The Commonwealth of Kentucky presented a check for $500,000 to American Smelting and Refining Co., (ASARCO) in February 1980, for an option on a 1600 Acre site in Breckinridge County KY., owned by ASARCO for construction of a commercial-sized plant. HRI is conducting a program of R&D support for pilot plant operations and process improvement.

Project Cost: $296 million (design - $14.7 million, construction - $157.3 million, operation for two years - $124 million) HOWMET ALUMINUM PROJECT - Howmet Aluminum Corporation, Lancaster. PA A ten-f6ot diameter single stage Wellman-Galusha gasifier has been started-up but is presently 'banked" waiting on modifications to be completed on the furnace to which the gasifier is connected. The unit will produce low-Btu gas equivalent to 500 MMBtu per day for use in aluminum melting furnaces.

Project Cost: $700,000 HYGAS PILOT PLANT PROJECT-- DOE, Gas Research Institute, and Institute of Gas Technology The HYGAS Pilot Plant has been operating at IGT, Chicago, Illinois, since 1972. The plant design capacity is 75 tons-coal/day producing 1.5 MMSCF/day of pipeline gas. The process reacts steam and hydrogen with coal or coal chars, at pressures between 1000 to 1500 psig and temperatures between 1,400 0 and 1,800°F. The raw product gas contains hydrogen, methane, traces of ethane, carbon oxides and sulfur compounds. The hydrogen requirement is generated by steam-oxygen gasification of residual char from the hydrogenation stages. Technical feasibility of the process has been demonstrated with Montana lignite (1975), subbituminous coal, and with Illinois bituminous caking coal (1976). UOP's Procon Division prepared conceptual designs for a commercial and a demonstration plant based on the HYGAS Process. Operations directed towards supplying design data for the HYGAS process using western Kentucky Bituminous coal feed have been completed with DOE funding. The HYGAS Pilot Plant operations were terminated in August 1980 after com pleting the experimental program with Western Kentucky coal. The final pilot plant for peat gasification. The plant will be operated by IGT and jointly funded by DOE and CR1.

Project Cost: Total Cost, $24 million DOE - $16 million CR1 - $8 million

4-86 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNF(JELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

ICGG PIPELINE GAS DEMONSTRATION PLANT PROJECT - DOE and Illinois Coal Gasification Group (ICGG) -(Industrial participants are subsidiaries of Northern Illinois Gas Co., Peoples Gas Light & Coke Co., Central Illinois Light Co. Inc., Central Illinois Public Service Co., and North Shore Gas Co. respectively.) ICGG was awarded a contract in June 1977 to begin work on the first phase of a three-phase project to design, construct, and operate a coal gasification facility under the governments high-Btu gasification program. The DOE, however, decided that ICGG and Conoco would compete for available funds for one high Btu project and stopped work on some of the tasks in Phase I for both projects, while reviewing the separate efforts in an attempt to make a decision on which project should proceed to construction. After review, DOE decided that both projects should continue through Phase I, design, because more information was needed to make a decision. DOE has continued to delay a decision which is currently scheduled for early 1981. The 2200 TPD coal gasification facility will produce 24 million SCFD of SNG, 1,700 BPD of fuel oil, and 400 BPD of naphtha. The plant is to use the COGAS process with COGAS Development Company functioning as the principle project licensor and Dravo Corporation as the architect- engineer. The process incorporates fluidized bed pyrolysis to produce both gas and liquids. The development of the COGAS process is supported by a consortium of American companies. The ICGG plant is proposed to be built in Perry County, Illinois, and is to process a blend of Herrin No. 6 and Harrisburg No. 5 coal as its primary design coal. Provisions will be made for processing two alternate coals. Conceptual commercial plant design has been completed. Demonstration plant process design is in preparation. DOE will fund the majority of costs of the ICGG project through Phase I, Demonstration Plant Design. Status: DOE is currently revising a draft environmental impact statement (DEIS) for the plant in Perry County, Illinois. A public meeting to discuss environmental issues of the demonstration plant was held in August 1979 in Cutler, Illinois.

Govt. Project Cost: Design $35 million and 50 percent of construction and operation costs.

*INTEGRATED INDUSTRIAL SYNFUEL COMBINED CYCLE COGENERATION PLANT -Texaco Inc., General Electric Co On September 30, 1980, Texaco and General Electric submitted a proposal to DOE to conduct a feasibility study to evaluate the use of a synthetic fuel system, known as an Integrated Industrial Synfuel Combined Cycle Cogeneration Plant (ISCP), in industrial applications at two GE plants, which together would convert about 1,300 tons of coal per day into medium-Btu synthesis gas. The ISCP system will use the oxygen-blown Texaco Coal Gasification Process for synthesis gas production and a General Electric gas turbine, with a heat recovery steam generator and steam turbine suitable for cogeneration of power and thermal energy.

ProjectCost: $2.7 million for the feasibility study. KEN-TEX PROJECT - Texas Gas Transmission Corp. and Commonwealth Of Kentucky 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, propose 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-Stu gas of 975 Btu/CF heating value. Phase I -80 MMSCFD demonstration plant. Phase II -250 MMSCFD commercial facility. Status - A joint proposal by the Kentucky Department of Energy and Texas Gas Transmission was submitted to DOE in December 1979 to perform additional work to complete Phase zero of the multi-phase program.

Project Cost: $750 million

KILNGAS PROJECT -- Allis-Chalmers, State of Illinois, Gilbert/Commonwealth Associates, Inc., Electric Utility participants are: Baltimore Gas and Electric Co., Central Illinois Light Company, Consumers Power Co., Illinois Power Co., Iowa Power Co., Monongahela Power Co., Ohio Edison Co., Potomac Edison Co., Public Service Indiana, Public Service Co. of Oklahoma, Union Electric Co., and West Penn Power Co. The KILNGAS process is based on Allis-Chalmers 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 TPD Commercial Module plant occurred on October 31, 1980. The plant will provide low-Bt.11 60 Btu/SCE) gasjo the Wood River Station of the illinois Power Company at East Alton, Illinois. Mechanical completion is scheduled for late 1972. Gilbert is providing AlE scenarios. J.A. Jones Construction of Charlotte, N.C. was chosen as construction manager for the plant. State o f illinois has allocated $18 million in Coal Development Bond Act funds to assist in construction of the plant. Each of theelectric utility participants is considering purchase of 4,000 to 5,000 TPD plants either to displace oil from existin g boilers or to fuel new combinpd .-vrI nnwarnIntc 'lflth

Project Cost: Estimated at $135 million *New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 - 4-87 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) *LAKE DE SMET SNG FROM COAL PROJECT - Texaco, Inc., Transwestern Pipeline Co. Texaco and Transwestern Coal Gasification Co. (a subsidiary of Texas Eastern Corp.) proposed to DOE, September 30, 1980, to evaluate the feasibility of constructing a commercial scale synthetic fuels plant near Lake DeSmet, 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. A multi-million dollar water development project has been completed as a prerequisite for future utilization of the coal reserves. This represents a modification of a previously announced study by the two concerns, which now propose to become joint participants in the synfuels facility itself, with Texaco Inc., being the sole owner and operator of the mine supplying the coal for conversion to synfuels. Project Cost: Undetermined LEWIS RESEARCH CENTER GASIFIER ALTERNATIVE POWER PLANT - NASA Lewis Research Center and Cleveland Electric Illuminating Co. (CE!) In response to the National Energy Act of 1978 that directs all Federal facilities to conserve natural gas and oil, and wherever practical convert to coal, the Lewis Research Center investigated several alternatives for using high sulfur coal in an environmentally acceptable manner. Preliminary analyses indicated that a coal gasifier and cold gas cleanup system integrated with a combined cycle cogeneration powerplant could provide both steam heating and baseload electrical demands for the center. CEI and Lewis Research Center agreed to cooperate in a feasibility study to assess the technical, environmental, and economic factors for this power plant concept to be sited at the Lewis Research Center in Cleveland, Ohio. A six month conceptual design was completed by Davy Mckee

Project Cost: $58 million LC-FINING PROCESSING OF SRC EXTRACT - DOE and Cities Service Pilot plant studies are being made to demonstrate the use of Lummus/Cities-Fining (LC-Fining) technology to upgrade solvent refined coal extract (SRC-1). SRC-I, 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-I 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-I 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 0 F). The technical information derived from this work is being used in support of the current DOE-sponsored two-stage liquefaction program. Hydrocracking of the SRC-I/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 1 - C4 gas yield. PDU operations under this contract have been completed and a final report is being prepared. Project Cost: $2.8 million 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 useability of low-medium Btu 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, but was turned down. Project Cost: $922,000 *New or Revised Projects.

4-88 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

LUMMUS COAL LIQUEFACTION DEVELOPMENT - DOE and Lummus Co. Lummus is developing a catalytic coal liquefaction process (clean fuels from coal) on a 30 lb/hr bench scale unit. The program is geared towards production of all-distillate product which can be readily upgraded to transportation fuels. The experimental program was completed early in 1979, and is currently under review by DOE through a UOP subcontract. The Clean Fuels From Coal (LCFFC) Process, employs a series of plug-flow, expanded catalytic reaction beds and a patented Lummus anti-solvent deashing technique for solids removal. The deashing module of the LCFFC Process has been successfully demonstrated at DOE's Fort Lewis, Washington, facility, and is undergoing final installation at DOE's Catlettsburg, Kentucky, plant designed to handle 600 tons/day of coal.

Project Cost: $4.7 million (2.5 year contract) MEDIUM BTU GASIFICATION PROJECT - Houston Natural Gas Corporation, Texaco The feasibility of building a medium-Btu coal gasification plant using the Texaco coal gasification process to produce 300-Btu synthesis gas has been under study by Houston Natural Gas Corporation (HNG) and Texaco, Inc., since late 1979. A preliminary engineering feasibility study was completed by Ebasco Services in January 1980. Texaco and HNG have received a DOE grant 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 25,000 barrels a day of methanol. Status: Preliminary engineering design is underway.

Project Cost: Undetermined

MEDIUM BTU SYNTHESIS GAS STUDY - Airco, Inc., Bechtel, Inc., Cities Service Co., Conoco, Inc., PPG Industries, and United Energy Resources, Inc.

A feasibility study is being conducted for a medium-Btu coal gasification plant to be located in Louisiana. Initial output of the plant would be 125 million Btu daily, as early as 1986. The plant would be built in stages to an eventual capacity of 250 million Btu daily. The participating companies would use the synthesis gas for a variety of purposes, including compliance with the Powerplant and Industrial Fuel Use Act, expansion of operations, sales to other industrial customers, and feedstocks for products such as methanol. The study will address economics, technology, plant site location, and raw material supply sources, and is expected to take more than a year to complete. Estimated Cost: $1,000,000 for the study.

MEMPHIS INDUSTRIAL FUEL GAS DEMONSTRATION PLANT-- DOE, Memphis Light, Gas and Water Division Memphis Light, Gas and Water (MLCW) is under contract to DOE to design and construct medium-Btu gasification plant converting 3158 tons of coal into 175 MMSCFD of 300 Btu/CF fuel gas. IGT's U-Gas1z Gasifier will be used to produce fuel gas for industrial customers in Shelby County, Tennessee. Foster Wheeler Energy Corporation will 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 proposed feedstock. Phase I (Preliminary Engineering and Design) was submitted to DOE on December I, 1979 for evaluation, and a contract to proceed into Phase II was signed in May 1980. During Phase II Memphis Light, Gas and Water will continue in its Dresent roll as orime rontrartnr Fnster Wheeler support provided by IGT will include pilot operations at its Chicago Energy Development Center where the U-GAS" Gasifier was developed. - Construction of the plant is scheduled for completion in 1984 with demonstration period to be completed in 1986 at a total cost of about $700 million. In Phase III of the project Delta Refining will start-up and operate the demonstration plant with emphasis on safety and efficiency of operation.

Project Cost: Phase I -$11.00 million (DOE) Phase II - j9 million (DOE/MLGW) Phase III - $80 million ( DOE/MLGW)

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-89 STATUS OF SYNFUELS PROJECTS/COAl. (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) MINNEGASCO PEAT BIOGASIFICATION PROJECT - DOE and Minnesota Gas Company, (Dynatech R/D Company, Subcontractor) Minnegasco's laboratory scale research and preliminary economic evaluation on peat biogasification performed by Dynatech RID Company were very encouraging. DOE signed a contract with Minnegasco for co-funding on a continuation of the experimental work on pretreatment and fermentation of peat to produce methane. The work is being conducted at Dynatech RID Company.

Project Cost: $425,000 for 18-month project starting October I, 1979.

MINNEGASCO PEAT GASIFICATION PROJECT-- DOE, Gas Research Institute, and Minnesota Gas Company Minnegasco began evaluation of peat gasification in conjunction with IGT in 1974. In July 1976, ERDA signed contract with Minnegasco for laboratory and PDU-scale gasification of peat. Work being conducted at IGT for conversion of peat to SNG, and other tests at Dynatech R&D Company and Rockwell International are underway. Use of HYGAS pilot plant for peat planned to begin by September 1980; pilot plant modification costing about $3.0 million is planned to be completed by October 1980.

Project Cost: $1.2 million for 1976-1978 project Minnegasco recently awarded $2.0 million DOE contract to extend PDU work until August 31, 1980. MOLTEN SALT PROCESS DEVELOPMENT-- DOE and Rockwell International Rockwell plans to design, build and operate a 1 TPH PDU to test molten salt gasification process for low-Stu 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. H 25 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 2 program has been initiated aimed at completing the development of the low-Btu (airblown) Molten Salt Coal Gasification Process. Preparations are currently underway for the first run of Phase 2.

Project Cost: $12.6 million (Phase 1) sirmillion (Phase 2) $17.0 million (Total)

MOUNTAIN FUEL SUPPLY COMPANY COAL GASIFICATION PROCESS --Mountain Fuel Supply Company Inc., Ford, Bacon & Davis Mountain Fuel and Ford, Bacon and Davis have developed an entrained flow, oxygen blown gasifier in a 0.5 TPD laboratory facility. The gasifier operates at slagging temperatures (about 2,800°F), and 150 psig. The heating value of the product gas is about 300 BtuISCF. Both radiant and convective heat exchangers are used to recover heat from the process. Detailed engineering is 80 percent complete for a 30 TPD process development unit which will be used to fire existing brick kiln at Salt Lake City. DOE funding is being sought. Project Cost: $6.0 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. A 25 ton-per- day pilot plant has been designed with support from British Petroleum Co., and construction will start early 1981 at Point of Ayr, North Wales,

Project Cost: 25 million British pounds (1980 prices)

4-90 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) NATIONAL COAL BOARD LOW BTU GASIFICATION PROJECT - National Coal Board 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 Control Electricity Generating Board has led to recommendations to proceed. Project Cost: Feasibility study and associated experiments - 2 million British pounds Pilot plant program - 15 million British pounds NATIONAL COAL BOARD SUPERCRITICAL GAS SOLVENT EXTRACTION PROJECT - National Coal Board, British Department of Energy NCB has developed the Supercritical Gas Solvent Extraction (SGSE) process on a scale of 5 kg. per hour. An aromatic solvent such as toluene is used to extract hydrogen-rich components from coal at 350-400°C and 100-200 atmospheres. This is above the critical temperature and pressure of the solvent. When the solvent is cooled and depressurized, a pitch-like material is recovered. This is hydrogenated to produce light distillates. Badger Ltd, assisted by Badger Energy Services Inc., have prepared conceptual designs of a plant having an output of 60,000 BPD of liquid hydrocarbons under separate contracts from the NCB and Shell Coal International Ltd. The designs have been used as models for economic evaluation. A 25 ton-per-day pilot plant has been designed with support from the British Department of Energy and British Petroleum Co. and Construction should start early 1981 at Point of Ayr, North Wales.

Project Cost: 29 million British pounds (1980 prices)

NEW MEXICO LURGI COAL TO GAS/METHANOL PLANT (formerly Wesco Coal Gasification Project) -- 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. The companies have requested a $3 million grant, the final amount of which is subject to negotiation, for a feasibility study to determine the project's technical, economic and environmental viability. The study, which is expected to be completed within the next 12 months, will include preliminary plant design, construction schedules, capital and operating cost estimates, evaluation of plant site alternatives, further studies on the characteristics of local coals, evaluation of product transportation alternatives and environmental and socio-economic impact studies. Project Cost: (Studies to provide cost basis within next 12 months)

PIKE COUNTY LOW-BTU GASIFIER FOR COMMERCIAL USE -- DOE, Appalachian Regional Commission, Common- wealth of Kentucky In April 1977, DOE awarded a five-year cost-sharing contract to Pike County, Kentucky, for design, construction and operation of two-36 TPD Wellman-Galusha gasifiers to be located near Pikeville, Kentucky. Architectural and engineering services were provided by Mason & Hanger Silas Mason Co., Inc., Lexington, Kentucky. The low-Btu gas will serve a multi-faceted development including residential housing, a shopping center, municipal buildings, etc. The product will be approximately 2930 MMCF of 150-Btu gas per year. Design and engineering completed, construction began in October 1978, and gasifier installation began in June 1979. Initial construction is complete. The scope of the project is being reviewed to include a gas clean-up system and a new basis for proceeding with the project is being established. Project review and establishment of new project baseline is being conducted by Stearns-Roger, Denver, Colorado.

Total Project Cost: $12,110,000 DOE - 50 percent Kentucky Department of Energy - 25 percent Appalachian Regional Commission - 25 percent

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-91 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) RISER CRACKING OF COAL -- DOE and Institute of Gas Technology This project is a 4-year experimental study to investigate a process for the conversion of coal to BTX rich synthetic motor fuel by rapid gas-phase hydrocracking of coal. In Phase I of the work, a coiled 118-75 bench-scale reactor (BSR) was designed and fabricated. Studies to define the effects of reaction variables on conversion to BTX liquids, gases and total conversion have been made. The results of these studies provided the basis for design of a 100 lb/hr riser cracker reactor PDU under Phase II of the project. The PDU is operational and two stages of partial combustion are used to raise coal and hydrogen to reaction temperature. The PDU results agreed with those from the BSR, but some oxidation of volatile products took place in the partial combustion sta ges lowering the yields as a

Project Cost: $1.5 million

*SAN ARDO COGENERATION PROJECT - Pacific Gas & Electric Co., Texaco Inc. PG&E and Texaco Inc., submitted a proposal to DOE, September 30, 1980, to prepare a feasibility study for a coal gasification/cogeneration plant to be located near San Ardo in the Salinas Valley, California. The study would evaluate the environmental and economic viability of gasifying 4,000 tons per day of bituminous coal into medium Btu synthesis gas for generating electricity and steam. The plant would generate 210,000 KW per day of electricity for PG&E customers and 1.5 million pounds of steam per hour for steam-flooding operations in Texaco's oil producing leases in the San Ardo field. The gasification facility would be based on the Texaco Coal Gasification Process. Foster Wheeler Engineering Co. has been selected by PG&E and Texaco as the architect/engineering firm for the study.

Project Cost: $9.7 million for the feasibility study. SASOL TWO (PROPRIETORY) LIMITED - Sasol Limited (Holding Company of the Group) Sasol Two is a commercial project based on the success of Sasol One, for the manufacture of mainly motor fuels, 287,000 TPY tar products, 100,000 TPY ammonia, and 75,000 TPY sulfur. The plant is situated on the eastern high veld of Transvaal. Estimated coal (low grade) consumption is 12 million tons per annum from the Bosjesspruit Colliery. The facilities include boiler house, Lurgi gasifiers, oxygen plant, Rectisol gas purification, gas reformers, and refinery. The hydrocarbon synthesis will use Sasol's Synthol process. Managing contractor is Fluor Engineers. Construction is completed and all units will be commissioned by the end of 1980. Production of first "crude" oil at Sasol Two started on March 18, 1980. Sasol has given Fluor Corporation the go-ahead to begin work on Sasol Three at an estimated cost of $3.8 billion. At the end of June 1980, less than 16 months after the decision had been taken to build Sasol Three. ohvsical construction on the site was annrniimatelv 73 nerrent rnmnletnd

Project Cost: $3 billion (including off sites and mine) S. K. GASIFICATION PROCESS-- Shell International Petroleum Co. and Krupp-Koppers GmbH Shell is undertaking a joint development with Krupp-Koppers of a pressurized entrained coal gasification process. A six TPD pilot plant has been in continuous operation at Shell's Amsterdam laboratory since December 1976. A number of different coals and petroleum cokes have been successfully gasified at 450 psi pressure. This pilot plant has now operated for over 4500 hours. A 150 TPD prototype plant has been constructed at the German Shell Hamburg/Harburg refinery. Since the start-up in November 1978, a number of successful runs have been completed. The longest run so far lasted for over 250 hours while gasifying bituminous coal with oxygen/steam at 300 psi pressure. The carbon conversion was over 99 percent and a crude gas was produced with a CO content of 1.5 percent vol. Planning is underway for a 1000 TPD coal gasification plant to be built at Shell Chemie's Moerdijk site with operation expected in late 1984. The coal gas from the plant will be used for environmentally acceptable high- efficiency electricity generation in a combined-cycle power station, which features both gas and steam turbines. Project Cost: Estimated at $150 million (excluding powerplant)

SLAGGING GASIFIER DEVELOPMENT-- DOE, and Grand Forks Energy Technology Center, Stearns-Roger, Inc. A slagging fixed-bed gasifier was designed and operated from 1958 to 1965 under the direction of the U.S. Bureau of Mines. The project has been reactivated and low-rank coals gasified with emphasis on operation parameters and quantification and characterization of organic effluents in wastewater. Concerns as to the type and character of effluents from caking coals were sufficient that the unit was redesigned. Modifications included dual hoppers and feed systems to provide a constant bed height, and a stirrer to break up agglomerates. Relocation of the modified gasifier into a permanent seven-story pilot plant was completed in October 1979. Tests using a North Dakota *New or Revised Project

4-92 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) Lignite aimed atgenerating wastewater for treatment testing was nearly finished by the end of FY80. Four tests of over twenty hours of slagging operation have been performed and as evidenced by gasifier temperaturesiZeffluent rate and quality, lined-out operation is reached after about eight hours of slagging. Operation at 300 psi, 6000 SCFH 02 and a 1:1 molar steam/O, ratio produced over 31,000 SCFH gas with a heatin value of 330 Btu/SCF at an as received coal feed rate of l,t25 lbs/hr or a throughput of better than 1,200 lbs/hr It g2. Successive tests will be made on bituminous coals, each with a greater degree of caking beginning next year after all modifications have been tested on lignite and sufficient lignitic wastewater samples have been acquired for effluent treatment studies. Project Cost: $3.35 million, FY81

SOLVENT REFINED COAL PILOT PLANT (SRC-0 -- DOE, International Coal Refining Company, (Air Products and Chemicals Inc./Wheelabrator-Frye Joint Venture), 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 ash content is reduced to a maximum of 0.16 percent; sulfur to a maximum of 0.96 percent. Plant capacity is 6 TPD. Data from the Wilsonville, and Ft. Lewis, Washington, SRC plants have been correlated, and seven 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 a new entity, the International Coal Refining Company (ICRC). Under terms of a cost sharing agreement, signed August 7, 1980, [CRC 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 has been optioned by the Kentucky Department of Energy. Products include clean solids and liquids with heating values approximately 16,000 Btu per pound. SRC li quids include heav y oil (650-850°F fraction oils), middle distillate (400-50°F oils) and nanhtFn (c

five design subcontractors:

Project Cost: $1.488 billion (Demonstration Plant Only) SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-11) - DOE and JVCO (Pittsburg & Midway Coal Mining Co. (P&M), subsidiary of Gulf Oil Corporation; Ruhrkohle AG/VEBA; Japan-SRC, Inc.) The SRC pilot plant at Ft. Lewis, Washington, has a capacity of 50 TPD of coal feed in the SRC I (solid product) mode or 35 TPD of coal feed in the SRC If (liquid product) mode. The SRC I mode produces a low ash/low sulfur fuel which is solid at ambient temperature. Dissolver conditions are 850°F under H 2 atmosphere and 1500 psig for SRC I and 2000 psig for SRC II. The process has been developed by P&M from bench-scale. The pilot plant was designed and constructed by Stearns-Roger and Rust Engineering, respectively, and has been operational since 1974. SRC II mode produces low sulfur liquid product, and has been tested using Kentucky 9 and 14, Illinois 6, and Pittsburgh seam (Powhaton No. 5 and Blacksville No. 2) coals. In the SRC II mode, stripped reactor effluent is recycled for feed coal slurrying, and ash, unreacted coal, and dissolved but non-distillable coal products are recovered as vacuum tower bottoms. Solid/liquid separation by filtration is eliminated. The Pilot Plant operated in the SRC I mode from April through August 1979 to evaluate the Lurnmus antisolvent de-ashing unit which was sucessfully commissioned in May 1979. Operation in the SRC II mode resumed in late October 1979, to evaluate demonstration plant design concepts and conditions. Under a separate contract with DOE, Gulf (P&M) has prepared a preliminary conceptual desfgn of a 6,000 TPD SRC II demonstration module being planned for construction near Morgantown, West Virginia. Gulf is now developing a detailed design. Badger Energy, Inc., has been awarded a subcontract to provide engineering services for the demonstration plant. On July 31, the contract that formally completed the cost sharing agreement between the U.S., West Germany, and Japan was signed at the White House. A joint venture company (JVCO) comprised of P&M, Ruhrkohle AG/VEBA of Germany, and a new entity in Japan to be called Japan-SRC, Inc., will be responsible for the performance of the contract. Project Cost: Fort Lewis Plant: $20 million (construction) $13 million per year (operation) $42 Million (current DOE contract) Demonstration Plant: $1.439 billion

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-93 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) 'SOUTHERN CALIFORNIA SYNTHETIC FUELS ENERGY SYSTEM - Texaco Inc., Southern California Edison Co., Pacific Lighting Corp., C.F. Braun Texaco, Mono Power Co. (a wholly-owned subsidiary of Southern California Edison Co.), Pacific Lighting Fuels Development Co. (a subsidiary of Pacific Lighting Corp.) and C.F. Braun & Co. submitted a proposal to DOE September 30, 1980, to prepare a feasibility study for a medium-Btu synthetic gas plant and related facilities in Lucerne Valley, San Bernardino County, California. The overall objective of the proposal is to evaluate the feasibility of and develop a plan for constructing and operating: (1) a coal mine and coal slurry plant at the icaiparowits coal field located in southern Utah; (2) a pipeline to transport the slurried coal from the mine to the gasification plant; (3) a 20,000 ton-a-day coal gasification plant in the Lucerne Valley utilizing the Texaco Coal Gasification Process; (4) a pipeline to transport the coal-derived synthetic gas from the gasification plant to the Los Angeles Basin. Project Cost: $4.1 million for the feasibility study.

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 near 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 is also conducting geotechnical investigations at three potential damsites for the off- stream storage reservoir. Tenneco commenced a one-year ambient air quality and weather monitoring program in the state-line area in 1979. The data is to be used in computer modeling studies addressing potential impacts on regional EPA Class I areas. Overall project timing is uncertain. Tenneco Coal Gasification Co., a subsidiary of Tenneco, Inc., filed its first annual Long-Range Plan under the Montana Major Facility Siting Act in April 1980. Plans were initiated for a project development study for the location of a possible 250 million MMSCF per day coal gasification plant to produce pipeline quality gas using Lurgi coal gasification technology. Project Cost: Undetermined

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 T/D of coal. It 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 1200 psi has 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 lID 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 demonstrated continuous operation for periods in excess of 300 hours. 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 for a confidential U.S. Chemical Company process to gasify coal to produce fuel gas for electric power generation. Other commercial applications using the Texaco Coal Gasification Process are described separately in the "Status Of Projects" under the following headings: Cool Water Coal Gasification Project, Medium Btu Gasification Project, Central Maine Power Company Project, TVA Ammonia From Coal Project, Chemicals From Coal Project, W. R. Grace Methanol From Coal Plant,

on Project Cost: West German Plant: $50 million

*New or Revised Projects

4-94 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.) TOSCOAL PROCESS DEVELOPMENT - TOSCO Corp. TOSCO has under development an atmospheric, low-temperature (800-970°F) coal pyrolysis system, TOSCOAL Process, at their 25 TPD pilot plant facilities located near Golden, CO. The TOSCOAL Process is an adaptation of TOSCO's 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 subbituminous and Illinois No. 6 bituminous. Status - Development is continuing with an active pilot plant program. Project Cost: Undetermined

TRI-GAS PROJECT (BCR Fluid Bed Gasifier) -- DOE and Bituminous Coal Research, Inc. A process development unit (PDU) is in operation at Bituminous Coat Research, Inc., Monroeville, Pennsylvania. The objective is to develop a fluid bed gasifier for production of low-Btu gas. The PDU has a capacity of 100 lb/hr. Each stage of the three-stage unit has been tested independently to obtain data necessary for coordinated three-stage operation. The unit has been operated successfully on a non-caking westerncoal and on a mildly-caking midwestern coal. Final tests are being run on an eastern coal. The project is scheduled to terminate October 31, 1980. Project Cost: $4.2 million TRI-STATE PROJECT -- Texas Eastern Corporation, Texas Gas Transmission Corporation. Planning continues by Texas Eastern Corporation and Texas Gas Transmission Corporation to build a plant using the Fischer-Tropsch synthesis process for coal liquefaction. The proposed plant, to be located in Henderson County, Kentucky, is expected to consume about 28,600 tons of high-sulfur coal per day to produce approximately 50,000 barrels per day equivalent of gasoline, diesel fuel, jet fuel, substitute natural gas and chemical feedstocks. Feasiblity studies for the plant, conducted by Texas Eastern and Sasol, Ltd., in cooperation with Fluor Corporation, were completed in April 1980. In July 1980, the project was selected by the DOE for Cooperative Agreement funding under the synthetic fuels commercialization program. Under the Agreement, DOE would provide a total of $24.3 million of an estimated $44.1 million, two-year work program designed to move the project to the point of a decision to proceed with construction. This work program will include a large-scale gasification test of Illinois Basin coal at a Sasol plant in South Africa; engineering design; capital and operating cost estimates; studies to determine optimum product slate; site specific environmental, health, safety and socio-economic impact studies, and negotiation of contracts for coal and other resource requirements. Contingent upon results of this course of work, construction could begin in 1983, providing jobs for up to 15,000 workers as well as contract work for local shops and businesses. About 2,400 employees would be required to operate the plant. Projected Cost: (Studies will provide final process design and product slate as well as the cost basis for evaluating a commercial project in the U.S. at the earliest possible time) TRW COAL GASIFICATION PROCESS - TRW, Inc. TRW is developing a low-Btu, low residence time entrained gasifier which uses a variable orifice injector based on rocket engine technology. The variable orifice allows for a six-to-one throttleability, with accompanying load following characteristics. A laboratory reactor 1.5 feet in diameter and three feet long partially combusts pulverized coal by tangential air injection. Reaction temperature is about 2,500°F at low pressures. Subbituminous and bituminous coals have been tested. Project Cost: Undetermined 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 will be completed in mid-1980, after which time a three-year period of demonstration is planned. Capital costs will total $43.2 million. Brown and Root, of Houston has been awarded a $25.6 million contract for the construction of the eight ton per hour coal gasifier. The air separation plant is being built by Air Products and Chemicals, Inc. at a cost of $5 million. The remainder of the work will 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. Status:• The gasifier was dedicated and started up at the TVA's 13th Demonstration of Fertilizer

Project Cost: $46 million

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-95 STATUS OF SYNFIJELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

COAL CONVERSION PROJECTS (Cont.) TVA MEDIUM BTU COAL GASIFICATION DEMONSTRATION PLANT -Tennessee Valley Authority (TVA) The Tennessee Valley Authority is planning a coal gasification plant capable of processing up to 20,000 tons of coal feed-stock per day and producing medium-Btu gas for use in dispersed industrial and utility applications in the Tennessee Valley region. The plant will consist of several parallel trains, each capable of producing medium - Btu gas from moderate to highly caking eastern U.S. coals. It will be a grass roots faciliy consisting of coal receiving and handling, gasification, gas cleanup, air separation systems, and all necessary ancillary facilities. Plans call for site preparation to begin in the spring of 1981 with operation of the first gasifier module scheduled to begin in 1985. Bechtel National, C. Inc., 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 Btu- gas. The five processes are: 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. Congress approved $ss million in 1980 supplemental appropriations which will be used primarily for a Phase II effort including detailed design for two gasification processes (Texaco and Koppers-Totzek), pilot plant coal tests, license fees, and other items. As stated in the draft Environmental Imoact Statement released on Au gust 1. 1980. TVA chose Texaco and ICoDoers-

Project Cost: First Module: $1 billion

TWO-STAGE ENTRAINED GASIFICATION SYSTEM -- DOE, Electric Power Research Institute, and Combustion Engineering, Inc. This is a six-year, three-phase program to demonstrate the CE two-stage entrainment gasification system to produce a low-Btu gas from coal. A 5 TPH pilot plant has been designed and constructed by CE at Windsor, Connecticut. The two-stage unit includes a lower chamber which combusts char and coal under slaggig conditions, and an upper air deficient reductor section in which the product gas with a heating value of 120/Btu/ft. is produced. The combustor operates at 3,000°F and the reductor at 1,800°F. The gasifier operates at atmospheric pressure. Determination of investment and operating costs for a commercial scale plant will follow under the final project phase. The test facility was dedicated 10177. Status: To date, the facility has produced more than two billion cubic feet of gas during more than 3,000 hours of gasmaking operation on Pittsburgh seam coal. The tenth gasmaking run since inception of testing is in progress. Tests for the next few months will continue to use Pittsburgh seam coal. Tests of four other coals are scheduled to begin in fiscal year 1980, and revisions are underway to convert the plant for enrichment of gasifier air with oxygen. Combustion Engineering in conjunction with Gulf States Utilities was awarded a contract for $5 million for a preliminar y design of a demonstration plant. If built, the plant would be

The estimated $50 million project cost covers all work through four coal tests involving air and oxygen-enriched air blown operation.

Project Cost: $50 million TWO-STAGE LIQUEFACTION - DOE and Cities Service/Lumrnus 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 a two-stage liquefaction process. No effect of solvent boiling range (500- 850°F to 740 - 850°F) was noted for 850°F+ conversion at a 780°F operating temperature. The denitrogenation was improved with a heavier boiling solvent. The thermal effect upon 850°F+ 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°F+ 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-I coal extracts obtained from the Pyro and Lafayette mines has essentially no effect on the LC-Fining hydroprocessing. In the two-stage liquefaction process, the non-catalytic short contact time coal dissolution and C- E Lummus antisolvent deashing have been successfully integrated and solvent is being hydrotreated in the LC-Fining unit. Process solvent is being used in the coal pasting step of feedstock preparation for the SCT operation. The catalyst age in the LC-Finer is estimated to be 1020 pounds 850°F+ SRC-I coal extract per pound of catalyst. Project Cost: $7.3 million

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFIJELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) COAL CONVERSION PROJECTS (Cont.)

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 l80-Btu 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. Elkol, Wyoming coal was used initially and other coals from Wyoming and Colorado have been tested. Orr-Schelen-Mayeron and Assoc., Minneapolis, MN, provided architectural services for the support facilities, Foster Wheeler designed the gasification section. The Stoic gasifier was started up during October 1978. The unit was shut down in November 1978 for equipment modifications. The gasifier was operated for two weeks xn February 1979 to check equipment modifications. During this run, Big Horn, Montana coal was used. The FW-Stoic Gasifier has experienced mechanical problems during startup which have now been overcome. The plant has had several periods of extended operation. The gasifier has successfully gasified western subbituminous coal. Altogether five different 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. Project Cost: $5.5 million (50150 DOE/participant funding)

WESTINGHOUSE ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERATION --DOE; Westing- house Electric Corporation, Advanced Coal Conversion Department Westinghouse has been operating since 1975 at Waltz Mill, PA, a 15 TPD process development unit for perfecting a single-stage gasification system. System employs fluidized-bed gasification, combustion and dry ash agglomeration within a single vessel. Operating temperature is 1,700-2,000°F. Various grades of coal ranging from Wyoming sub- C bituminous, Texas Lignite, Western Kentucky and Indiana coals to high-caking Pittsburgh seam have been successfully gasified after direct injection to the single reactor. The PDU has produced both low-Btu gas with air injection and medium-Btu with oxygen injection at 225 psig. Tests with an integrated two stage system consisting of a devolatilizer and a gasifier have also been completed. Currently the test program is being directed toward optimizing operation of the PDU with air and oxygen at 225 psig and in the evaluation of desulfurization, heat recovery, particulate removal, and combustion components. A 3-meter diameter cold flow scale-up model has been constructed and will be operated in 1980 and 1981 to provide a data base for scale-up of the gasifier to commercial scale of 40 TPH.

Project Cost: $42.2 million

WYCOALGAS, INC., COAL CONVERSION PROJECT (formerly Panhandle Eastern, Wyoming Project) - Panhandle Eastern and Peabody Coal Co. A 150 MMCFD capacity commercial project using Lurgi and Texaco gasification and methanation is being developed and an expansion to 300 MMCFD is proposed. The plant will be 16 miles northeast of Douglas, Wyoming. Peabody has dedicated a Campbell County coal supply of over 500 MM tons of coal that will be delivered to the plant by railroad. The state has issued a 1974 appropriation to take water from the North Platte and a permit to construct a 26,000 AF reservoir. Panhandle has rehabilitated the dam on another 26,000 AF reservoir and is entitled to one quarter of the volume and water rights. A water well based supply will back up these systems. Panhandle was selected for negotiation of a cooperative agreement by DOE on July 9, 1980 for funding of the work--process engineering, coal tests, environmental and socio-economic investigations, permit applications, etc.--required before the project's construction phase can start. Contractors are Bechtel, Lurgi, SASOL, Woodward Clyde, Mountain West and others.

Project Cost: Estimated at $1 billion

ZINC HALIDE HYDROCRACKING PROCESS DEVELOPMENT -- Shell Development Co., and Conoco Coal Development Company This is a bench-scale project for producing liquid products from coal. Conoco Coal Development Research Division at Library, PA is to test the potential application of a zinc-chloride hydrocracking process to produce distillate fuel and gasoline from coal or coal liquids. Early work involved reaction of Colstrip subbituminous coal in a two pound- per-hour scale unit. Initial runs in 1978 and 1979 used SRC from Ft. Lewis Plant in a PDU scale reactor at 100 lbs./hr, DOE has decided to stop funding the project. Conoco remains enthusiastic because of the unusually high removal of N,O,S, and high gasoline yield. A 2-year private bench-scale program is being organized. Project Cost: $11 million (90 percent DOE, 5 percent Shell, 5 percent Conoco)

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-97 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980)

*.i**,.*wwi*i***n*,*pe.,...,i,.**wn-n-UNDERGROUND COAL CONVERSION PROJECTS n-**********.*****w**

UNDERGROUND COAL GASIFICATION -- Extractive Fuels, Inc. Extractive Fuels, Inc. of Casper, Wyoming has submitted a proposal to the Department of Energy for an in situ pilot coal gasification project. The project would be conducted on Extractive Fuels leases in the Powder River region. Plant would produce 1.5 MM SCFD of SNG. World Energy, Inc. would be prime contractor for project. Status -DOE denied the grant and private funding is being sought for the project. Project Cost: About $78 million $67.4 million DOE $10.6 million EPA UNDERGROUND COAL GASIFICATION -- Public Service of New Mexico, University of New Mexico The Public Service of New Mexico (PNM) has evaluated an underground coal gasification (UCG) site near the San Juan Power Generating Station. Location of the UCG site is Sec. 36, T30N, RISW. Product gas would be used in the power plant as boiler fuel, or as reducing gas to product HS for Claus plant. Target zone is a IS to 17 foot thick seam of subbituminous coal approximately 500 feet deep. teological, environmental, and hydrological testing have been completed for the site. Environmental evaluation of the site was being funded by Environmental Protection Agency, the Office of Water Research and Technology, and the State of New Mexico. The first stage of the project was funded by PNM and included site characterization, preliminary geotechnical assessment, and formation pre-burn testing. During June and July of 1979, personnel of Los Alamos Scientific Laboratories performed groundwater drawdown testing to assess the impact of the groundwater regime on UCG development. During August 1979, personnel of Sandia Laboratories conducted injection and tracer analyses to locate flow within the coal seam. The 1979 studies were funded by the Department of Energy. Test results obtained from the two stage project indicate that site conditions in the San Juan Basin area are amenable to the development of UCG technology. Project Cost: Undetermined UNDERGROUND COAL GASIFICATION -- University of Texas (Austin), Basic Resources, Conoco, Mobil, ARCO, duPont, Lone Star Gas, Exxon, DOE, EPA, Texas Mining and Mineral Resources Research Institute, and HEW 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 goal 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 selection properties (oxidation, gasification, pyrolysis, sulfur emissions), rock mechanical properties of the overburden, and biological characteristics of wastewater (surface and subsurface). Computer models for predicting gas composition, sweep efficiency, subsidence, and process economics are under development. Characterization of organic and inorganic pollutants for lignite gasification is being performed under a cooperative agreement with EPA.

Project Cost: $220,000/Year UNDERGROUND COAL GASIFICATION, CANADA -- Alberta Research Council, Four government agencies, II 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 Forestburg project involved reverse combustion linkage followed by forward gasification of two pairs of wells at opposite ends of a 9 m x IS 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. A new 5-year field test is planned but details are still being negotiated. Project Cost: $10 million for 5-year program

4-98 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

UNDERGROUND COAL GASIFICATION, MANNA 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 Manna, 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 Manna 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). Manna III, 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 original wells over- rode coal seam. Two new offset wells were drilled to reestablish linkage at bottom of seam. Subsequent gasification test indicates coal over-ride again. Manna IV was re-injected on April 20, 1979 using a linear pattern of four wells spaced 37.5 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 II, the link to the third well was complete and at least two links were seen, both low in the coat seam. During the test, gas production of 4500 scffmin 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 Manna II, phases 2 and 3 site will begin in October 1980. Cores from both Manna II and Moe Creek 3 will be 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 $3.2 million, FY 1979

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, Moe Creek No. I, was conducted during October 1976 at a site 25 miles southwest of Gillette, Wyoming. Gasification at Moe 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 subbitumionous coal at a depth of 165 feet from the surface. During the 47 day run 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 H 2, 5 percent CH 41 11 percent CO, and 44 percent CO 2. 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 eynerimenL

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

UNDERGROUND COAL GASIFICATION, PRICETOWN PROJECT -- DOE, Morgantown Energy Technology Center, Consolidation Coal Company The project is 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

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-99 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) UNDERGROUND COAL CONVERSION PROJECTS (Cont.) 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. Luring 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 350 tons consumed per day at 25-30 tons during gasification. Test operations were shut down on October 19, 1979, and post-test coal seam and environmental monitoring initiated.

Project Cost: $1.1 million, FY 1977 $3.2 million, FY 1978 $0.9 million, FY 1979

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 110 foot-thick coat 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. This was followed by 60 days of forward combustion at air flow rates up to maximum capacity of 4,000 SCFM. Average gas quality exceeded 200 Btu/SCF. Combustion was completed November 20, 1978. Since that time, ARCO has been reviewing the results of this test and further assessing the economic viability of the technology. The review was completed early in 1980, and a decision was made to accelerate the program. The target of having a commercial module or plant in operation before 1990 was adopted.

Project Cost: $30- $50 million 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 Il, T2IN, R89W. This field test was clearly a success in that all of the test objectives were met. 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 180 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/02 test yielded 230-280 Btu/SCF gas at rates ranging between 2000-4000 SCFM. Current activities include post-burn coring and analysis of the first test as well as detailed design and statement of work for the second experiment in the series planned for FY 1982. Project Cost: $13.5 million 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 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, has been selected for DOE's first programatic activity in the new Underground Coal Gasfication 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.

4-100 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 STATUS OF SYNFUELS PROJECTS/COAL (Underlining Denotes Changes Since September 1980) UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

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 2round. air, water, and arrhenlnc,it-aI

Project Cost: $850,000

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 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/scf 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/scl 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. Plans call for gasification of about 2,000 tons of lignite during the 1980 test.

Project Cost: $250,000/year

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-101 RECENT COAL PUBLICATIONS

Adlboch, W. and K.A. Theis, "The Rheinbraun High Temperature Winkler Process," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Aiman, W.R.,"Solar Coal Gasification: Plant Design and Economics," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980. Asmussen, D., "Trends in Peat Management and Utilization in the Upper Great Lakes Region," presented at the SME-AIME Fall Meeting, Minneapolis, Minnesota, October, 1980. Beer, ).M., "Reduction of NO Emission by Staged Combustion of Coal-Derived Liquid Fuels," presented at the 73rd Annual Meeting of the AIChE, thicago, Illinois, November, 1980. Broeker, R., "Two-Stage Atmospheric Coal Gasifier at the University of Minnesota," presented at the 7th Annual UMR- DNR Conference on Energy, University of Missouri, Rolla, October 1980.

Bombaugh, K.)., et.al ., "An Environmentally Based Evaluation of the Multimedia Discharges From the Lurgi Coal Gasification System at Kosovo," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Bradt, R., "Fracture of Refractory Concretes," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980. "Chemicals From Coal: Planning for the 1990's and Beyond," presented in Process Economics International, Vol. 1(2) page 12, Winter 1979/80. Cheng, W.B., "Entropies of Coals and Reference States in Coal Gasification Availability Analysis," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980. "Coal Processing Technology, Vol. VI," a Chemical Engineering Progress technical manual published by the American Institute of Chemical Engineers, 1980. Collins, R.V. and K.W. Lee, "Comparison of Coal Conversion Wastewaters," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Cornils, R. and R. Specks, "Experience With the Texaco Process for Coal Dust Pressure Gasification," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Cotter, J.E., et al., "Initial Effort on a Pollution Control Guidance Document for Direct Liquefaction," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September 1980. Cowles, 3.0., et al., "Utilization of Synthetic Fuels: An Environmental Perspctive," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September 1980. Crawford, K. and W.J. Rhodes, "Development of a Pollution Control Guidance Document for Indirect Liquefaction," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V., St. Louis, Missouri, September 1980. Culver, C., et at., "Inactivation/Property Management of Agglomerating Burner (Coal Gasification) PDU," report FE- 3023-7 by Battelle Columbus Laboratories for the U.S. DOE, July, 1980. Cypres, R., and P. Bredael, "Production of Light Aromatics from Coal Hydrogenates," Fuel Processing Technology, August, 1980, pp.297-311. Daugherty, D.P., "The Conversion of Undesirable Aromatic and Sulfur-Containing Compounds from Coal Gasification," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

Dickerson, L.5., "Laboratory Studies Supporting Underground Coal Gasification--A Chemical Engineering Technicians Rote," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980. Eccles, R.M. and G.R. DeVaux, "Current Status of H-Coal Commercialization," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

4.102 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT PUBLICATIONS - COAL

Enoch, H.G., "Environmental Consequences of a Coal Conversion Industry in Western Kentucky," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980. Epperly, W.R., et.al., "Exxon Donor Solvent Coal Liquefaction Process: Development Program Status," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Fallon, P.1., et al,, "The Flash Pyrolysis of Lignite and Sub-bituminous Coals to Both Liquid and Gaseous Hydrocarbon Products," Fuel Processing Technology, August, 1980, pp.1 55-168. Finson, M.L..A Computer Model for Fluidized Bed Gasification of Coal," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

Fussman, G. and M. Rossbach, "The Saarberg/Otto Gasifier," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Garg, D., et al., "Selectivity Improvement in the Solvent Refined Coal Process I. Detailed First-Stage Reaction Studies: Coal-Mineral Catalysis," Fuel Processing Technology, August, 1980, pp.245-261.

Garg, D., et al., 'Selectivity Improvement in the Solvent Refined Coal Process 2. Detailed Second-Stage Reaction Studies: Hydrotreating of Coal Liquids," Fuel Processing Technology, August, 1980, pp.263-284.

Grassling, B., "World Coal Resources," published by The Financial Times Business Information Ltd., Bracken House, 10 Cannon Street, London EC4P 4BY, 1980, price: $155.00.

Green, D.A., "Ranking of Potential Pollutants From Coal Gasification Processes," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980.

Gurski, P. and G. Hines, "Kilngas for Utility Applications," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

*Harris, L.A. et al., "Coal Liquefaction: Recent Findings in Occupational Safety and Health," a special technical report by the National Institute for Occupational Safety and Health, Rockville, Maryland, 20857, June 1980, 14 pages.

Harris, R.K., "Coal and Oil Shale: Expanded Use, Expanded Environmental Risk," presented at the Conference on Synfuels and the Environment sponsored by the Energy Bureau, Inc., and held in Washington, D.C., on October 16-18, 1980. Hatate, Y., "A Mathematical Model for Coal Liquefaction in the Solvent Refined Coal Process," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

*Hefner, W.J. and L.A. Caristrom, "Gas Turbines for Future Coal-Based Power Generation Systems," presented at EPRI's Conference on Synthetic Fuels, San Francisco, October 1980.

Hill, V., "Review of Corrosion and Erosion Research in Coal Gasification Atmospheres," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980.

Hiller, H. and O.L. Garkisch, "Convert Coal Now," in Hydrocarbon Processing, Vol. 9, September, 1980, pp. 238-242. *Holmgren, J.D., et.al ., "The Westinghouse Gasification Program," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Holt, N. and J. McDaniel, "Environmental Test Results From Coal Gasification Pilot Plants," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980.

Hossain, S.M., et al., "Upgrading Coal Products Can Affect Environment," in Hydrocarbon Proc essi ng , October, 1980 issue, pp .79-86.

"Inventory of Coal Utilization Technology," staff article in Coal Mining and Processing, October, 1980, pp.57-60.

Iwata, K., et al., "Average Chemical Structures of Mild Hydrogenolysis Products of Coals," Fuel Processing Technology, August, 1980, pp.221-230.

Jackson, D.M., "SRC-11 Demonstration Project," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. *Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-103 RECENT PUBLICATIONS - COAL Josephson, 3., "Toxic By-Products of Coal Conversion," in Environmental Science and Technology, November 1980, pp. 1283-1286. Jones, D.G., et al., "Catalytic Hydrogenation of Liddell Bituminous Coal Effects of Process Variables on Coal Dissolution in Batch Autoclaves," Fuel Processing Technology, August, 1980, pp.169-180. Kennedy, C., "Review of Refractory Behavior in Slagging Applications," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980. Keyser, 3., "Corrosion in Coal Liquefaction Systems," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980. Klein, M.T., "Model Pathways in Lignite Pyrolysis," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980. Klusmann, A., et.al ., "The Coal Hydrogenation Plant at Bottrop," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Knust, R.B., "The CE Coal Gasification Process: Commercial Outlook for the 1980's," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. "Kosovo Phase II Source Test Data," Rudarski Institut, REMHK Kosovo," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. •Krickenberger, K.R. and S.H. Lubore, "Feasibility of Utilizing Carbon Dioxide Produced During the High-BTU Coal Gasification Process for Enhanced Oil Recovery," a report to the American Gas Association by The MITRE Company, 1980, 33 pages. *Krurnholtz, "Water Assessment for Monongahela Synfuel Plant," June 6, 1980. Lenz, H. and D. Bocker, "Rheinbraun--Liquefaction of Brown Coal," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Levy, A., "Erosion in Coal Liquefaction Systems," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization," Gaithersburg, Maryland, October, 1980.

Lin, C., et.al ., "Data Bank for Synthetic Fuels-Part 2," presented in International Edition Hydrocarbon Processing, Vol. 59(8), page 117, August, 1980. Lohmann, C. and J. Langhoff, "The Improved Lurgi Fixed Bed Pressure Gasification by the Ruhr 100 Gasifier," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Luthy, R.G.,"Treatment and Reuse of Coal Conversion Wastewaters," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Magee, R.A., et.al., "COS-H, Relationships in Process Producing Low/Medium BTU Gas," presented at EPA's Symposium on Environmental Aspects of 'Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Mangold, E.C., "Design of Environmental Control Systems for Coal Synthetic Fuel Plants," presented at Manhattan College's 7th National Conferencelon Energy and the Environment, Phoenix, Arizona, November 1980. Martin, G.B. and W.S. Lanier, "Combustion Technologies for Controlling the Environmental Impact of Synfuels Utilization," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Mason, D. and J.G. Patel, "Chemistry of Ash Agglomeration in the U-Gas Process," Fuel Processing Technology, August, 1980, pp.181-206. Mathur, V.K., "An Economic Study of Direct and Indirect Solar Coal Gasification," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980. May, V.T., et.al., "Dow Coal Liquefaction Process Update," presented at Electric Power Research Institute's Conference - on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

*Reviewed in this issue.

4-104 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT PUBLICATIONS - COAL

Morris, S.M. and W.A. Wilson, "SRC-I Coal Refining Demonstration Plant," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Murphy, L., "Alaska's Coal Leasing Program," presented at Focus on Alaska's Coal , a 3-day conference sponsored by the University of Alaska, held at Fairbanks, October 21-23, 1980.

National Coal Association, "Coal Synfuel Facility Survey," August, 1980, price: $25.00.

Nishida, N., et al., "Qualitative and Quantitative Assessment of Reaction Models of Coal Hydrogenation," Fuel Processing Technology, August, 1980, pp.231-244.

Olness, D.U., "LLL In Situ Coal Gasification Project: Quarterly Progress Report, January Through March 1980," Lawrence Livermore Laboratory, report ?/UCRL-50026-80-1, May, 1980.

Passman, R., "Projects Status Report: Synfuels From Coal," presented at the Synfuels Industry Development Seminar of Government Institutes, Inc., held at Washington, D.C., on November 6-7, 1980.

Patterson, R., "Development of the C-E Medium-BTU Gasifier," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980.

Phillip, C.U., and R.G. Anthony, "Dissolution of Wet Texas Lignite in Tetralin," Fuel Processing Technology, August, 1980, pp.285-295.

Pollina, R.J. and R.R. Smyth, "Behavior of Refractories in High Temperature Coal Slag Environments," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980.

Pruce, Leslie M., "Methanol Holds Promise for Gas Turbines," Power, Vol. 124(9), page 105, September, 1980. Raymon, N., "Corrosion in Catalytic Gasification Atmospheres," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980.

Ritchie, R., "Fatigue in Coal Conversion Steels," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980. - Rudolph, P.F.H., et.al ., "Lurgi Coal Gasification," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Rundell, D.N., "Application of a Bhatia-Epstein Model to the H-Coal Fluidized Bed Reactor," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

Sanders, R., "Coal Resources of Alaska," presented at Focus on Alaska's Coal, a 3-day conference sponsored by the University of Alaska, held at Fairbanks, October 21-23, 1980.

'Sharman, R.B. and J.E. Scott, "The British Gas Lurgi Stagging Gasifier," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Schlinger, W., "Development of the Texaco Gasifier," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980.

Scott, F.E.,"Along the Road to a Synfuels Industry," Coal Mining and Processing, October, 1980, pp.49-57. - "Search for Energy Unearths Peat," in Chemical Engineering, November 3, 1980, pp.35-39.

Sheieh, J.H., "Multiobjective Optimal Synthesis of Methanation Process," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

*Siegart, W.R., "Texaco Coal Gasification Technology,' presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Singh, S.P., "Thermodynamic Availability Analysis of Coal Gasification Processes," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

Smyth, 3., "Creep of Refractory Concretes," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization," Gaithersburg, Maryland, October, 1980. *Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-105 RECENT PUBLICATIONS - COAL Sparacino, Charles M. and Douglas J. Minick, "Determination of Phenolics in Coal Gasifier Condensate by High- Performance Liquid Chromatography with Low-Wave Length Ultraviolet Detection," Environmental Science & Te- chnology, Vol.76(7), Page 880, July, 1980. Sylvestri, A.)., "Status of the Mobil Methanol-to-Gasoline Process," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Thomas, W.C., etal., 'pollution Control Guidance Document for Low Btu Coal Gasification Systems: Background Studies," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Todd, 3., "Development of Low-Alloy Steels for Coal Conversion Pressure Vessels," presented at the Fifth Annual Conference on Materials for Coal Conversion and Utilization, Gaithersburg, Maryland, October, 1980. *U.S. Bureau of Land Management, "Kaiparowits Coal Development and Transportation Study," a final report to ELM by Environmental Research and Technology, Inc., August, 1980. *U.S. Department of Energy, "Aspects of Commercializing Coal-Derived Methanol Fuels in the United States 1985 to 2000," Vol. 1, Fossil Energy, March 1980, report number FE-2416-44. U.S. Department of Energy, "Engineering Test Facility Conceptual Design," Final Technical Report, Fossil Energy, February, 1980, report number DOE/FEI26I4-3. U.S. Department of Energy, "Homogeneous Catalytic Hydrocracking Processes for Conversion of Coal to Liquid Fuels Basic and Exploratory Research," Final Report, July 30, 1980, report number FE-2202-52. U.S. Department of Energy, "Potential Markets for High-Btu Gas from Coal," Fossil Energy, April 1980, report number DOE/RA/02625-2. U.S. Department of Energy, "Production of Methanol and Methanol-Related Fuels from Coal," May, 1980, Oak Ridge, Tennessee, report number ORNL-5564. U.S. Department of Energy, "Stability of Coal-Derived Particles in Organic Media," August, 1980, Oak Ridge, Tennessee, report number ORNL-5631. U.S. Department of Energy, "Technical and Economic Feasibility of Alternative Fuel Use in Process Heaters and Small Boilers," February, 1980, report number DOE/EIA-10547-01. *U.S. General Accounting Office, "A Shortfall in Leasing Coal From Federal Lands: What Effect on National Energy Goals?" a report (EMO-80-87) to Congress by the Comptroller General, August, 1980. *U.S. General Accounting Office, "Liquefying Coal for Future Energy Needs," a report (EMO-80-84) to Congress by the Comptroller General, August, 1980. Volkel, H., "The Application of Shell-Koppers Coal Gasification Process in Power Generation," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. Wadden, R.A., "Potential Health Problems from Coal Conversion Technologies," presented at Manhattan College's 7th National Conference on Energy and the Environment, Phoenix, Arizona, November 1980.

Walter, F.B., et.al ., "Cool Water Coal Gasification Program: A Demonstration of Gasification Combined Cycle Technology," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980. *Weinrejch, G., "Technical and Environmental Considerations Underlying the Great Plains Project," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Williamson, P.C.," The TVA Ammonia From Coal Project," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Witmer, F.E., "Environmental Control Options for Synfuel Processes," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980.

*Reviewed in this issue.

4-106 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 RECENT PUBLICATIONS - COAL

Wurfel, H., "Saarberg Coal Liquefaction Developments," presented at Electric Power Research Institute's Conference on Synthetic Fuels: Status and Directions, San Francisco, October, 1980.

Yee, ICY .,"Characterization of Coal Gasification Ash Leachates Using the RCRA Extraction Procedure," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. Young, R.J., "Occupational Health Considerations for the Emerging Coal Conversion Industry," presented at the 73rd Annual Meeting of the AIChE, Chicago, Illinois, November, 1980.

Zee, C.A., et.al., "Modderfontein Koppers-Totzek Source Test Results," presented at EPA's Symposium on Environmental Aspects of Fuel Conversion Technology, V, St. Louis, Missouri, September, 1980. COAL - PATENTS

Coal Industry (Patents) Limited, M.J. Flinn, et al, - Inventors, U.S. Patent 4,218,303, August 19, 1980, "Coal Pyrolysis." Hydropyrolysis of coal can be done as a two stage process, offering good yields of benzene. The first stage is carbonization of coal in the presence of hydrogen or reactive gas at elevated pressure. The volatile products, without cooling or condensing, are then subjected to cracking at a temperature above the carbonization temperature, in the absence of catalyst, in the presence of hydrogen or reactive gas. The char remaining is reactive and can be gasified. The process is easier to control and offers many advantages compared to prior proposed single stage hydropyrolysis. Cogas Development Company, R.T.- Eddinger and L.D. Friedman - Inventors, U.S. Patent 4,213,826, July 22, 1980, "Fluidized Coal Carbonization." In the multi-stage fluidized carbonization of coal to produce oil, gas and char, oil containing vapors from the first stage are used as the fluidizing gas to dry the incoming coal feed. The oil vapor pressure of the fluidizing gas is maintained at a value under 10 mm. to prevent oil condensation in the fluidized drying vessel. The technique makes possible the recovery of sensible heat from the first stage overheads.

Exxon Research and Engineering Company, A.L. Saxton - Inventor, U.S. Patent 4,213,848, July 22, 1980, "Fluid-Coking and Gasification Process." The heat requirements of a fluid coking zone are provided by introducing a hot vaporous hydrocarbon stream into the coking zone instead of the conventional hot coke stream. The fluid coking process may be integrated with a coke gasification process.

du Pont, Anthony A. - Inventor, U.S. Patent 4,212, 652, July 15, 1980 9 "Apparatus and System for Producing Coal Gas." Pulverized coal is introduced into a rising stream of steam in a central reaction column of a retort to constitute a fluidized or entrained bed. The coal reacts with the steam to form a gas consisting of hydrogen, carbon monoxide, carbon dioxide, nitrogen, methane and higher hydrocarbons. The retort is constructed so that product gas and air may be burned in an annular chamber surrounding the central reaction column to produce hot flue gas. The hot flue gas is used to drive a turbine which in turn, drives a compressor which introduces compressed air into the annular chamber. Steam tubes may be disposed in the annular space so that the steam introduced to the central reaction chamber may be super-heated by the hot flue gas.

Energy Modification, Inc., W.K.T. Gleim - Inventor, U.S. Patent 4,211, 633, July 8, 1980, "Separation of Asphaltic Materials from Heptane Soluble Components in Liquified Solid Hydrocarbonaceous Extracts." A more efficient separation of asphaltic materials from the heptane soluble components in liquified coal and other liquified solid hydrocarbonaceous materials is accomplished by using a natural gasoline fraction, boiling in the range of from 200° - 400°F, as a solvent extraction agent and then effecting a centrifugal separation at elevated temperatures and pressures. The resulting separated asphaltic materials will have far less heptane soluble material than the heretofore used procedures which involved the settling out of the ashphaltenes in huge settling tanks.

Gulf Research and Development Company, N.L. Carr, et al., - Inventors, U.S. Patent 4,211, 631, July 8, 1980, "Coal Liquefaction Process Employing Multiple Recycle Streams." In a coupled coal solvent liquefaction-gasification system wherein a recycle mineral residue-containing slurry is mixed with the raw coal feed slurry for the liquefaction zone, the resulting feed slurry is under a pumpability total solids level constraint. Where a coupled system is operating under such a total solids level constraint for the feed slurry, any increase in the mineral residue recycle rate relative to the coal feed rate advantageously provides a catalytic activity and selectivity advantage in favor of liquid coal product at the expense of higher and lower boiling products.

Hydrocarbon Research, Inc., E.S. Johnson - Inventor, U.S. Patent 4,217,112, August 12, 1980, "Production of Fuel Gas by Liquid Phase Hydrogenation of Coal." The thermal hydrogenation of solid coal without added catalyst produces hydrocarbon gases in the methane to propane range as the principal product, plus substantial yields of synthetic petroleum-like hydrocarbon liquids. The C 4-400°F naphtha liquid fraction is steam reformed to produce hydrogen, while heavier distillate liquid fractions are used as fuel to operate the steam reformer and for other process heat requirements, so that all of the hydrogen required for the coal hydrogenation reaction is produced from portions of the liquid products.

CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1980 4-107 COAL - PATENTS Hydrocarbon Research, Inc., M.D. Chervenak - Inventor, U.S. Patent 4,217,201, August • 12, 1980, "Integrated Coal Cleaning, Liquefaction, and Gasification Process." Coal is finely ground and cleaned so as to preferentially remove denser ash-containing particles along with some coal. The resulting cleaned coal portion is gasified to produce a synthesis gas, the ash is removed from the gasifier, usually as slag, and the synthesis gas is shift converted with steam and purified to produce the high purity hydrogen needed in the coal hydrogenation system. This overall process increases the utilization of as-mined coal, reduces the problems associated with ash in the liquefaction-hydrogenation system, and permits a desirable simplification of a liquids-solids separation step otherwise required in the coal hydrogenation system. Lummus Company, A.A. Simone - Inventor, U.S. Patent 4,216,074, August 5, 1980, "Dual Delayed Coking Liquefaction Product." Coal, which is liquefied in the presence of a pasting solvent, is separated into an ash-free and an ash-containing coal liquefaction product. Each of such products is delayed coked in separate zones with the vapors from such zones being introduced into a common combination coker-fractionator to recover ash-containing and ash-free coking recycle, pasting solvent for the liquefaciton and lighter products. The process is particularly applicable to coal liquefaction products produced from high ash containing coals.

McDowell-Wellman Company, T.E. Ban, et al., , . Inventors, U.S. Patent 4,220,454, September 2, 1980, "Process for Gasifying Pelletized Carbonaceous Fuels." A process is disclosed for gasifying pelletized coal to produce a !ow-Btu gas containing large amounts of hydrogen and carbon monoxide. The process is carried out on a circular traveling grate machine on a continuous basis. A horizontally moving, quiescent, gas-permeable bed of coal is formed by depositing at least one layer of a sized recycle charge of coal and at least one layer of fresh coal. To initiate an oxidizing reaction zone, the surface of one of the layers is ignited and the zone travels as a wave downwardly into the layer and upwardly into any superposed layer. Air and steam or air and carbon dioxide are either updraf ted or downdraf ted through the bed to control combustion. The coal is reduced in zones ahead of the advancing zone or zones of oxidation, and the reactions are terminated before the oxidation zone reaches both outermost surfaces of the bed to minimize the formation of carbon dioxide. lJnreacted coal is separated from fine ash and is used as the recycle feed. Mobil Oil Corporation, N.Y., Chen - Inventor, U.S. Patent 4,211,635, July 3, 1980, "Catalytic Conversion of Hydro- carbons." Distillate petroliferous stocks such as neutral lubricating stocks and distillate fuels are hydroprocessed for dewaxing and/or removal of sulfur, nitrogen and metals under hydrogen pressure in a downflow reactor packed with a catalyst suited to the desired conversions. Lighter portions of the charge are introduced to respectively lower levels of the catalyst bed, whereby product withdrawn from the bottom of the reactor is reconstituted distillate of which lighter portions have received milder treatment. Societe Francaise des Products pour Catalyse, C. Marcilly - Inventor, U.S. Patent 4,217,205, August I?, 1980, "Catalysts for Hydrocarbon Conversion." Catalysts, particularly useful in catalytic reforming and for producing highly pure aromatic hydrocarbons, comprising an alumina carrier and containing (expressed in proportion of the weight of the alumina carrier):

0.005 to 1 percent of platinum 0.01 to 4 percent of gallium, indium or thallium 0.01 to 2 percent of tungsten, and 0.1 to 10 percent of halogen. Texaco Inc., J.T. Nolan, Jr., - Inventor, U.S. Patent 4,218,222, August 19, 1980, "Method of Charging Solids Into a Coal Gasification Reactor." An extruder for feeding finely divided solids and, in combination therewith, means for using gas in various ways to repulverize the finely divided solids. It lends itself to a procedure for continuously charging finely divided solids with water into a high pressure reactor. The high pressure is inherently contained, and the solids are repulverized for use in a reaction, Wurfel, H. - Inventor, U.S. Patent 4,214,974, July 29, 1980, "Process for Hydrogenation of Coal." The invention is an improvement in the process for hydrogenation of a finely divided coal and oil slurry wherein the improvement comprises subjecting the hydrogenation products to a first phase separation to obtain a liquid fraction and a gaseous fraction. The gaseous fraction is subjected to a second phase separation to obtain a liquid fraction having a boiling range between about 200°C and about 500°C, which fraction is used to preheat the coal and oil slurry by direct mixing therewith.

4-109 CAMERON SYNTHETIC FUELS REPORT, DECEMBER 1990 appenait APPENDIX

Meeting Report: DOE/EPA-SRC-II EIS 5-1

Tennessee Valley Authority Draft Environmental Impact Statement Appendix B Waste Characteristics and Row Diagrams 5-5 MEMORANDUM

Meeting Between the Department of Energy and the Environmental Protection Agency on SRC-II

MEETING REPORT: DOE/EPA-SRC-II £15

DATE: September 15, 1980

PLACE: Room 4E-096 DOE, Forrestal Building

TIME: 2:00 p.m. - 3:30 p.m.

ATTENDEES: See attached

Over the past several weeks EPA's comments on the SRC-II draft EIS have generated much concern on the part of DOE officials. Therefore, Key officials of both agencies met to address outstanding issues. It was made clear from the outset that both agencies are strongly committed to the development of a synthetic fuels industry in an environmentally sound manner. With respect to the issues raised on SRC-II, the following agreement was made.

AGREEMENT

1. Regarding EPA/DOE closer coordination

DOE invited EPA to work closely with DOE's Fossil Energy Environmental Task Force which is currently coordinating five synthetic fuel demonstration projects. EPA accepted this invitation.

2. Regarding applying NEPA to the design stages of the project

EPA supports DOE'S NEPA strategy as outlined in the attached letter from John Sawhill to Douglas Costle and believes that the information gaps EPA identified in contenting on the DEIS will be remedied by the FEIS and supplemental reports which DOE will make available to the public. EPA does not believe that DOE needs to issue a revised DEIS before It issues the FEIS.

3. Regarding effective monitoring

The accuracy of analyses and effectiveness of mitigating measures must be tested by a comprehensive monitoring program throughout construction and operation of the demonstration project. DOE and the industrial partners are conmitted to such a program and will assure that EPA and the public are fully apprised of Its results. 5-1 4. Regarding applying NEPA at the commercialization stage of the project

DOE has signed a cost-shared agreement with the industrial partners which now assures that DOE will prepare appropriate NEPA documentation prior to any transfer of the demonstration facility to the industrial partners. EPA agrees that the above commitment satisfactorily addresses one of the major concerns EPA expressed when commenting on the DEIS.

'

George Fumich Jr. I William N. Hedeman, Jr. Assistant Secretary Director for/Fossil Energy, DOE Office of Environmental Review g it- Environmental Protection Agency Lya L. Brothers 116ty Assistant Secretary for Environment, DOE

Attachments

2

5-2 THE SECRETARY OF NERGY WASHINGTON, D.C. 205E5

September 17, 1980

Honorable Douglas H. Castle Administrator United States Environmental Protection Agency Washington, D.C. 20406

Dear Mr. Costle;

I want to extend my appreciation for your expression of the Environmental Prqtection Agency's cooperation and support for the Department of Energy's synthetic fuel demonstration program. We encourage and welcome the Environ- mental Protection Agency's efforts to expedite environmental guidance, reviews, and permits. The development and commercialization of synthetic fuel technologies will necessitate a continued close and effective working relationship between the Environmental Protection Agency and the Department of Energy.

I am advised that interactions between the Environmental Protection Agency and the Department of Energy have begun in connection with the development of generic environmental guidance documents for synthetic fuel technologies. We view this process as extremely critical since these guidance documents will play a major role in shaping environmental compliance requirements for future commercial synthetic fuel facilities. We believe that environmental guidance for synthetic fuel technologies should reflect a range of best available control systems and concepts rather than one particular system or concept that may not be universally cost-effective or technically applicable for individual facilities.

In your letter you expressed concern about the coordination of environmental review and regulatory requirements with the development of the proposed SRC-II project in Morgantown, West Virginia. As you know, this project has major Importance to the President's synthetic fuel program. It is expected to resolve many of the remaining uncertainties with regard to the technical feasibility, environmental acceptability and economic competitiveness of the solvent-refined coal technology.

Conceptual design of the SRC-II project is virtually complete. Detailed final design of the facility should commence on a full-scale basis in the near future and is scheduled for completion by March 1983. As is common in the process industries, facility construction will not await completion of final facility design and is scheduled to begin in the spring of 1981 with an estimated completion date of August 1984. This process should permit the design of appropriate environmental controls to proceed concurrently with final, detailed design of the overall project and to be incorporated in a timely manner into the construction schedule. We look forward to working closely with the Environmental Protection Agency in the design of such controls and to expedite requisite environmental permits. 5..3 Page 2

With respect to our strategy for compliance with the requirements of the National Environmental Policy Act (NEPA), we plan to issue a final environ- mental impact statement with the best available information prior to any decision to proceed with major detailed design efforts and to commence construction of the SRC-It facility. In our view, it is appropriate to complete this final environmental impact statement prior to any signifi- cant financial commitments to the SRC-II project, such as would be incurred by the completion of final design, projected to cost approximately $200 million. Utilizing a tiering approach, we would, of course, perform sup- plementary NEPA reviews as necessary, to address significant environmental impacts not within the scope of the final environmental impact statement. For example, further NEPA review would be required if environmentally significant new information relevant to the selection of environmental control equipment arises as a result of further design efforts. In addition, as new information becomes available which we believe would be of interest to EPA, we will promptly share it with you.

In addition, in accordance with the terms of the cost-shared contract, the Department of Energy will prepare appropriate NEPA documentation prior to any transfer of the demonstration facility to the industrial partner.

It is my intention that Department of Energy staff continue to work closely with the Environmental Protection Agency Headquarters and Regional represen- tatives on resolving environmental issues concerning the synthetic fuels technology area generally and the proposed SRC-II project specifically.

Thank you again for your expressionof cooperation and support.

ohn C. Sawhill eputy Secretary f / -

5-4 TENNESSEE VALLEY AUTHORITY DRAFT ENVIRONMENTAL IMPACT STATEMENT APPENDIX B Waste Characteristics and How Diagrams

1. Waste Characteristics

The following information was used to support environmental evaluations of the candidate gasifiers. Also included is information on wastewaters from ancillary facilities such as the coal pile runoff and cooling tower blowdown. Additional information on waste characteristics can be found in reference 1.

1.1 Wastewater

1.1.1 Coal Gasification and Gas Processing Systems

Process wastewaters are a result of gas scrubbing to remove soluble and insoluble substances, gas quenching to control operating temperatures, steam condensation or reforming during methanation or hydrotreating, and quenching of ash or slag for disposal. Gas liquor (sour water) is the total liquid stream from condensing or scrubbing in the total coal gasification processing system. This gas liquor will likely contain a wide variety of the components found in the product gas as well as sulfur and nitrogen compounds, particulates, phenols, tar and oils (depending on gasifier configuration), and soluble salts. Contamination of methanation reforming water should be minimal because the gases are cleaned before methanation. The sour water produced by the hydrotreating process contains hydrogen sulfide, ammonia, oils, char, and other coal-derived materials. Wastewater from slag or ash Quenching will contain any water-soluble components in the slag or ash.

The majority of tars and oils are created by lower temperature processes (Lurgi dry-ash and Lurgi slagging) that first contact the coal at relatively low temperatures with the raw product gas exiting the gasifier (see Section 2.3). At extreme temperatures, as in the case of the Koppers-Totzek reactor, no tars and oils are formed.

Tables B-I through 8-6 give wastewater characteristics of the five candidate gasifiers. These data show the effect of process temperature on the gasifier wastewater. The wastewater from high temperature processes (8&W, Koppers-Totzek, and Texaco) contain little, if any organic constituents. The wastewater from lower temperature processes (Lurgi dry-ash and Lurgi slagging) contain a variety of organic constituents.

The basic character of the complex organic structure of coal is aromatic. Therefore, the tars that are expelled from the coal during devolatilization in lower-temperature reactors may be expected to contain naphthalenes, indenes, anthracenes, and similar compounds. Oxygenated compounds, such as phenols and

B-i 5-5 cresylic acids, may be expected in addition to nitrogen- and sulfur-containing ring structures. In moderate-temperature reactors, these complex aromatics are hydrocracked and possibly hydrodealkylated to simpler BTX (benzene-toluene-xylene) streams. In higher-temperature systems, even these simple aromatics are cracked to gaseous forms.

The lower temperature processes that produce tars and oils tend to have high-molecular weight organic sulfur species in the product gas. Low-temperature reactors also tend to form various high-molecular-weight nitrogenous compounds, such as pyridines, pyrroles, azoles, indoles, quinolines, anilines, amines, and similar compounds.

During gasification, trace metals found in feed coal are expected to appear predominately In the gasifier ash or slag; those metals that do volatilize into the gasifier product are expected to be removed during gasifier quench and scrubbing. It has been noted that, during combustion of coal, fly ash particles are enriched in trace elements such as arsenic, cadmium, copper, chromium, molybdenum, lead, antimony, zinc, sulfur, boron, nickel, vanadium, selenium, silver, mercury, chlorine, fluorine, beryllium, and uranium. While. little data exist, the more volatile trace elements may condense on the fine particulates and contribute to their toxicity.

Of the volatile trace elements that may appear in the gasifier product gas, most of the elements would be expected to be removed in the gas purification steps, and a great majority of the trace elements would appear in the washwater, eventually to be removed during the wastewater treatment process. Certain trace elements in coal (viz, aluminum, cadmium, copper, molybdenum, lead, antimony, and zinc) preferentially concentrate on smaller particles during combustion, whereas mercury, chlorine, and bromine are discharged as vapors. These trace metals may be found in higher concentrations in the quench waters from entrained bed gasifiers than in those from fixed bed gasifiers, because of a larger carry-over of fly ash into the gas quench step in entrained bed gasifiers.

1.1.2 Ancillary Facilities

In addition to wastewaters previously described, several additional wastewater streams will be produced, namely drainage from coal and sulfur storage piles, cooling tower blowdown, ash sluice waters from the auxillary boiler (if ash is to be handled wet; however, if fly ash is handled dry, there may be runoff from the dry fly ash storage area), metal cleaning wastes, boiler blowdown, and various low volume wastes. -

Coal pile runoff is commonly acidic and contains high concentrations of suspended and dissolved solids, sulfate, iron, aluminum, beryllium, copper, mercury, nickel, selenium, and zinc. Coal pile runoff at either site could be combined with the gasifier blowdown stream for neutralization and reduction, to some 5-6 5-2 degree, of certain metals. The combined flew could then be treated in subsequent downstream wastwater treatment processes or the coal pile drainage could be treated separately and discharged or reused.

If byproduct sulfur were stored on site, the area around the storage pile would be diked and runoff collected and treated prior to discharge or reuse. The pollutants of concern are total suspended solids, chemical oxygen demand (COD), and oil and grease.

Assuming that fly ash from the auxiliary boiler would be handled dry, bottom ash could be handled wet and sluiced to the settling pond. Elevated concentrations of pollutants in the discharges from such ponds are suspended solids, sulfates, iron, aluminum, manganese, mercury, cyanide, selenium, and arsenic.

Chemical cleaning of utility boiler system components occurs after about three years of operation. Both acidic and alkaline solutions are utilized and waste liquors contain metals, nutrients, and organics. Constituents of particular concern are COD, Total Organic Carbon (TOC), phenols, nitrogen, phosphorus, arsenic, cadmium, chromium, copper, iron, lead, manganese, nickel, silver, and zinc. These cleaning wastes would be routed to the plant wastewater treatment facilities.

The chemical characteristics of cooling tower blowdown discharge will consist primarily of the constituents found in the makeup water, which have been concentrated by virtue of the evaporative losses within the condenser cooling system. In addition, chlorination or other techniques may be used as a biocide and corrosion inhibitors may need to be added to the cooling water. Chlorinated blowdown water discharged from the plant may require dechlorination due to recent concerns for the health risk and ecosystem effects associated with the use of chlorine. Any chlorinated discharge will comply with the National Pollutant Discharge Elimination System (NPDES) permit effluent limitations for the facility. It may also be possible to treat this blowdown for reuse within the facility. Any other biocides selected would be used in accordance with the requirements of the Federal Insecticide, Fungicide, and Rodenticide Act and discharged according to HPDES permit limitations. The chemical characteristics and concentrations in condenser cooling water discharge are affected by the concentration factor at which the system is to be operated, the use of biocides and the use of corrosion inhibitors.

During construction at either of the two sites, it has been estimated that the onsite construction force will range from approximately 1,500 to 6,800 employees with a resultant domestic wastewater onsite flowrate of from approximately 24,000 to 170,000 gallons per day. Two alternatives exist for handling the construction force domestic wastewaters. One option is to install and operate over the entire construction schedule a wastewater treatment facility devoted entirely to this waste stream. The 5-7 8-3 second option is to install and operate a wastewater treatment facility to handle the anticipated flow between 1981 and 1985, after which the excess portion of future, domestic wastewaters could be routed to the gasification wastewater treatment facility. If the latter alternative were selected, the gasification wastewater treatment facility would be designed to accept the domestic wastewater stream.

Construction runoff is another miscellaneous waste stream that must be handled. The means by which this waste stream will be controlled and monitored is described in chapter U of the text. Pollutant parameters of concern include total suspended solids, oil and grease, and p11.

1.1.3 Wastewater Treatment

Table 2-9 in the EIS text presents a summary of wastewater treatment technologies that are under consideration for coal gasification processes. There are additional candidates for consideration, such as powdered activated carbon addition to activated sludge, ozonolysis for dissolved organics removal, biological nitrification-denitrification for nitrogen removal, and mixed media filtration for suspended solids removal. This table indicates control effectiveness in terms of percent removal, of certain parameters; but these data are not predicated upon actual experience with coal gasification wastewater. In addition, there is little information on control effectiveness for the priority pollutants or the fate of these pollutants within the individual processes, i.e., whether these pollutants remain in the liquid effluent or in the sludges generated.

Because of the unknowns related to the wastewater characteristics mentioned in the previous section, the specific wastewater treatment processes cannot, at this time, be chosen with any significant degree of certainty. The wastewater treatment processes discussed are considered to cover those most viable; however, their sequencing is not yet proven for treatment of gasifier wastewaters.

Preliminary estimations made by TVA on probable wastewater from its Ammonia From Coal Project (which uses a Texaco gasifier) indicate that the use of chemical precipitation, ammonia stripping, and activated sludge processes may produce a treated gasifier and gas processing combined effluent with the following ranges of effluent characteristics: BOD5 - 30 to 100 mg/l; COD - 60 to 1,000 mg/l; ammonia - 9 to 300 mg/I; cyanide - 3 to 8 mg/I; phenols approximately 0.01 mg/I; and total suspended solids - 30 to 150 mg/I. Further treatment including ozonolysis, biological nitrification-denitrification, and mixed media filtration may further improve the effluent quality to the following: BOD ç -13 to 100 mg/I, COD - 18 to 200 mg/I, ammonia- 1 to 3 mg/l, c'anide - 1 to 3 mg/l, phenols - essentially zero, and total suspended solids - 10 to 15 mg/I. Some removal of toxic

B- 4 5-B and hazardous pollutants by these treatment processes is expected, but the resultant effluent concentration is not yet known.

Some of the wastewater treatment processes presented in -Table 2-9 indicate a potential for producing various byproducts. Chemical precipitation and biological treatment processes produce sludges which require further processing for either ultimate disposal or reuse. An option under consideration is the combination and dewatering of sludges and transfer to the gasifier for combustion. -

Regeneration by combustion of activated carbon used in any wastewater treatment system may produce undesirable air emissions of trace elements or organics removed from the wastewater. Disposal of spent activated carbon in the slag disposal area may be the most viable option. -

The volume and characteristics of sludge or solid byproducts produced in wastewater treatment are not well defined. - However, handling and disposal practices will be chosen that will minimize any potential adverse environmental impacts.

TVA is developing a testing program to ensure the operational readiness of the two preferred gasification processes using eastern high-sulfur coal. As a part of this program, TVA will collect and analyze environmental data. This data will be used to expand the effluent characteristic data base and as input to the design process.

1.2 Solid Waste

The waste coal ash from the gasifier is similar in nature to that from a coal-fired utility boiler. The ash or slag is comprised of a number of elements; but silicon, iron, and aluminum comprise as much as 90% or more of the total ash. The ash will contain a number of trace elements, some of which are potentially toxic to plants and animals at certain levels. - These trace elements have been discussed in the previous section.

A characteristic of the gasifier ash that was of concern to TVA was its potential for leaching. Recent regulations promulgated pursuant to the Resource Conservation and Recovery Act are aimed at protecting groundwater from degradation. Leaching of trace metals from coal ash was viewed as presenting potentially adverse impacts on groundwater. The Environmental Protection Agency established a test by which one could determine whether a waste was likely to leach hazardous concentrations of a given substance into groundwater under conditions of improper management. If the waste were to meet the criteria after being subjected to the test procedure, it would be considered "hazardous" and would be subject to more stringent disposal requirements than if it had not met the criteria.

The criteria most directly affecting coal ash was 'Extraction

B-5 5-9

Procedure (E?) Toxicity." A solid waste is considered "hazardous" if the extract from a sample of the .waste contains any of a specified list of contaminants at a concentration equal to or greater than a specified concentration. Table 3-7 lists the EPA EP toxicity criteria pollutants and their respective limits as well as the results of leaching tests done on TVA coal-fired power plant ash and slag.

As can be seen from this table, TVA has performed a number of tests on the leaching characteristics of slag and fly ash from its power plants using the EP. All of the leachate trace element concentrations of concern were substantially below the EPA limits. It was found that when ash or slag was subjected to the EP, fly ash was more susceptible to leaching. With few exceptions, higher amounts of fly ash constituents were "leached" from the fly ash than from slag. It is thought that slag is more resistant to leaching due to its vitreous physical qualities and larger particle size. The finer fly ash particles may not have passed through a molten phase (as slag has) and the finer - particles provide a larger surface area for contact with water and possible leaching.

Slag from a Lurgi slagging gasifier was subjected to the same test that TVA's boiler slag and ash underwent. Results (see Table 3-8) compared favorably with those of the TVA power plant slag study.

From the perspective of protecting groundwater, a gasifier producing a vitreous slag would be desirable. It appears, however, that neither slag nor ash would present a serious threat to groundwater contamination if properly handled and disposed.

RafArAnnA

"Characterization, Treatment, and Disposal of Liquid and Solid Wastes From Coal Gasifiction Facilities," Vol. I by J. M. Wyatt, D. B. Cox, and L. H. Woosley, Tennessee Valley Authority, June igeo.

5-10 3-6 TABLE 8-1

ESTIMATED MW GASIFIER EFFLUE NT CHARACTERISTICS

Parameter Concentration, mg/I

BUD 5 600

COD 1,200

TSOC 300

Phenols ioo

NH 2,000

SCW . 500

Ct 30

Oils 20

TSS 0

Source: Wyatt, J. M., D. B. Cox, and L. H. Woosley, "Characterization, Treatment, and Disposal of Liquid and Solid Wastes From Coal Gasification Facilities," Vol. I, Water Quality Branch, Division of Water Resources, Office of Natural Resources, Tennessee Valley Authority, June 1980.

5-11 11-7 TABLE B -2

Analysis of Water From Kopperb-Totzek Plant Kutahya, Turkey

Concentration at Sample Locationa, 811b Component 1 2 3 4 5

pH 8.8 8.8 8.9 8.8 8.9 CaO 78. 101. 78. 135. 179. MgO 97. 161. 194. 145. 113. Na 17.5 17.5 17.5 17.5 17.5 K 5.6 8.8 10.0 8.0 8.0 Zn 0.01 0.03 0.02 0.02 0.02 Fe 0.05 0.22 1.95 0.20 0.614 NH 0.32 157. 1814. 137. 122. NO 58.2 3.32 13.7 214.7 22.9 PO, total 1.89 0.81 1.21 0.81 2.70 Cl 18 85 96 57 46 So 42. 216. 155. 255. 109. CN 0.26 0.52 12.5 1.4 114.0

consumed 8. 9. 400. 11. 1145. Chemical oxygen demand 14. 18. 128. 16. 63. S iO2 14.8 15.0 14.8 19.8 42.6 Suspended solids 114. 14612. 5084. 3072. 50. Cu 0.01 0.01 0.01 0.01 0.06

a. 1) Cooling water to slag quench tank. 2) Water from slag quench tank. 3) Washwater after washer-cooler. 11) Water into clarifier. 5) Clarifier effluent. b. All measurements in milligrams per liter (mg/1) except for pH. c. Not detected

Source Farnsworth, J.F., Mitsak, D.M.; and Kamody, J.F.; "Clean Environment with Koppers-Totzek Process", Symposium Proc

October, 1

5-12 SR TABLE 8-3

Characteristics of Koppers-Totzek Condensate

COD 420

TOC 40

NH 17,000

CN 25

SCN 68

142

503 170

Carbonate CO 142,000

Source; Wyatt, J. M., D. B. Cox, and L. H. Woosley, "Characterization, Treatment, and Disposal of Liquid and Solid Wastes From Coal Gasification Facilities," Vol. I, Water Quality Branch, Division of Water Resources, Office of Natural Resources, Tennessee Valley Authority, June 1980.

5-13 8-9 TABLE 6-4

TEXACO GASIFIER SLOWDOWN CHARACTERISTICS

Parameter Concentration

Total Suspended Solids 330 mg/I

Total Dissolved Solids 2,000 mg/1

Ammonia 1,600 mg/I

Chloride 1,320 mg/1

Total Organic Carbon 760 mg/i

Total Inorganic Carbon 104 mg/I

Source: Wyatt, J. M., D. B. Cox, and L. H. Woosley, "Characterization, Treatment, and Disposal of Liquid and Solid Wastes From Coal Gasification Facilities," Vol. I, Water Quality Branch, Division of Water Resources, Office of Natural Resources, Tennessee Valley Authority, June 1980.

5-14 B- 10 TABLE 14-5

Characteristics of Raw and Processed Wa,tewater From the L:'gi Dry Ash Process Plant at Salsothurg, South Africa

General Properties

______values Parameter Raw WatewaIer Processed Wastewater Phenol, mg/I 1,250 3.2 Chemical oxygen demand, mg/I 12,500 1,330 Organic carbon, mg/l 14,190 a Total dissolved solids, mg/I 2,460 596 PH 8.9 6.2 Ammonia, mg/I 11,200 150

Concentration of Specific Compounds

Concentration 5gjb Compound Raw Wastewater Processed Wastewater Fatty Acids

Acetic acid uI 123 Proponoic acid 26 30 Butanoic acid 43 16 2-Methytpropanoic acid 2 5 Pentanoic acid 13 7 3-Methylbutanoic acid i 5 Haxanoic acid 1 6 Monohydric Phenols

Phenol 11250 3.2 2-Methyiphenol 3140 3,2 3-Methylphenol 360 0.2 14-Methylphenot 290 0.2 2,4-Dimethylphenol 120 c 3,5-Dimethytphenol 50 C Aromatic Amines

Pyridine 117 0.145 2-Methypyridine 70 0.05 3-Methylpyrtdirie 26 0.05 4-Methylpyridine 6 0.05 2,4-Dimethylpyridine 1 c 2,5-Dimethytpyridine 1 0 2,6-1)imethylpyridin., I C Aniline i

a. Not determ,,ed. b. Dal, chinned from single samples. Raw wastewai.er samples were Less than 6 months old, and treated wastewater samples were less than 1 month old. C. Not round.

Source: Singer, P.C.; Pfaender, F.K.; Chinchilti, 1.; Macicrawaki, A.?'.; amb, J.C. • itt; Goochman, R. 1978. Assessment of sea'. conversion wastewaters: Characterization and preliminary biotreatability. EPA-600/7-78-181, University of North Carolina. Prepared for Office of Energy, Minerals, and Industry, U.S. Environmental Protection Agency.

B-il 5-15 TABLE 13-5

Characterbitics of Wastewater From the Lurgi Slagtng Process Plant Using [3: turd nous Coal at Weot.ri '1 , Sc,t ,nd

Concentratios at Sample Component Location mg/i

p13b 6.6 9.1 9.2 Alkalinity 188. 12,550. 4,279. Chemical Oxygen Demand 114. 1,140. 1,220. Total Suspended Solids 55. 1 lOB. 70. Total Dissolved Solids 400. 2,518. 6,466. N, nitrate 29.9 1,100. 1,325. N, ammonia 1075. 71,400. 1,400. Sulfate 52. 81. 38. Cl 21. 58. 78. F - 10. 28.2 100. 0.01 0.01 0.01 Mn 0.03 0M9 0.1 Pt' 0.1 0.01 0.2 Cr 0.03 0.3 0.01 Ca 27. 1.9 5.35 Mg 7.25 1.19 3. Cu 0.1 0.01 Ni 0.06 0.3 0.1 K 6.25 10. 26.5 Ag 0.03 0.03 0.03 So 7.7 0.01 0.21 Na 88. 7.1 25. Ti 20. i,500. 870. Al 1. 1. 1. Fe 4.17 232. 140. Hg 0.76 0.0002 Be 0.007 0.007 As 0.52 1.3 Sb 0.15 0.7i Se 0.087 0." TI 0.007 0.007 C13 17. 0.38 Phenols - 2,000. 2,1400. Flourene 0.01 1.3 Acenaphthene 0.01 Naphthalene 2.0 1.5 Phenanthrene 0.78 1.0 Ethyl hexyl phthalate 0.014 - 0.23 Pyrene 0.02 0.01 Flouranthene 0.06 0.01 Benzene 92.0 - 1.3 Toluene 5.5 1.8 Ethyl henzen' , 1.1 0.0! 1,1, 1 -trirht'LE,ns- -'.16 Chlorc' Corm '.70 Bromodtcbloromethane 0.14 0.01 Phenol 103.0 193. 2,4-dimethylphenol 0.01 1.2 Polychlorinated biphenyl.s 0.30 0.75 Pesticide 0.75 0.30

a. 1) slag quench water; 2) oil separater water effluent; 3) tar separater water effluent b. All measurements in milligrams/liter (mg/i) except pH.

Source: Heunisch, G.W. and Gordon J. Leaman, Jr., "Phase I: The Pipeline Gas Demonstration Plant. Analysis or Coal, By-Products and Wastewaters from the Technical Support Program.' DOE, FE-2542-23, August, 1979.

5-16 B-1 2

00 C'J - -4tfl C 00000 00 00 -.4 000000000 000000 U ddddddddc ddddcc dd000 Cl) vvvvvvvvv V VVV V V V V V V V V V -4

-c C CC ------In ri 0C'itflO-4 ---4 --0--- 0 t'J 0 ,-4 0000000 N- 0 0 - 0 00 000 t4 0 In 0 0 '0 000 C1 C C 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 - 0 0 0 C) ...... "-4 '.40000000000000000000000000000 i-i C) V V V V V V V V V V V V V CI C) Cl, --4 u-i --4 C'-1 In In (N (N eq (N C (N CN (N ri (N C C-i (N (N (N C-i C-i (N C-i C-I C-i 4-) C-i C-i C C) '0 0000 a0000000000000000000 -4 co ocoo d dccc d VV V VVVVVVVV VVVVV VV V IVVV -4 .0 '0 0000000000000 C-i 0000000000 In - C-i 00 Ia 0 0 0000000 0 00000 0 00 0000000000 4.-I C) Ia -t 000000000000000000000000000 In CI C V V V V V V V V V V V V V V V V V V V V V V 04 C) U 0 C C InulInInInMi UlInInIn In tifl In00InIn IC 0 000000 00000 (N 00000 C-I 0 0 In 0 N- 00 0 E -.4 000000- 00000000000 In 0 0400000 -.5 I-I 0 000000000000 00 000000 ddddddt V V V V V V V V V V V V V V V V IV IV V V IV ci) I-4 U C) CO p4 --4 C) EIn r1cr10In0In r,omr-In00mcIn-m In In In In In 00 00 In 0 .-s 0 0- 0 0 0\ 0 4000 C-i 000 0 O In 0000 C) -40 C-i 0000000400000000000 0000000 0 '-4 'OO 0 0 0 0 0 0 00 00 000000000 0 '-4 Cl, -IC 'CV V IV V V V V V V V V V V CI 0 Ia IaC) C) C) I- -o .0 0 C) In In 0 - C-i O 0 C-i 0 Q\ 00 0 0 In 00 (N 000 -.7000-P C10 OC) r.1InF-Cq In ------rim-i- C-i In - '0 In0 0 Ia LI -4 C 00 laO 0 0 0 0 00 000 00000 00000 0 --4 Cl, Ia V V V V 0 0 p4 -4 0 -I, 0' C1 CC '.4 In -4 -t '0 In00-t -S -s r- -t 0 T 0 -i 'O0\ 0 C-i -'00 In - C-- 0- 0 (N 0 In 0 C-i 0 -0 C-i 0 • 0- 00 00 00000 - 0 00000 -C 0000000 0 04 CC.c 1.01.c -C .01.0 I . -C 1.0 I.CCtIa C (-1$ CO I'M ri, I'M I')) 10) 0) 10) I'M Ill, I'M 10, 0) I'M 0) r4 Cl) < 1< -c 1< 1< -c 1< i< 1< i< 1< 1< -t < 44 0 .01 .01 .01 .CI .01 .01 .01 .01 CI .01 .01 .01 .01 Qr4 0 E Oil B OlE l B oI B iCI 8 COlE OlE WI 8 olE ol 8 0)18 I 8 CCI B .0 a 0 0 <10 <10 <10 <10 410 <10 <10 <10 410 4iJ NU Ni-I -4i.J .44J >U >.JU N J.J N i-I NU 4< ON o '.4 0 - 0 '.4 0 0 - 0 r-4 0 r-4 0 '-4 0 4 0 '.4 0 .4 0 '.4 0 '.4 0 Q 04 .r4 CC - = .0 11111111111 I IIIl'IlIlIIl Ill 0 040 -C 0 0 :s) s4 0 - :14 .-) Z

B-13

5-17 TABLE B-S

Leaching of Pittsburg 118 Coal Slag from a Lurgi Slagging Cashier Under the EPA "Extraction Procedure"

Concentration in extraction Element liquor, mg/i

Arsenic 0.00027 Barium - <0.2 Cadnium 0.000054 Chromium 0.0016 Lead <0.0003 Mercury 0.00064 Selenium 0.005 Silver <0.0003

Source: Heunisch, G. W. and Gordon J. Leaman, Jr.,"Phase 1: The Pipeline Gas Demonstration Plant. Analysis of Coal, 86- Products and Wastewaters from the Technical Support Program," DOE, FE-2542-23, August, 1979

B- 14

5-18 EL( MEN 1L

AIR st:uH CLEL• TAIL GAS

- - - --I befl C04t _.ICOAL I • MEDIUM.uTj L:

DISPOSAL

FIGURE B-I PROCESS BLOCK FLOW DIAGRAM - 85W GASIFIER

I El E.ENYAL SULFUR

:r;.N TAIL GAS

Q*YtN

CCA i ¼4Ec1uM-eTu Ls II ¶CMP:ESSCH

L__ YETRANATIONj_..eNATURAL GAS

TO To SLAG FLY ASR TO IOSTE 64TER DiSPCSL DISPOSAL TREATMENT

FIGURE 8-2 PROCESS BLOCK FLOW DIAGRAM - KOPPERS—TOTZEK GASIFIER

5-19

CLEAN

N IT HO AL N TAIL GAS VENT

AIR AIR SLL FIR SEPARATIONTEXACO PLANT ELESEWIA_ SULF uP

O'GEN

COAL HANDUENG GAS COOLING ACID GAS I- --61 kcoIUM-r - 3*5 & Pf4(PARAT1O GASIFICAT ON S SINUSIJ1NG REMOVAL

METHANATION j NATURA_ lAS

10 F..T ASH/CARSON SL AU IIECOVERY 10 WASTE AVER TREAIMENT D.SPOS',L IT CA N & N 'AS H To GASIFIER

FIGURE B3 PROCESS BLOCK FLOW DIAGRAM - TEXACO GASIFIER

AI

AIR NITROGEN SULFUR EPAIIAT'ON .ENT RECOVERY ELEMENTAL SULFUR

"NaOSIGEN ACID GAS

COAL LUNG I GAS CIIOLING ACID GAS COAL HANDLING sIrcArIcN I OMPHESS'0NI vD REMO\TA - AND AND SA SCRWUING MEDUM-UTU GAS ARE PA RAT '0 II • ORIING

IQUIR $ - .fTNATID_... USSTITUT( .\AILIFIAI GAS

STEAM - GAS LIOLOR GAS GENERATION 1n1NCL - UAPt,1 "A A.D SEPARATION IQUOR .TM3UIA HECOJRt

SLAG AMMONIA TO TAIL GAS ,IANDL ING PHENOLS NHTRA TREATING TAR 0 IL T SULFUR tANI TO WASTE *AIFH SLAG TO TREATMENT D'S SAL

FIGURE 6-4 PROCESS BLOCK FLOW DIAGRAM - BGC/ LURGI SLAGGING GASIFIER

5-20 AIR STACI, CLEAN AIR NIT ROGE N GAS TAIL GAS SEATICN I OXYGEN VENT

COAL FINES ELEMENTAL SULFUR

COAL FINE S STEAM

CAL 'AN[ 1ING LUMS. ACIDGAS ______GAS - )AL J MEDIUMOTU S AND ASLFICATICN REMO.AL :)MpRE5srg i I__ -As ______PRESS GS PnEN IAPHIHA AND qMPA IECCMPREStI AMMON!A______RECOVERy -

• CL.TAR I ASk A:: G:S lID WASTE WATER HANDUNG T) SU.' U TREATMENT

10 DISPOSAL

FIGURE 8-5 PROCESS BLOCK FLOW DIAGRAM - LURGI DRY ASH GASIFIER

5-21