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VOLUME 18 - NUMBER 2 JUNE 1981

QUARTERLY

c0 0 : ty J - - g r Of Mines

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

® Rcg. U.S. P.I. OFF. Cameron Synthetic Fuels Report is published by the Rocky Mountain Division of The Pace Company Consultants & Engineers, Inc. as a multi-client service and is intended for the sole use of the clients or organizations affiliated with clients b, 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 of any part of the publication requires the express permission of the Rocky Mountain Division of the Pace Company Consultants & Engineers, Inc.

The Rocky Mountain Division has provided energy consulting and engineering services since 1955. The Division's experience includes resource evaluation, process development and design, systems planning, marketing studies, licensor comparisons, environmental planning, and economic analysis. The 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.

S. FRANK CULBERSON. PRESIDENT

TED C. BORER, MANAGER-INFORMATION SERVICES

SYNTHETIC FUELS STAFF

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

CONTRIBUTORS JULIE H. SMITH

CHERRY CREEK PLAZA II 650 S. CHERRY ST., SUITE 400 DENVER, COLORADO 80222 (303) 321-3919 CONTENTS

HIGHLIGHTS A-1

I. GENERAL GOVERNMENT

Reagan Administration's Fossil Energy Policies and FY '82 Fossil Energy Budget Reviewed i-i President Reagan Serious about Regulatory Reform 1-4 Third Biennial National Energy Plan (NEP-11) Being Formulated ...... 1-6 Recent Presidential Appointments Are of General Interest 1-6 Synthetic Fuels Corporation Received 61 Proposals in Response to Its Initial Solicitation of October 31 1-7 Synthetic Fuels Corporation Announces Initial Project Selection Guidelines 1-1? Synthetic Fuels Corporation Issues Interim Guidelines on Disclosure and Confidentiality ..... 1-18 GAO Gives DOE Good Marks on Selection of Projects for the Alternate Fuels Program ..... 1-19 Colorado Issues Its Joint Review Process Manual Governing Project Permitting 1-20 Japan Shows Increased Interests in Synthetic Fuels 1-22 U.S. GOVERNMENT SYNTHETIC FUELS PROCUREMENT NOTICES LISTED ...... 1-23 U.S. GOVERNMENT NOTICES OF PROGRAM INTEREST LISTED ...... 1-25

U.S. GOVERNMENT "RESEARCH AND DEVELOPMENT SOURCES SOUGHT" NOTICES LISTED 1-26 U.S. GOVERNMENT SYNTHETIC FUELS CONTRACT AWARDS LISTED ...... 1-27 ENVIRONMENT

National Commission on Air Quality Submits Its Final Report to Congress 1-28 EPA Issues Emission Reduction Banking Manual 1-30 BLM to Prepare One EIS for All Uinta Basin (Utah) Synfuels Projects 1-31 Small Synfuels Plants Now Governed under Wyomin g's Industrial Siting Act 1-31 WATER

BlA Formulating Rules for Regulation of Reserved Waters on Indian Reservations. .1-32 Water for Utah Energy Projects Will Come from Presently Unused Resources 1-32 ENERGY FORECASTS

Exxon Updates Its U.S. and World Energy Forecasts 1-35 Synthetic Liquids Projected to Become the Major Source of Liquid Fuels • . 1-38 Carter Presidential Panel Report Calls for Energy Conservation, Not Energy Production. • • 1-39 ECONOMICS

Study Claims That As Oil Prices Rise. Costs of'law Synfuels Plants Rise Proportionately 1-41

COMING EVENTS ...... 1-43

RECENT GENERAL PUBLICATIONS 1-46 II. OIL SHALE

PROJECT AC71VMES Rundle Project in Queensland Is Shelved...... 2-i Tosco/Exxon Operating Agreement for Colony Project Is Summarized 2-1 White River Shale Project Plans Phase I Construction to Begin in December 2-i Magic Circle Energy Corp. Announces Cottonwood Wash Oil Shale Project 2-2 TECHNOLOGY Study Rants Paraho Over }-Iytort for Eastern Oil Shale 2-3 Plateau Plans 20,000 BPD Refinery Addition for Shale Oil 2-8 Colorado Synfuels, Inc. Plans Microwave Field Test in Wyoming 2-9 New Process Is Claimed to Dissolve Oil Shale ..... 2-10 FOREIGN Extraction of 31.3 Million Tonnes of Oil Shale in Estonia Reported for 1980 2-il - Soviet Geologist Urges Expanded USSR Oil Shale Development 2-li Jordan Pursuing Additional Oil Shale Studies 7 . 7 2-Il

SOCIOECONOMICS Rio Blanco County Planning Commission Recommends Socioeconomic Conditions for C-a Permit Approval 2-13 ENVIRONMENT Los Alamos Publishes Health and Environmental Program Status Report 2-15 DOE Inspector General Investigates Anvil Points £15 Delay 2-15

LAND Status of Oil Shale Legal Proceedings Noted • 2-17 Colorado BLM Office Publishes Map of Pre-1920 Claims ..... 2-19

STATUS OF OIL SHALE PROJECTS ...... • 2-20 RECENT OIL SHALE PUBLiCATIONS ...... 2-26

III. OIL SANDS

GOVERNMENT Conflict over Canadian NEP Continues ...... 3-1 ERCB Allows Esso Cold Lake Project to Use Natural Gas. 3-2

PROJECT ACTIVITIES Rio Verde Energy Plans Kentucky Oil Sands Production 3-5 Aarian Seeks SFC Aid for Utah Project ..... 3-5 Westken Plans In Situ Project in Kentucky 3-5 Colorado Companies Propose Kansas Heavy Oil Project 3-6 CALSYN Project Will Use Dynacracking 3-6 Getty/Others to Expand California Pipeline Capacity 3-7 Suncor Shuts Down for Biennial Maintenance 3-8 Major Oil Sands Projects React to Canadian NEP 3-9 IS DIN HZ[S)FL.It1I

Physical Separation Applied to Utah Oil Sands 3-12 Syncrude Develops Two Stage Flotation Process ...... 3-13 Potential for Induction Heating Method Discussed ...... 3-14 BETC Awards Contracts to Study Microbial Oil Recover y...... 3-16 Biotechnology Provides an Alternative Oil Recovery Route ...... 3-i? Syncrude Explores Heavy Metal Recovery ...... 3-18 LAND

The U.S. Gets Another Chance to Adopt Combined Hydrocarbon Leasing ...... 3-20 Geology of Manville Hydrocarbon Reservoirs Published ...... 3-21 ECONOMICS

Induction Heating Shows Economic Potential ...... 3-23 U.S. Bureau of Mines Compares Costs of Unconventional Mining Methods ...... 3-25 FOREIGN

Mangyshlak Oil Development is Discussed ...... 326 U.S.S.R. Balakhany Oil Mine Drilling Underway ...... 3-26 Petroven Pours Money Into Oil Development ...... 3-27 Corpoven Improves Processing Capacity ...... 3-27 Maraven Modernizes Cardon Refinery ...... 3-28 Lagoven Undertakes Major Projects to Increase Orinoco Belt Production ...... 3-28 STATUS OF OIL SANDS PROJECTS ...... 3-33

RECENT OIL SANDS PUBLICATIONS ...... 3-46

IV. COAL PROJECT ACTIVITIES

Great Plains Files Proposed Rate Settlement and Receives FERC Approval ...... 4-1 GAO Report Describes Great Plains Status ...... 4-I W.R. Grace Project Activities Described ...... 4-2 New England Energy Park Described ...... 4-2 Congressional Options Regarding Solvent Refined Coal Plants Discussed ...... 4-2 ENVIRONMENT

SRC-I Draft Environmental Impact Statement Released ...... 4-6 GOVERNMENT General Accounting Office Advises Cost Control Methods for Coal Liquefaction Plants ...... 4-10 FERC Denies Transwestern Recovery of Costs of Abandoned WESCO Project ...... 4-11 Montana Energy Almanac Updated ...... 4-li U.S. Regulatory Council Reports on Coal Regulatory Problems ...... 4-13 The Substitution of Coal for Oil and Gas in the Industrial Sector Is Studied b y the Energy Information Administration ...... 4-15 TECHNOLOGY 'Alternative Fuels Monitors' Assess Readiness of Coal Gasification and Liquefaction Technologies ..... 4-17 Gas Price Decontrol Promotes Coal Gasification for NH 3 Production ...... 4-24 EPP.1 Studies Methanol Production via Winkler Gasification and ICI Gas Synthesis ...... 4-25 Wellman Designs and Builds Small Gasifiers in the U.S ...... 4-26 Proceedings of Workshop on Critical Coal Conversion Equipment Published by ESCOE ...... 4-27

NJ ECONOMICS Economics of Methanol and/or Gasoline from Wyodak Coal via Lurgi Gasification Evaluated ...... 4-29

ENERGY POLICY AND FORECASTS Congressional Research Service Reports on Outlook for Commercialization of Coal-Based Synfuels Industry ...... 4-31 National Coat Association Forecasts Coal Use for Synfuels Production ...... 4-31

FOREIGN CSR Ltd. and Mitsui to Evaluate SEC Using Victorian Brown Coal ...... 4-34 Preliminary Design Study to Be Made for a Coal Gasification Plant in Brazil ...... 4-34

LAND DOE Coat Production Goats Are Increased ...... 4-35 Expressions of Leasing Interest in Fort Union Coal Given ...... 4-40 Study Process for Leasing Fort Union Coal Outlined ...... 4-42 Record High Bid Submitted for Federal Lease ...... 4-43 Lease Sate Scheduled for Alabama Subregion ...... 4-45 - - -Interior Announces Guidelines for Possible 5-Year Extension of Pre-1976 Federal Coal Leases ...... 4-45 Surface Mining Regulations and Litigation Reviewed . . . - . . - 4-46 - STATUS OF COAL PROJECTS ...... 4-49 RECENT COAL PUBLICATIONS ...... 4-91

V. APPENDIX

Extensions to Diligent Development Requirement for Federal Coal Leases ...... 5-1

iv HIGHLIGHTS

Synthetic Fuels Corporation Receives Lively Response To Its First Solicitation

March 31, 1981 was the deadline for receipt of proposals to be submitted in response to the Initial Solicitation by the U.S. Synthetic Fuels Corporation for proposals for financial assistance for synthetic fuels projects. As of March 31, 61 proposals had been received A listing of the proposals with brief descriptions of each project proposed, is presented in an article which begins at page 1-7. Despite the deadline, the SFC will continue to receive proposals under its first solicitation.

The forms of financial assistance which the SFC is authorized to offer are loan guarantees, price guarantees and purchase agreements, loans, and joint ventures.

The SFC Announces Its Initial Guidelines On Project Selection, Disclosure, and Confidentiality

On April 9, John McAtee, the Acting Chairman of the U.S. Synthetic Fuels Corporation, released the Corporation's "Initial Guidelines on Emerging Issues and Recommendations for Selecting Projects for Financial Assistance. The Corpora- tion's approach to the project evaluation and the statutory framework within which the Corporation must operate are reviewed in an article which begins at page 1-17.

John McAtee is no longer Acting Chairman of the SFC. President Reagan has nominated Edward E. Noble to serve as Chairman of the Board. The President also nominated six other persons to serve on the Board as Directors. These and other Presidential nominations of interest are discussed in an article which begins at page 1-6.

NCAQ Final Report Kicks Off Clean Air Act Debate In Congress

The Clean Air Act of 1970, which is possibly the most controversial of the environmental protection statutes, is now before Congress for consideration of amendments. When amended by the Clean Air Act Amendments of 1977 (P.L. 95- 95), the amended Act created a National Commission on Air Quality. It also directed the Commission to evaluate the Act and to recommend changes which appear necessary for the Act to achieve its goals. The Commission was also directed to submit its final report to Congress by April 15.

The final report of the National Commission on Air Quality has been submitted to Congress. Its formal presentation represented the "kick-off" of what promises to be a hotly-debated argument over revision of the Clean Air Act. We review the NCAQ final report in an article which begins at page 1-28. We reviewed the positions of the major adversaries in this argument in an article which was presented in the March 1981 issue of the Cameron Synthetic Fuels Report, at page 1-21.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 A-i HIGHLIGHTS

President Reagan Appears To Be Serious About Regulatory Reform

President Reagan has made regulatory reform one of the top priorities of his economic improvement policy. Soon after his inauguration, he issued Executive Order Number 12291 on Federal Regulation, which established new procedures that executive agencies must follow in developing their regulations (See the Cameron Synthetic Fuels Report, March 1981 issue, page 1-3). Then, by postponing the effective dates of proposed regulations, he "froze" these regulations for further study and probable revision. More recently, he formed the Presidential Task Force on Regulatory Relief, headed by Vice President Bush, to ensure consistent direction to agencies which formulate regulations. Vice President Bush has just released a list of existing regulations that various agencies must reassess and possibly modify. These affect many Departments, including DOE, DO!, and EPA. The regulations to be reviewed, which will be of interest to synfuels developers, are discussed in an article which begins at page 1-4.

Along with regulatory relief the President insists on reducing the cost of government. Indicative of efforts to reduce costs is the Administration's request for $435 million in Budget Authority for Fiscal Year 1982 for Fossil Energy. This represents about $1.13 billion less than the Budget Authority request for Fossil Energy made by the outgoing Carter Administration. Details of the new budget request are presented at page 1-1.

NEP-IlI Is Being Formulated

In accordance with the Department of Energy Organization Act (P.L. 95-91), the Department of Energy must soon prepare the third biennial National Energy Plan (NEP-11I). When prepared, it will be submitted to the Congress. In an article which begins at page 1-6, we review DOE's activities in preparing its NEP-Ill.

Rundle Oil Shale Project In Queensland Is Shelved

In April, Esso Australia Ltd. and Southern Pacific Petroleum/Central Pacific Minerals (SPP/CPM) announced that plans to build two demonstration retorts, a Superior and a Lurgi-Ruhrgas, have been shelved. Details appear on page 2-1. In late May, an amended agreement was reached by the partners. Esso will commit at least $30 million directly to a mineability feasibility study over the first three years and not less than $20 million more, if it elects to continue, for another two years. Esso will pay SPP/CPM $10 million immediately after a formal joint venture agreement takes effect and $5 million on the third and sixth anniversaries of the effective date. The $5 million payment would increase to $25 million per year if Esso, as operator, executed a prime contract for construction of a commercial plant. Esso will have the right to withdraw at the end of the third and fifth years of the program and at the end of each thereafter, in which case payments to SPP/CPM would cease. Esso will bear all development costs, excluding payments up to $330 million to SPP/CPM at 1981 values.

A-2 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 HIGHLIGHTS

Tosco/Exxon Colony Agreement Is Summarized

Tosco will retain at least 20 percent interest in the Colony Shale Oil Project, even if it does not advance its share of funds for development. Expenditures in 1981 are estimated at $260 million. Our summary of the agreement is on page 2-1.

White River Shale Project Expects Phase I Construction By December

According to applications to the U.S. Synthetic Fuels Corporation, the lessees of Tracts U-a/U-b plan to begin construction of a Superior retort and a Union B retort by the end of the year. Details appear on page 2-1. We understand, however, that these plans are not firm.

Magic Circle Announces Cottonwood Wash Oil Shale Project In Utah

Ultimate production is planned to be 30,000 BPD using the T 3 retorting process, a variation of N-T-U batch retorts. We review their plans on page 2-2.

Davy McKee Study Indicates Paraho Preferable To HYTORT For Eastern Shales

A study for the Buffalo Trace Area Development District in Kentucky reviewed resources, mining, and processing of oil shale in two counties. The controversial results are presented on page 2-3.

Utah Refinery Plans 20,000 BPD Addition For Shale Oil

Plateau plans to expand its Roosevelt, Utah, refinery to process 20,000 BPCD. The addition is slated to be on line by late 1984. Details appear on page 2-8.

Colorado Synfuels, Inc. Plans Microwave Oil Shale Field Test In Wyoming A field test is planned to demonstrate the so-called Jeambey process on a 40-acre Wyoming State lease in the Green River basin. The patent, a feasibility study, and details about the corporation are presented on page 2-9.

New Process Is Claimed To Dissolve Oil Shale Rock

Horizon Technology, Inc. of Fort Collins, Colorado, has submitted patent applications for a process that uses a recycling chemical solvent to dissolve oil shale rock and to separate metal and mineral by-products from the kerogen. Horizon claims that the process can be applied both on the surface and in situ. Our analysis is on page 2-10.

Estonia Mined 31.3 Million Tonnes Of Oil Shale In 1980

Eighty percent of the oil shale extracted in Estonia is used, by direct combustion, to produce electrical and thermal energy. A Soviet geologist has urged development of oil shale in the Carpathians, and the USSR is investigating Jordanian oil shale, as is West Germany. These developments are discussed on page 2-11.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 A-3 HIGHLIGHTS

Rio Blanco County Planning Commission Recommends Socioeconomic Conditions For C-a Approval It is becoming even more evident that socioeconomic matters are the governing institutional constraints threatening the development of oil shale. Among the conditions for a permit for Rio Blanco Oil Shale Company (RBOSC) is a recommendation that 7 percent of the yearly budget for the project be set aside for impact mitigation. RBOSC is administratively appealing some of the Planning Commission's recommendations, but the issue could wind up in the courts. The Planning Commission's recommendations are outlined on page 2-13.

DOE Inspector General Investigates Anvil Points EIS Delay

In November 1975, it was decided that an EIS would be needed for the Paraho lease activities at Anvil Points. Paraho proposed an increase in the amount of oil shale to be mined from 400,000 tons to 11 million tons. DOE'S Inspector General is highly critical of administrative d ilays and long review cycles that have hampered the production of a final IS. The Inspector General's report is reviewed on page 2-15.

Debate Over Canadian National Energy Policy Continues

On April 13, 1981, in Winnipeg, Federal Energy Minister Marc Lalonde and Alberta Energy Minister Mervin Leitch met to discuss several points of possible compromise concerning the proposed Canadian Energy Program. Although an agreement between governments has yet to be reached, the talks represented the first significant step toward a compromise since the program was announced last October. In March 1981, Alberta initiated the first of three threatened oil cutbacks, reducing production by 60.000 barrels a day. The second cutback of 120,000 barrels a day is scheduled to begin on June 1, 1981. The conditions for, and consequences of, these cutbacks are summarized along with the status of the NEP in an article beginning on page 3-1.

A related article beginning on page 3-9, discusses the response of four oil sand project groups to the NEP. The effect on the Suncor, Syncrude, Alsands, and Esso projects is discussed along with future options for each.

Tar Sand Leasing Bill Proposed

Once again, legislative efforts are underway to establish a combined hydrocarbon leasing program which would allow for simultaneous tar sand, oil and gas resource development. Two identical bills were introduced into the House, HR 3114 by Representative James Santini (D-Nev.), and HR 3092 by Representative Dan Marriot (R-Utah). Hearings are scheduled for mid-June. The proposed legislation is thoroughly discussed in an article beginning on page 3-20. Industry comments and concerns are included along with a review of the history of tar sand leasing.

A-4 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 HIGHLIGHTS

Petroven Plans To Increase Heavy Oil Production

During the next few decades, we can expect rapid growth of the Venezuelan heavy oil industry. Petroven has launched a multi-billion dollar development program targeted at increasing Venezuela's oil production and refining capabilities. Lago- yen has undertaken a major project to upgrade low gravity Orinoco Belt heavy oil to an export grade crude at 125,000 barrels per day. In addition, Lagoven is currently overhauling its Amuay refinery to increase heavy oil feedstock usage and alter the product slate. Maraven has begun a program to modernize the Cardon refinery, adding a new heavy sour crude facility and demetalizing capabilities. Corpoven has also actively been working to increase output of refined products and plans to complete the gasoline project by Fall at their El Palito refinery. These projects are discussed in four articles beginning on page 3- 27.

Suncor Maintenance Program Underway

During May and June of 1981, Suncor will shut down the Fort McMurray oil sands plant for a turnaround and maintenance program. Scheduled biennially, the program will require just over 670,000 man hours and will cost Suncor $21 million. In addition, the project will result in a production loss of 1.8 million barrels. The massive undertaking is described on page 3-8.

Syncrude Develops Two-Stage Flotation Process

A new approach to conventional hot water separation is now going through final optimization in a 2.5-ton-per-hour pilot plant. The two-stage-flotation process developed by Syncrude Canada Ltd. Research, has shown a 95 percent bitumen recovery from medium-quality tar sands (10 - 11 percent bitumen content). The process occurs at a lower temperature and requires less water than the conventional separation method. A review of the process is given on page 3-13. Esso Cold Lake Project Can Use Natural Gas

The Alberta Energy Resources Conservation Board approved an application by Esso Resources Canada Ltd. to use natural gas rather than coal as make up fuel for the Cold Lake oil sands project. An article beginning on page 3-2 discusses the background to the application and the reasons for Esso's request to switch fuel types. In addition, the expected project fuel requirements and terms for the Board's decision are given.

Biotechnology Is Applicable To Oil Sands

The use of microorganisms to recover hydrocarbons from heavy oil deposits is under development by Canadian and U.S. companies. The Bartlesville Energy Technology Center recently awarded research grants in this area to the University of Georgia and the University of Southern California. An article on page 3-17 describes the progress being made by Worne Biochemicals in applying biotechnology to oil recovery.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 A-S HIGHLIGHTS U.S.S.R. Heavy Oil Development Encounters Problems Mangyshlak Oil Development is making progress, but slowly. Planned activities for the Karazhanbas field and the Kalamkas field are described along with the problems of development on page 3-26. Electrical power supply problems are addressed A following article beginning on the same page provides an update of the drilling activity at the U.S.S.R. Balakhany oil mine. PEEC Approves Great Plains Offer Of Settlement Twenty days after filing the Offer of Settlement, Great Plains received approval from the Federal Energy Regulatory Commission for the gas purchase agreement as proposed in the offer, but with certain conditions. A review of the Offer of Settlement is on page 4-1. The following article describes the recently published GAO report concerning the Status of Great Plains. The review is brief as much of the report contains a history of Great Plains that has been covered in detail in past issues of the Cameron Synthetic Fuels Report, and much of the remainder of the material presented by GAO is out of date due to the recent FERC approval. W.R. Grace Co.'s Coal-To-Methanol Project Becomes The First Coal Project To Join Colorado's Joint Review Process The final form of the Colorado Department of Natural Resources manual, "Colorado Joint Review Process for Major Energy and Mineral Resource Develop- ment Projects" is reviewed in the general section on page 1-20. Details of the agreement between the W.R. Grace Project and the governmental entities in the Joint Review Process is described on page 4-2. Congressional Options Regarding SEC Plants Are Discussed The Congressional Research Service released a report to congress designed to provide information useful in deciding the future of the Solvent Refined Coal Plants. The report, which poses more questions than it answers, is reviewed on page 4-2. SEC-I Draft Environmental Impact Statement Released While discussions continued about the future of the SRC plants, sponsors continued the necessary pre-construction work. The Draft Environmental Impact Statement for the SRC-1 project was released in January. A review of the two volumes begins on page 4-6.

A-6 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 HIGHLIGHTS

Escalating Costs A Problem For Coal Liquefaction Plants

In another report concerning the Solvent Refined coal plants, the Government Accounting Office (GAO) recently made recommendations to the DOE to control cost growth in the liquefaction programs and the future energy programs. An analysis of GAO findings is on page 4-10. The problems encountered by the H- Coal and Exxon Donor Solvent projects during recently completed construction were analyzed by the GAO, and recommendations made to congress regarding the solvent refined coal plants based on these problems.

FERC Denies Cost Recovery On WESCO Project

While the GAO was making recommendations concerning the cost of liquefaction plants, the FERC issued a ruling of importance to the Synfuels industry concerning the abandoned WESCO coal gasification project. The FERC ruled that the WESCO project expenses did not qualify for rate base treatment for alternative cost of service treatment that Transwestern had requested. FERC's denial is discussed on page 4-11.

Energy Development In Montana Discussed

The Montana Energy Almanac was recently updated. A review of the update begins on page 4-11. A description of Montana's Major Facility Siting Act with an analysis of its most recent amendments are given. A review of major energy policy being considered for Montana is included.

Coal Regulatory Problems Identified

The State's Regulations are often in conflict with the Federal Regulations. Before the Regulatory Council was abolished, (as discussed in the article on page 1-4 in the General Section), they issued a report on coal regulatory problems, and the resulting conflict between the States and the Federal agencies. A description of that timely report is on page 4-13 of the Coal Section.

Alternative Fuels Monitors Assess Direct And Indirect Liquefaction Technologies

The Environmental Protection Agency commissioned Hagler, Bailly & Company to prepare monitoring reports to determine the commercial readiness of various alternative fuels technologies to aid in the EPA's preparation of Pollution Control Guidance Documents. The monitors for Coal Gasification and Indirect Liquefac- tion and Direct Liquefaction are reviewed on page 4-17. The two monitors are a compilation of material previously reported in more original reports. MetMnol For Electric Power Generation Studied

Methanol as a fuel for generation of peaking electric power was the topic of a study recently completed by the Electric Power Research Institute. The Winkler Gasification and IC! methanol synthesis was the basis for the study which is reviewed on page 4-25.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 A-7 HIGHLIGHTS

Outlook For Coal Based Synfuels Uncertain The report by the Senate Committee on Energy and Natural Resources entitled "Synfuels from Coal and the National Synfuels Production Program, Technical, Environmental, and Economic Aspects" describes the outlook for synfuels as uncertain. The report is only briefly reviewed on page 4-31, however, as much of the material is out of date as it was based on the previous admimistration's policies. The outlook is still uncertain, though for different reasons, with the current administration. National Coal Association Forecasts Synfuels Goals Will Not Be Achieved

Because of the economic, technical, environmental, and other regulatory conditions that must be met by synfuels plants, the production goals set by the government in creating the Synthetic Fuels Corporation will not be met. The latest NCA forecast on coal use in the 1980's is described on page 4-31.

DOE Coal Production Goals Increased In updating the preliminary coal production goals, DOE has increased the amounts for a number of reasons, including a higher expected need for coal for synfuels production. An analysis of DOE's latest goals update is on page 4-35.

Interest In Synfuels Is High In The Fort Union Region An indication of the interest in synfuels is revealed in the expressions of leasing interest submitted for the Fort Union Coal Leasing Region. The expressions are tabulated on page 4-40. In addition, the following article describes the study process underway in the region.

Fort Union Region Will Prepare Preliminary Facility Evaluation Report Of special interest to the synfuels industry is the Preliminary Facility Evaluation Report that will be prepared for each tract in the Fort Union Region. Using the expression of leasing interest, the Regional Coal Team will postulate a likely use or reasonable alternate uses by site (tract or tracts). Purpose of this evaluation is to analyze the impacts of development for the whole region for inclusion in the Regional EIS. A description of the PFER's is contained in the review on page 4- 42.

Leasing Continues Under Federal Coal Management Program

A truly competitive coal lease sale was conducted in April at the Bureau of Land Mangement in Denver. A record of $1,700 an acre was paid for a tract in Hayden Gulch at the third sale held under the new program. Further discription of the sale is on page 4-43.

A-S CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 ______S r fl f)IU[CJRS: ge)IlDReraJL

GOVERNMENT

REAGAN ADMINISTRATION'S FOSSIL ENERGY "Second is the nature and extent of the energy POLICIES AND FY'82 FOSSIL ENERGY BUDGET problems facing this nation. Our domestic policies REVIEWED must continue to be made within the shadow of an uncertain and increasingly expensive supply of for- Roger W. A. Legassie, Acting Assistant Secretary for eign energy. Yet, it is naive to believe that the Fossil Energy (DOE) presented a succinct summar y y of Federal government can develop and force the the new Administrations energ policy in testimony introduction of new technologies before the eco- presented on March 12 to the House Subcommittee on nomic or regulatory climate is ready. This is not Energy Development and Applications (to the House to say that we cannot allocate enough money to Committee on Science and Technology). That policy is construct some large-scale projects, but the com- stated best by quoting Mr. Legassie, as follows: mercial acceptance of these technologies depends on their relative economics. We believe we can "The Fiscal Year 1982 revised budget request for expand the development of our vast domestic re- Fossil Energy has been forged from two basic sources and accelerate the commercial introduc- principles which undergird the Administration's tion of new and better technology by creating the energy and economic policies. proper climate for private investments and risk taking." 'First, we must take unprecedented steps to regain control of the Federal budget. Every Federal The Administration is requesting $435 million in Budget government program has been examined in detail, Authorit y for Fiscal Year 1982 for Fossil Energy. This is and nearly every agency has been required to about $1.13 billion less than the Budget Authority re- contribute to the effort to reduce growth in quest made by the outgoing Carter Administration on Federal spending. The Department of Energy is no January 15, 1981. Details of the new budget request for exception. Fossil Energy Research and Development b y DOE for FY 1982 are presented as Table I, taken from Legassie's presentation.

TABLE I

DEPARTMENT OF ENERGY FY 1982 BUDGET REQUEST FOSSIL ENERGY RESEARCH AND DEVELOPMENT (Budget Authority in Thousands)

January 15 Revised Program Budget Request Budget Request COAL

Mining R&D

Underground Mining 20,000 $ 15,000 Surface Mining 2,000 -- Coal Prep & Analysis 10,000 6,000 Capital Equipment 800 800 Subtotal 32.800 21,800 Coal Liquefaction

Direct Hydrogenation 65.000 $ 20,000 Solvent Extraction 63.000 30,000 Indirect Liquefaction 22,000 14,000 Third Generation Proc. 18,300 18,300 Support Studies/Eng. Evaluations 14,600 10,600 Liquefaction Demo Plants 703,400 12,300 Capital Equipment 700 700 Subtotal 887,000 105,900

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-1 TABLE 1 (Continued) January 15 Revised Program Budget Request Budget Request Surface Gasification

High Btu Gasification $ 8,700 $ 1,140 Low/Med Btu Gasification 13,200 13,200 Third Generation Proc. 28,870 27,100 Technical Support 12,000 12.000 Gasification Demo Plants 153,600 -- Capital Equipment 550 550 Subtotal 216,920 53,990 In Situ Gasification Low/Medium Btu Gas $ 3,000 $ 3,000 Gov/Industr y Coop Proj. 2,200 -- Steeply Dipping Beds 3.200 3,200 Environmental Support 1,300 1,300 Supporting Research 800 800 Capital Equipment - - 300 300_ Subtotal 10,800 8,600 Advanced Research & Technical Development

Processes $ 21,400 $ 21,400 Direct Utilization 12,800 12.800 Materials & Components 12.000 12,000 Program Direction & Coordination 11,500 8,500 University Coal Research 5,400 5,400 General Plant Projects 6.000 6,000 Capital Equipment 500 500 Construction 3,000 1,000 Subtotal 72,600 67,600 Advanced Environmental Control Technology

Flue Gas Cleanup $ 17,400 $ 6,500 Gas Stream Cleanup 14.400 14,400 Cleanup Base Technology 5,500 5.500 Capital Equipment 500 500 Subtotal 37,800 26,900 Combustion Systems

Atmospheric Fluidized Bed Combustion $ 15.300 $ 11,300 Advanced Combustion Technology 1,100 1,100 Alternative Fuel Utilization 6,400 6,400 Combustion Systems Demo. Plants 3,000 3,000 Capital Equipment -- Subtotal 76,700 38,800 Heat Engineering & Heat Recovery

Central Power Systems $ 16,500 $ 91100 Dispersed Power Systems 6,500 6,500 Heat Recovery Component 6,000 - Capital Equipment 450 450 Subtotal 29,450 16,050

1-2 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE 1 (Continued) January 15 Program Revised Budget Request Budget Request Fuel Cells Phosphoric Acid System Devel. $ 10,100 $ 10,100 Molten Carbonate System Devel, 14,100 Advanced Concepts 14,100 4,400 4,400 Subtotal 28,600 28,600 Magnetohydrodynamics

Open Cycle Systems $ 59,500 $ Closed Cycle System 500 Capital Equipment Subtotal 60,000 Program Direction $ 12,520 $ 12,520 COAL TOTAL $ 1,465,190 $380,760 PETROLEUM Enhanced Oil Recovery

Heavy Oil $ 9,100 Light Oil $ 7,100 8,000 8,000 Tar Sands 6,000 Capital Equipment 5,000 750 750 Subtotal 23,850 20,850 Advanced Process Technology

Advanced Exploratory Research $ 1,000 Product Characterization & Utilization $ 1,000 2,000 2,000 Shale Oil Refining & Utilization 700 Capital Equipment 700 500 500 Subtotal 4,200 4,200 Oil Shale

In Situ Conversion $ 25,850 $ 15,250 Surface Conversion 1,300 Capital Equipment 1,000 1,000 1,000 Subtotal 28,150 17,250 Drilling & Offshore Technology Drilling Offshore Technology Environment & Support Capital Equipment Subtotal Program Direction $ 1,620 $ 1,620 PETROLEUM TOTAL $ 57,820 $ 43,920

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-3

TABLE I (Continued)

January 15 Revised Budget Request Program Budget Request GAS Enhanced Gas Recovery Eastern Gas Shales $ 10,900 $ 2.600 Western Tight Sands 11,000 6,000 Methane from Coal Beds 5,000 1.000 Environment & Support 700 400 Capital Equipment 600 200 Subtotal 28.200 10.200 Program Direction $ 460 $ 460 GAS TOTAL $ 28.660 $ 10,660 RESOURCE APPLICATIONS -(Transferred to-FOSSIL ENERGY-) Domestic Energy Supply

Coal $ 1,200 $ -- Oil Shale Industrialization 5,500 -- Oil and Gas 1,500 -- Industrialization Planning 800 -- Program Direction 3.000 -- Subtotal 12.000 - Federal Leasing $ 3.489 $ TOTAL RA FUNCTIONS TRANSFERRED TO FOSSIL ENERGY $ 15.489 FOSSIL ENERGY TOTAL $ 1.567,159 $435,340

PRESIDENT REAGAN SERIOUS ABOUT The Task Force description of existing regulations which REGULATORY REFORM are of interest to the synfuels industry follow.

President Reagan has made regulatory reform one of the Coal Conversion Program top priorities of his economic improvement polic y. On February 17, he issued Executive Order 12291 on A complex set of rules implementing a statute which "Federal Regulation." As discussed in detail in the directs electric utilities and large industrial fuel users to March issue of the Cameron Synthetic Fuels Report switch from oil and gas to coal or some alternative fuel. (page 1-3), this Order revoked Executive Order 12044 on The statute includes a prohibition of natural gas for "Improving Government Regulations" and established baseload power generation after 1990. new procedures that executive agencies must follow in developing their regulations. These requirements may be unnecessar y with decontrol, and counterproductive, given increased availability of On March 25, Vice President Bush announced that the natural gas since the Fuel Use Act was passed. President had abolished the United States Regulatory Council in order to avoid duplication of effort by the BCT Effluent Guidelines newly formed Presidential Task Force on Regulatory Relief and to ensure consistent direction to the various Under the 1977 Amendments to the Clean Water Act. agencies. Vice President Bush is Chairman of the EPA is required to consider the reasonableness of costs Presidential Task Force on Regulatory Relief. in establishing more stringent effluent limits for industrial dischargers of conventional (non-toxic) pollutants in Vice President Bush released a list of existing regula- relation to comparable municipal costs. Under these tions that various agencies will be reassessing and possi- requirements, EPA established the incremental cost of bly modifying. He also released a list of regulations that achieving a more stringent treatment of municipal are designated for postponment. The postponed "mid- wastewater as a benchmark for determining the "reason- night" regulations will not be made final in their current ableness" of more stringent controls for industrial dis- form, but will be reviewed by the agencies. chargers. EPA determined a benchmark cost of $1.15

1-4 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 per pound for municipal treatment. However, recent automatically be reduced to the lowest feasible level anal ysis indicates that EPA's methodology maybe in- (i.e., through engineering and work practice controls). correct. EPA is restudying the BCT benchmark cost to The policy specifically rejects the use of cost-benefit ascertain whether a lower cost figure would meet the analysis in setting exposure levels. requirements of the law. Adoption of a lower benchmark cost figure could result in substantial savings. The Task Force description of regulations designated for postponement or revision which are of interest to the Hazardous Waste Disposal synfuels industry follow.

These rules establish a comprehensive, "cradle-to-grave" Prime Farmlands (46 FR 7208) program governing the generation, handling, and disposal of hazardous wastes. Estimates of the costs of this This rule implements the Surface Mining Act, and re- program range from one to two billion dollars per year; places rules invalidated by the Courts in 1978 concerning however, EPA has never completed a thorough regula- the standard defining whether mined areas should be tory/economic analysis of the program and any cost returned to prime farmland and the "grandfather" rule figure is somewhat speculative. Several major issues concerning land being mined before passage of the Act. deserve review, including the comprehensive definition This rule will be reexamined. of hazardous waste under the rules and the limited extent to which EPA has been able to vary program Prime Farmlands (46 FR 7894) requirements based on the degree of hazard of the waste. This program will impose a substantial additional This amendment also implements the Surface Mining burden in terms of the time, effort, and financial re- Act, dealing only with the grandfather clause and also sources required of the private sector in meeting the implementing the Court's ruling. This rule will be information requirements imposed by the program. reexamined.

Surface Mining Rules Extraction of Coal, Two Acres or Less (46 FR 7902)

These regulations implement the Surface Mining Act, These rules tighten the two acre exemption included in which sets forth techniques that must be used for the Surface Mining Act. The Interior Department has surface mining, particularly recontouring and reclaiming decided to reconsider it. the land afterwards. The requirements for original contour and vegetation may preclude more useful or FLPMA j) Exchange Authority for Public Land (46 FR aesthetic treatment. These rules not only raise the cost Aa of surface mining, but could render some areas uneconomical to mine at alt. This rule deals with procedures governing the Interior Department's authorit y to exchange public lands for private lands. The rule will remain frozen until the Department decides whether to reconsider it. Federal Coal Management Program Vice President Bush also announced EPA's approval of These regulations govern competitive lease sales for coal the first State "bubble" rule that avoids the need for on federal lands. They determine the rate at which coal case-by-case EPA review. Approval of this rule, submit- will be made available (target-setting procedures), and ted by New Jersey, will permit cheaper and more flexi- withdraw some areas entirel y from coal mining "unsuitable pollution control at the State level and will result in bility" criteria. In the West, where Federal lands contain greater pollution reductions at the same time. the major share of total coal reserves, excessively restrictive management can cause shortages, lessen EPA to Continue to Publish its "Agenda of Regulations" competition, and raise coal prices. One major activity of the abolished U.S. Regulatory OSHA Carcinogen Policy Council is to be continued under the Reagan Administra- tion. This is the publishing, semiannually (April and The Cancer Policy does not regulate specific chemicals October), of an "Agenda of Regulation" by the EPA. nor require their regulation. Instead, it explains how OSHA will regulate carcinogens in the future. It is EPA published its most recent Agenda on Regulations in intended to streamline the regulatory process, thereby the Federal Register on April 27, 1981, commencing at conserving the resources of both the Agency and page 23692. A previous agenda was published on January affected industries, as well as providing greater protec- 14, 1981, 46 FR 3408. Each agenda should be useful to tion to employees. It is also designed to assist industries' keep interested parties informed of the progress of long-term planning by giving them notice of how regula- regulations. Each agenda includes new regulations as tion would proceed. The policy achieves these goats by well as existing regulations, which the Agency is review- establishing (1) the evidentiar y criteria by which OSHA ing or revising. will conclude that a substance causes cancer; (2) a system for establishing priorities; (3) rulemaking procedures, including limitations on the issues which can be raised; and (4) certain substantive requirements which must be incorporated into future regulations of Category I carcinogens, most notably that employee exposure must

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-5

THIRD BIENNIAL NATIONAL ENERGY PLAN (NEP-Ill) The U.S government should also take steps BEING FORMULATED necessary to deal with potential disruptions in world oil markets. These steps include In accordance with Section 801 of the Department of increasing strategic petroleum stocksand eli- Energy Organization Act (Public Law 95-91), the Depart- minating controls on oil which discourage the ment of Energy is beginning to prepare the third biennial private sector from dealing with disruptions National Energy Plan. NEP-Ill, when prepared, will be effectively. submitted to the Congress. It is anticipated that this submission will be made in June 1981. The level of oil imports per se is only a rough indicator ofy the Nation's progress in solving DOE scheduled seven public hearings on NEP-Ill in April its energ problem. The welfare of the in San Francisco, Dallas, Atlanta, Denver, Boston, Chi- American people is inextricably linked to cago, and Washington, D.C. that of people in other countries, so the U.S. cannot insure its own security by a reckless DOE prepared a staff working paper which was to attempt to eliminate imports. "stimulate public comment and recommendations," but which was not necessarily intended to constitute a draft Energy is an international issue and so the of the NEP-Ill. That working paper was published in the American people have an interest in seeing Federal Register on March 20, 1981, at pages 18000 - that other countries establish sound energy 18007. The working paper had the following four parts: policies. • Developing the Third National Energy Plan - • The International Context • Current Prospects and—Problems- - RECENT-PRESIDENTIAL APPOINTMENTS AREOF - • New Views of Energy Policy GENERAL INTEREST

Part IV, the New Views of Energy Policy, is of interest, Following are a few of the appointments, made by and contains a set of guiding principles offered by the President Reagan in recent weeks, which are of general new Administration. These are: interest in regard to synthetic fuels development:

The Nation's energy problems will be solved Edward E. Noble - as Chairman of the Board primarily by the American people them- of Directors of the U.S. Synthetic Fuels selves—by consumers, workers, managers, in- Corporation. Noble served previously as a ventors and investors in the private sector-- Director of Noble Affiliates, Inc., an oil- not by the government. related company in Oklahoma.

The government's role is to establish sound The following six persons' names have been public policies, based on economic principles. sent to the Senate Energy and Natural Re- national security concerns, and a due regard sources Committee for clearance, as prob- for environmental values, so that individuals able appointees as board members of the U.S. and firms in the private sector have the Synthetic Fuels Corporation: incentives to produce and conserve energy efficiently, consistent with the national - Robert Six interest. - Victor Schroeder - Howard Wilkins The government's role is not to select and - Robert Monks promote favored sources of energy. Doing so - Donald Santarelli risks wasting the Nation's resources. - Victor Thompson Formulation of energy policy must be sensi- • Garrey Edward Carruthers - as Assistant tive to the needs of the poor. But energy Secretary of the Interior (for Land and Water policy should not be used as an income trans- Resources). Carruthers previously served as fer program. For example, holding energy Acting Director of the New Mexico Water prices down for rich and poor alike is an Resources Research Institute. ineffective way to help the poor. • James G. Watt - as Chairman of the Water Federal public spending for energy purposes Resources Council. Watt currently serves as should be limited to those areas where the Secretary of the Department of the Interior. private sector is unlikely to invest sufficiently, such as in high cost, long lead time • Robert F. Burford - as Director of the technologies with substantial prospects of Bureau of Land Managment. A former high pay-off. Public spending should not be Speaker of the Colorado House of Represen- used to subsidize domestic energy production tatives, Burford is a rancher from Colorado's and conservation since this buys us little Western Slope. additional security and diverts capital, workers and initiative from more productive • Ann McGill Gorsuch - as Administrator of uses elsewhere in the economy. the Environmental Protection Agency. Gor- such formerly served as an attorney for

1-6 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Mountain Bell and in the Colorado House of March 31, 1981 was set as the deadline for receipt of Representatives. proposals in response to the Initial Solicitation. As of March 31, 1981, the Synthetic Fuels Corporation had • Georgians Sheldon - renominated as Com- received 61 proposals from industry. Of these proposals, missioner for FERC for a term expiring 14 were for oil shale projects, 17 were for coal gasifica- 10/24/84. Sheldon served as a member of the tion projects, 19 were for coal liquefaction projects, Commission since 1977, and as Acting Chair- eight were for tar sands projects, one was for a coal-oil man since January of 1981. mixture project, one was for a project to produce hydrogen from water. • James Burrows Edwards - as Secretary of Energy. Edwards, a former Naval officer, A listing of the 61 proposals received, with a brief served as Governor of South Carolina and as description of each project proposed, is presented as Chairman of the National Governors' Asso- Table 1. ciation Subcommittee on Nuclear Energy. Even though the March 31 deadline for receipt of pro- • Donald T. Hodel - as Under Secretary of the posals under the Initial Solicitation has passed, the Department of the Interior. Hoclel was Synthetic Fuels Corporation will continue to accept Administrator of the Bonneville Power proposals. John McAtee, the Acting Chairman of the Administration and later served as a consul- SEC at the time the list of proposals was released, tant to the National Electric Reliability stated, "I anticipate that the Corporation will either Council. retroactively extend the March 31 deadline or issue a new solicitation for proposals which will provide us with • R. Tenney Johnson - as General Counsel to continuing information on the state of the industry." the Department of Energy. Johnson previously served as General Counsel to ERDA.

• William H. Coldiron - as Solicitor of the Department of the Interior. Coldiron served as Chairman of the Board of the Montana Power Company and was a Professor of Law at the University of Montana. • William K. Davis - as Deputy Secretary of Energy. Formerly a Vice President of Bech- tel Power Company, he has also served as Director of Reactor Development for the AEC.

• A. Alan Hill - as a member of the Council on Environmental Quality. Upon confirmation, the President intends to designate Hill Chair- man. He recently served as deputy secretary of the Agriculture and Service Agency, State of California.

SYNTHETIC FUELS CORPORATION RECEIVED 61 PROPOSALS IN RESPONSE TO ITS INITIAL SOLICITATION OF OCTOBER 31 The October 31, 1980 issue of the Federal Register contained the Initial Solicitation by the U.S Synthetic Fuels Corporation for proposals from companies for financial assistance for synthetic fuels projects. The forms of financial assistance which the SEC was prepared to offer were loan guarantees, price guarantees and purchase agreements, loans, and joint ventures. The Initial Solicitation by the SEC was discussed in detail in the December 1980 issue of the Cameron Synthetic Fuels Report, in an article which begins atat pages 1-5. The solicitation was reproduced in that article.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-7 TABLE 1

PROPOSALS FOR FINANCIAL ASSISTANCE SUBMITTED TO THE U.S. SYNTHETIC FUELS CORPORATION IN RESPONSE TO THE INITIAL SOLICITATION OF OCTOBER 31, 1980

ALABAMA

NORTH ALABAMA COAL GASIFICATION PROJECT - Murphy Hill, Alabama The North Alabama Coal Gasification Consortium is sponsoring a medium-Btu coal gasification project that would employ either a Koppers-Totzek or a Texaco gasifier. The project was started by the Tennessee Valley Authority. It would produce 600 million SCF per day of medium Btu gas (25,000 BOE/day). Construction would begin in 1982 and initial production is estimated in 1986. Loan guarantees are requested.

ALASKA

BELUGA METHANOL PROJECT - Near Granite Point, Alaska The project is a joint venture of Cook Inlet Region Inc. and Placer Amex Inc. The proposed technology is an indirect liquefaction using the Winkler Fluidized Bed Coal Gasification and ICI Low Pressure Methanol Synthesis processes. Production would be 54,000 barrels per day of fuel grade methanol. Operation would begin in the second quarter of 1987. Loan guarantees and price guarantees are requested.

ARIZONA

CONSUMERS SOLAR ELECTRIC POWER CORPORATION - Yuma County, Arizona The Consumer Solar Electric Power Corp. has proposed a project using photo- voltaic solar thermal electric power and hydrogen electrolysis technology. The project would produce 600,000 Kwh per day or an equivalent of 1,176.5 barrels of oil per day. Loan guarantees and price guarantees are requested.

ARKANSAS

CENTRAL ARKANSAS ENERGY PROJECT - Redfield, Arkansas The project is sponsored by the Arkansas Power & Light Company. The Texaco coal gasification process would be employed to produce 120 billion Btu's per day of medium Btu gas, in turn to be burned in a combined cycle cogeneration plant to produce electrical energy and process steam. Construc- tion would begin in 1984 with commercial operation estimated in 1988. Loan guarantees are requested.

CALIFORNIA

HOPCO - Kern County, California Cornell Heavy Oil Process has proposed a project in the Kern River Field in Kern County, California to produce liquid fuel from heavy oil resources. Completion of on site construction is scheduled for October 1981 with initial production to begin in February 1982. A loan guarantee is requested.

VACA TAR SAND PROJECT - Ventura County, California The Santa Fe Company has proposed a tar sand project located near the city of Oxniard, California. The facility will have 16 producing wells and two injection wells. Price guarantees are requested.

1-8 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE I (Continued)

MONTEX INTERNATIONAL CORPORATION PROJECT - Kern County, California The Montex Corporation is the sole sponsor. The project will employ Montex technology using ketones as a cold extraction of heavy oil from the bituminous deposits found in California. The project will produce 10,000 BPD of aircraft and motor fuels, and production will begin within six months of securing the necessary financing. Loan guarantees are requested.

SAN ARDO PROJECT - Monterey County, California The project is sponsored by Texaco, Inc. and Pacific Gas and Electric Company. It will employ the Texaco Coal Gasification process combined with topping cycle cogeneration to produce electricity and steam. The feedstock will be 4,000 tons per day of coal to produce an estimated 225 megawatts of electricity and 1.5 million pounds per hour of steam. Engineering and construction permit applications could be started in 1983. Loan guarantees are requested.

COOL WATER COAL GASIFICATION PROJECT - Dagqett, California The Coolwater Coal Gasificaton Program, sponsored by Texaco, Inc., Southern California Edison Co., Electric Power Research Institute, Inc., Bechtel Power Corporation, and General Electric Company, proposed a coal gasification project using a Texaco gasification process. The gasifier would produce 750 x lob Btu per hour of synthesis gas to power a 100 megawatt combined cycle electricity generating facility. Construction would begin in 1981 and initial production is estimated for 1983. The sponsors request joint venture participation by the Corporation.

CALSYN - West Pittsburg, California The project sponsor is California Synfuels Research Corporation, Torrance, California. The project proposes "heavy oil conversion" or "dynacracking" producing 1645 BOE per day of fuel gas, 2211 barrels per day of NAPHTHA and 1463 barrels per day of a heavy petroleum distillate. Construction is expected to begin within 180 days and continue for eighteen months prior to the first production. Loan guarantees have been requested.

COLORADO

SFL4LEGLASS CORPORATION PROJECT - Grand Junction, Colorado The Shaleglass Corporation proposes a project that would both produce and consume raw shale oil as an energy source in a Sorg cellular glass process that uses shale by-products to manufacture glass and building materials. Production levels of shale oil are unspecified. Production would begin 30 months from date of award. A joint venture is requested.

CHOKECHERRY COAL-SOURCED METHANOL PROJECT - Moffat County, Colorado The Energy Transition Corporation is sponsoring a coal to methanol module consisting of a single Koppers (KBW) gasifier and producing SO million gallons of methanol per year. They plan to expand eventually to produce 500 million gallons per year. Price guarantees have been requested.

COLONY PROJECT - Garfield County, Colorado The Tosco Oil Shale Corporation is jointly sponsoring an oil shale project with Exxon. The project would employ the Tosco II process to produce 48,300 BOE/day. Initial production would begin in the mid-1980's. Loan guarantees are requested for the Tosco share of the project.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-9 TABLE 1 (Continued)

CATHEDRAL BLUFFS - Rio Blanco County, Colorado The project is sponsored by a general partnership between Occidental Shale Oil and Tenneco Shale Oil. It will employ an oxy-modified in situ and surface retorting process and has a production goal of 55,000 barrels of shale oil per day (BPD) by 1988 and 94,000 by 1990. A loan guarantee is requested.

RIO BLANCO OIL SHALE PROJECT - Rio Blanco County, Colorado Rio Blanco Oil Shale Company has proposed a shale oil production facility using the Lurgi surface retorting technology. Approximately 50,000 barrels per day of production is planned for the project to be located on Tract C-a west of Meeker, Colorado. Operation of the retort is scheduled for mid-1983. A loan and price guarantee have been requested.

COAL FUEL CONVERSION COMPANY PROJECT - Near Trinidad, Los Animas County, Co. -The-project is-a joint venture of the Coal Fuel Conversion Company and Timberline Fuels involving the liquefaction of coal using the Ott hydra- -- - genation process. The project, which will produce 1,000 BPD of Bunker fuel #6, will be completed one year and three months after the decision is made to proceed. A purchase agreement is requested.

MULTI MINERAL CORPORATION PROJECT - Piceance Creek Basin, Colorado The Multi Mineral Corporation is proposing a project to produce shale oil using its own integrated in situ process. It would produce 50,000 barrels per day. Construction would start in 1981 and initial shale oil production is estimated in 1984. Loan and/or price guarantees are requested.

PARACHUTE OIL SHALE PROJECT - Garfield County, Colorado Sponsored by Mobil Oil Corporation, the project will employ underground mining technology tested by Mobil at the Parachute location and one or more different retorting processes. The facility will produce 50,000 BPD of oil shale by 1990. Construction is slated to begin in 1984/5. Loan and price guarantees are requested.

UNION PARACHUTE CREEK PROJECT - Garfield County, Colorado The project is being proposed by the Union Oil Company of California. The project will produce syncrude from shale oil, utilizing the Union-B process. The proposed plant will have an initial production of 10,000 barrels per day by 1983, increasing to 50,000 barrels per day by 1987. Initial plant construction would start in March 1981. A price guarantee is requested.

PACIFIC OIL SHALE - Garfield County, Colorado The proposal is submitted by Cleveland-Cliffs Iron Company, Cleveland, Ohio, a participant in the Pacific Oil Shale Project. Other participants are Standard Oil Company of Ohio and Superior Oil Company. The project utilizes the Superior Oil/Davy McKee technology to produce 45,000 barrels per day of shale oil. Construction of the first 15,000 BPD module is expected in 1983 with completion in 1986. Loan guarantees are requested.

ILLINOIS

MAPCO COAL-TO-METHANOL PROJECT - Carmi , White County, Illinois The project is being proposed by MAPCO Synfuels, Inc. (a subsidiary of MAPCO, Inc.). The project would utilize the Texaco Gasification Process and the low pressure methanol synthesis loop of Lurgi to produce 35,000 bbl/day of methyl fuel. Construction would begin in 1982 with completion in 1986 and operation in 1987. Price supports and a loan guarantee are requested.

1-10 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE 1 (Continued)

CLARK OIL & REFINING PROJECT - St. Clair County, Illinois The Clark Oil and Refining Corporation has proposed a project using indirect liquefaction to produce approximately 12,000 barrels per day of gasoline. Start-up of the facility, to be located east of New Athens, Illinois, is scheduled for 1988. Loan and price guarantees have been requested.

IOWA

BILLINGS ENERGY CORPORATION - Forest City, Iowa The Billings Energy Corporation is sponsoring a project using a Texaco coal gasification process to produce 3.1 billion Btu's per day as hydrogen. Construction would begin in 1983 with initial production estimated for 1985. A grant for further project definition was requested.

KANSAS

CHETOPA - Labette County, Kansas The project is sponsored by EOR Petroleum Company, Denver, Colorado. The project will utilize the TETRA Systems process for heavy oil recovery to produce 480,000 barrels the first year. Construction can begin within 6 months of approval. Full scale production can start 18 months later. Loan guarantees are requested.

KENTUCKY

RIO VERDE ENERGY PROJECT - Edmonson County, Kentucky The Rio Verde Energy Corporation is sponsoring a project to produce 10,000 barrels per day of crude oil from tar sands using in situ combustion methods. Initial production would follow securing financial assistance by two years with full production reached four years later. A combination of loan guarantees and price guarantees is requested.

W.R. GRACE & COMPANY - Henderson, Kentucky The project will use a Texaco gasifier to gasify high-sulfur coal to produce methanol for conversion to high-octane, unleaded gasoline. The production goal is 50,000 barrels of gasoline per day by 1989. Construction is scheduled to begin in 1983 with initial plant operations anticipated in 1987. At this time Grace is the sole sponsor. Loan and price guarantees are requested.

BRECKIMRIDGE PROJECT - Breckinridge County, Kentucky The project is being proposed by the Breckinridge Energy Co., a partnership of Ashland Synthetic Fuels, Inc. and Airco Energy Company, Inc. The project will employ the H-Coal direct liquefaction technology to produce approximately 50,000 BPD of oil equivalent products from high sulfur bituminous Illinois Basin coal. Construction would begin in 1983 and initial production is estimated for 1987. A loan guarantee is requested.

WESTKEN TAR SANDS PROJECT - Edmonson County, Kentucky The Western Petroleum Corporation has proposed a 12,000 barrels per day tar sands project. The project, located in Edmonson County, Kentucky, will use anin situ wet combustion process. Initial production is scheduled to begin in 1982 with full scale production of 12,000 barrels per day to be achieved in 1987. A loan guarantee is requested.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-lI TABLE I (Continued)

LOUISIANA

LOUISIANA GASIFICATION ASSOCIATES - Near Lake Charles, Louisiana The project is a joint venture of six companies including Airco Energy Co., Inc., Bechtel Petroleum, Inc., Cities Services Company, Conoco, Inc., PGP Industries, Inc., and United Energy Resources, Inc. The proposed technology is a Lurgi coal to gas process. The plant would produce 125 billion Btu per day of medium-Btu gas. Projected completion is scheduled for 1987. A loan guarantee is requested.

BELLEVUE - Shreveport, Louisiana The Calvin Billings Company proposes a heavy oil recovery project using principles of the Frasch method of sulphur mining. By using flue gas and steam the Calvin Billings Company plans to recover 900 barrels per day from tar sands, with construction start-up 30 days after financing. A loan guarantee has been requested.

CONVENT METHANOL PROJECT - Convent, Louisiana - Texaco Inc. has proposed a medium Btu coal gasification facility, using the Texaco coal gaifiàtion process. - The-project- will produce about 3,500 tons per day of methanol. The sponsor request loan guarantees.

GULF STATES UTILITY PROJECT - Calcasieu, Louisiana The project is a venture of Gulf States Utilities, a partnership that includes potential customers, product distributors, transporters and design and engineering firms, with Westinghouse Electric Corp. as a sponsor. The plant will use the Westinghouse fluidized bed coal gasification technology to produce coal derived medium Btu gas fuel from Wyoming coal to generate approximately 100 MW of electricity. Construction start-up is scheduled for 1983 with initial production in approximately 1985. Loan guarantees and price guarantees have been requested.

MASSACHUSETTS

EG&G PROJECT - Fall River, Massachusetts EG&G, Inc. is sponsoring a project using a Texaco coal gasification process to produce 758,000 gallons per day of methanol and 13,000 megawatt hours per day of electric power. Construction would begin in 1983 and commercial production is estimated to start in 1988. A loan guarantee is requested.

MONTANA

CROW INDIAN TRIBE PROJECT - Crow Reservation, Montana The Crow Indian Tribe is sponsoring a high Btu coal gasification project using Lurgi gasification technology. The project would produce 125 MM SCF per day. Construction would begin about two years after a decision by participants to proceed and three additional years of construction would be required to reach initial production. Loan guarantees are requested.

PHECOM ALTERNATIVE FUELS PROJECT - Miles City, Montana The Pacific Hydrocarbon Energy Company (PHECOM) is sponsoring a project to produce beneficiated coal-oil mixtures to be shipped to Pacific coast utilities. It would produce 15,500,000 tons per year of the coal-oil mixtures. Construction would begin in 1983 and initial production is estimated for 1986. Loan guarantees and price guarantees are requested.

TENNECO COAL GASIFICATION PROJECT - Wibaux County, Montana The Tenneco Coal Gasification Company has proposed a coal (lignite) gasification facility which will produce the equivalent of 43,000 barrels of oil per day. The facility will be located near Wibaux, in Wibaux County, Montana. The project sponsor is seeking a loan guarantee for 75% of project capital costs. Projection is expected in late 1988.

1-12 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE I (Continued)

NEW MEXICO

GRANTS PROJECT - Grants, New Mexico Energy Transition Corporation is proposing to build a 50 million gallon per year coal to methanol plant. The project sponsor has requested a price guarantee from the Corporation.

NORTH CAROLINA

PEAT TO METHANOL PROJECT - Creswell, North Carolina The Energy Transition Corporation is sponsoring a project to convert peat to methanol using KBW gasification technology. The project would produce 156,000 gallons per day of methanol. Construction would begin in 1982 and initial production is estimated for 1984. Price guarantees have been requested.

NORTH DAKOTA

GREAT PLAINS GASIFICATION ASSOCIATES PROJECT Mercer County, North Dokata American Natural Resources is sponsoring a high Btu coal gasification project employing a Lurgi gasifier. The project would produce 137.5 NMSCF/day of SNG. Construction has started under previous agreements with the Department of Energy. Loan guarantees have been requested.

OREGON

NICES PROJECT - Near Beardner, Oregon The project is being proposed by Northwest Pipeline Corporation. The plant will produce 250 million cubic feet of high Btu gas per day to be used in an Integrated Gasification Combined Cycle Electric Generator. The plant would come on line initially in 1985 with full production in 1990. Loan guarantees are requested.

PENNSYLVANIA

AC VALLEY CORPORATION PROJECT - Vanango County, Pennsylvania ThTAC Valley Corporation proposes to construct and operate a 10,000 barrel per day coal liquefaction project to be located north of Lisbon, Vanango County, Pennsylvania. A combination of Coppers gasification, IC! methanol synthesis and Mobil methanol conversion will be used to convert local coal resources into gasoline. Start up is expected in 1986.

KEYSTONE PROJECT - Cambria and Somerset Counties, Pennsylvania TheWfguioj Electric Company is sponsoring a project to employ the Westinghouse coal gasification technology to produce 100,000 barrels per day of methanol via indirect liquefaction processes. Construction would begin in about two years and initial production is estimated three years later. Loan guarantees are requested.

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 - 1-13 TABLE I (Continued)

TENNESSEE

MEMPHIS LIGHT, GAS & WATER PROJECT - Shelby County, Tennessee City of Memphis (Light, Gas and Water Division) has proposed a 50 billion Btu per day medium Btu industrial gas project using the U-gas technology. Construction of the facility, located adjacent to the Mississippi River in Shelby County, Tennessee, is anticipated to start in late spring of 1981 with operation scheduled for January 10, 1985. A loan guarantee is requested.

TENNESSEE SYNFUELS ASSOCIATES - Oak Ridge, Tennessee The project is a joint venture of Coppers Synfuels Corporation, a wholly- owned subsidiary of Coppers Company, Inc., and Citgo Synfuels, Inc., a wholly-owned subsidiary of Cities Service Company. The technology to be employed involves coal conversion to gasoline using KBW gasifiers, Pullman Kellogg methanol synthesis and the Mobil MTG catalytic process. The proposed project has a production goal of 50,000 BPD oil equivalent product. Con- struction would begin in 1982 and initial production is scheduled for 1985. Loan guarantees and price guarantees are requested.

TEXAS

TRANSCO ENERGY COMPANY PROJECT - Franklin, Texas The Transco Energy Company is sponsoring a medium-Btu coal gasification project employing Lurgi gasifiers. The project would produce 125 billion Btu's per day (21,600 BO[/day). Construction would begin in 1985 and production is estimated to begin in 1989. Loan guarantees are requested.

UTAH

GREAT NATIONAL PROJECT - Sunnyside, Utah The project is sponsored by Great National Corporation, Dallas, Texas. It will process tar sands to produce 10,000 BBL/day of synthetic crude. Production can begin in 1984. Loan guarantees are requested.

C&A COMPANIES, INC. TAR SANDS PROJECT - Grand County, Utah C&A Companies has proposed a 20,000 barrel per day tar sands facility for PR Spring Deposit, Grand County, Utah. The facility will be constructed by way of four 5,000 barrel per day nodules, the first of which will be on-line by 1983. The Mineral Research limited (MRL) solvent extraction process will be used at the facility.

SYNTANA-UTAH - Uintah County, The project is a joint venture of the Synthetic Oil Corporation and Quintana Mineral Corporation. It will employ an indirect/direct heated shale oil retort to produce refinable shale oil. Construction is scheduled to begin in 1984 with initial production of 16,500 OPO to be scaled-up to 50,000 GPO in the early 1990's. A loan guarantee is requested.

WHITE RIVER SHALE PROJECT - Uintah County, Utah Phillips Petroleum Company and Sunoco Energy Development Company, are two of three project sponsors proposing to produce shale oil using Superior and Union surface retorting technologies. The project would produce 16,120 barrels per day. Construction would begin in 1981 and initial production is scheduled for 1985. Loan guarantees have been requested.

COTTONWOOD WASH PROJECT - Uintah County, Utah Magic Circle Energy Corporation has proposed a project using the 73 retorting process developed by Science Applications to produce oil from shale. Initial production is scheduled for October 1986 at the facility to be located in Township 10 South in Utah. Full scale production is scheduled for February 1988 and will achieve 30,000 barrels per day of output. A loan guarantee and purchase agreement have been requested.

1-14 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE I (Continued)

PLATEAU PROJECT - Duchesne County, Utah PTiieau, Inc., a wholly-owned subsidiary of Suburban Propane Gas Corporation, has proposed a raw shale oil upgrading and refining project at its Roosevelt, Utah, refinery. The facility will produce 20,000 barrels per calender day of products including JP-4, gasoline and diesel fuel. A loan guarantee, product purchase agreements and price guarantees have been requested.

PARAHO LITE COMMERCIAL SHALE OIL FACILITY - Uintah County, Utah Thisis a joint venture of the Paraho Development Corporation and design program sponsors. The project will use the Paraho surface retorting technology to produce 30,000 BPD of shale oil. Construction start-up is scheduled to begin by mid 1982 with full operation by mid-1986. Price and loan guarantees are requested.

EMERY SYNFUELS PROJECT - Emery County, Utah Emery Synfuels Associates proposes a project to use the Lurgi dry-bottom gasification technology for the indirect conversion of coal to methanol and high Btu gas. The production goal is 389 million gallons per year of methanol and 22.7 billion SFC per year of high Btu gas (21,500 barrels/day oil equivalent). A loan guarantee is requested.

AARIAN DEVELOPMENT PROJECT - Vernal, Utah Aarian Development Incorporated is sponsoring a p roject to produce oil from tar sands using an ADI solvent extraction process. It would produce 20,000 barrels of bitumen per day. Construction would begin in 1982 and initial production would begin later that year with full production reached in 1986. Loan guarantees and price guarantees ar, requested.

VIRGINIA

WHITEHORNE COAL GASIFICATION PROJECT, Montaoanery County, Virginia consortium Norfolk and Western Railway Com- pany and United Coal Company, has proposed a coal-to-methanol-to_Qasoline facility to be located near Longshoo and McCoy in Montgomery County, Virginia. The project, which is scheduled to start operation in mid-1988 will oroduce 23,000 barrels per day of gasoline. Loan and price ouarantees have been requested.

TRISMEGISTUS PROJECT - Chesterfield County, Virginia D.A. Matthews has proposed a coal g asification/liquefaction facility with a commercial production capacity of 3.9 million gallons of gasoline per day plus pipeline natural gas. The plant is to be located in Meadowville, Virginia. Price guarantees are requested.

WEST VIRG:NIA

OHIO VALLEY SYNTHETIC FUELS PROJECT - Mason County, West Virginia CNG Energy Company, adivision within the Consolidated Natural Gas System, has proposed for its share of the Ohio Valley Project. The Project is a joint venture of Consolidated Natural Gas with the Standard Oil ConDany (SOWn)) as participating partner. The facility will be located near Pt. Pleasant, West Virginia and is anticipated to start production in July of 1936. A combination of the Texaco and DGC/Lurgi Slaggin g coal gasification processes will be used. Price guarantees, purchase agreements and/or loan guarantees have been requested for consideration.

UNITED SHALE OIL - West Virginia United States Shale Oil, Inc. is proposing to develop the Everman Retort Process for producing shale oil. The technology would produce a 3 BPD as a pilot plant and 120 BPD as a corirlercial plant. A pilot plant would be completed in 1981 and cortiercial production would benin a year later. A loan guarantee is requested.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-15 TABLE I (Continued)

FAIRMONT COAL GASIFICATION TRIGENERATION PROJECT - Fairmont, West Virginia The Westinghouse Electric Corporation is sponsorina a project that would employ the Westinghouse coal gasificatici technologyt o produce medium Btu gas in amounts equivalent to 2,560 barrels of oil per day. Construction would begin in 1981 and initial production is estimated for 1985. Loan guarantees are requested.

WYOMING

WYOMING COAL CONVERSION PROJECT - Wycoalgas, Inc., proposed to construct a high Btu coal gasification facility to be located 16 miles northeast of Douglas, Converse County, Wyoming. The facility will produce 300 MM SCFD, the equivalent of 50,000 barrels of oil per day. Project sponsors are requesting a loan guarantee from SEC.

WORLD ENERGY INC., PROJECT - Wor l d Energy, Inc., of Laramie, Wyoming, proposes to construct an underground coal gasification project to be combined with a coal liquefaction phase to produce refinable liquid fuels. —Although the site for the facility has yet to be determined, it will be located in the Great Divide Basin of Wyominq, near the towns of Rawlins and Wamsutler. Plant start-up is projected for 1935. A loan guarantee and price supports have been requested of SFC.

HAMPSHIRE ENERGY - Gillette, Wyoming The project is a venture of Kaneb Service, Inc., Ko ppers Company, Inc. and the Northwestern Mutual Life Insurance Company. It involves coal conversion to gasoline using <8W and Lurgi nasifiers, methanol synthesis, and the Mobil MTG catalytic process and would produce 19,377 OPO of unleaded gasoline. Construction would beoin in 1982 and initial production Is scheduled for 1985. Price and loan guarantees are requested.

UNDETERMINED

SE SC 0 Solid Energy Systems Corporation has proposed a project to produce acetylene from calcium carbide derived from coal. The facility proposed would be capable of producing 23,000 tons per day of commercial grade calcium carbide.

1-16 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 SYNTHETIC FUELS CORPORATION ANNOUNCES and the lowest unit oroduction cost. Production-related INITIAL PROJECT SELECTION GUIDELINES criteria, however, are to be balanced by mandates for diversity, particularly in the pre-1984 period. On April 9. John MeAtee, the Acting Chairman of the U.S. Synthetic Fuels Corporation, released Guidelines on The SFC cannot enter into joint ventures after approval Emerging Issues and Recommendations for Selecting of the comprehensive strategy. Projects for Financial Assistance. Public comment was requested on the initial guidelines. The Corporation is Judgments must be made by the Corporation. For seeking to develop the criteria which initially will be example, it must determine that its assistance to a employed in the project evaluation and selection process. project is necessary, that the recipient is qualified to The initial guidelines were prepared b undertake such development, and whether or not priority y the staff of the considerations be given to a project. Preference is to be Corporation, and will be reviewed by the Corporations Board of Directors, when appointed given to projects which involve the least financial assistance. Appropriate security and collateral are to be provided to ensure repayment of obligations. As authorized by the Energy Security Act of 1980 (P.L. 96-294). the Corporation may p rovide several forms of Specific requirements for various forms of financial financial assistance to synthetic fuels projects. These assistance include: forms include price guarantees, purchase agreements. loan guarantees, loans, and joint ventures. Price guarantees - "cost plus" arrangements cannot be used in determining sales price in Current appropriations permit the SFC to obligate up to connection with price guarantees. $6 billion. An additional $6.212 billion may become available to the Corporation after June 30, 1982. To the Purchase agreements - the SFC may not extent that the Department of Energy does not use funds commit to a sales price which exceeds the appropriated to it under the Federal Non-Nuclear Energy estimated prevailing market price. Provision Research and Development Act (P.L. 93-577) and the must be made for renegotiation within ten Defense Production Act for price and loan guarantees, years. up to $5 billion of these funds should be transferred from DOE to the SFC on June 30, 1981. Loan guarantees - no guarantee may exceed 75 percent of the initial estimated cost of The role of the SFC is to provide financial assistance to the project. If the project experiences cost the fledgling synthetic fuels industries as a supplement overruns, the SFC may guarantee no more to the conventional financial markets for the purpose of than 50 percent of such overruns (subject to achieving the national production goals for synthetic availability of funds). An annual fee of 0.5 fuels (soo,000 bid oil equivalent by 1987, and 2.000,000 percent of the amount of guarantee is pa b/doe 1992). y by -able to the SFC. The maturity of the guarantee cannot exceed 30 years or the useful life Statutory Framework for Project Assistance Reviewed of the project (whichever is less).

For any project to receive financial assistance from the Loans - SFC cannot make loans which SFC, that project must produce "synthetic fuel." The exceed the lesser of 49 percent of the total Act then defines synthetic fuel to mean "an y solid, initial estimated project cost or a minority liquid, gas, or combination thereof which can be used as financial position in the project, unless spon- petroleum or natural gas substitute and which is pro- sor demonstrates that a larger percentage is duced in a particular manner from coal (including peat), essential. In no event may a loan exceed 75 shale, tar sands or water as a source of hydrogen." percent of the initial estimated cost. Biomass is specifically excluded. Joint ventures - these are restricted to The Energy Security Act divides the Corporation's synthetic fuel project modules. Modules activities into two stages: must demonstrate feasibility of commercial production, must have the resource base to the period prior to the approval by Congress offer potential for achievement of national of a comprehensive strateg y to achieve the production goals, and be capable of expansion national production goals, and at the same site into a commerical synfuels plant. The SFC cannot finance more than 60 the period following the approval. percent of the project. By law, the Corporation must submit the comprehensive Combinations of financial assistance - the strategy by June 30, 1984. SFC may not award multiple forms of assistance. During both stages, the Act directs the Board of Direc- tors to use production-related criteria to select for Western Hemisphere projects - up to two financial assistance those proposals which are most ad- projects may be assisted outside of the U.S. vantageous in meeting the national production goals for s ynfuels, giving preference to proposals which represent SFC construction projects - the SFC has the least commitment of assistance by the Corporation very limited authority to initiate (prior to

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-17 approval of the comprehensive production The Corporation also announced the establishment of a strategy) up to three construction projects. public reading room, which will be located at the Cor- poration's office at 1200 New Ilampshire Avenue NW., The Corporations Approach to Project Evaluation Is Washington, D.C. The reading room will be open from Analyzed 9:00 a.m., to 5:00 p.m., on working days. The public reading room will contain at the minimum, the following Proposals received by the SFC will undergo a systematic materials: review and evaluation. The review process will consist of two major phases. • Descriptions of the organization, procedures, requirements, and activities of the Corpora- Phase I - In Phase I, the SFC will assess if a proposed tion; project is mature and has a reasonable prospect of receiving financial assistance from the Corporation. • Public summaries of all applications for financial assistance filed with the Corpora- Phase U - In Phase II, the SFC will assess such proposals tion; in greater detail. This may involve requests for additional information. • List of all recipients of financial assistance from the Corporation: During Phases I and II, the SEC will evaluate the merits of projects on the basis of criteria segregated into three • Approved minutes of every public board areas of concern: meeting of the Corporation except those portions withheld by the Board pursuant to sec- The project must be technically viable and tion 116(0(2) of the Energy Security Act: properly managed. • All Corporation press releases and transcripts It must demonstrate good prospects for eco- of all public conferences sponsored by the nomic viability. Corporation; The project must be acceptable in terms of • Copies of all testimony or speeches given by its environmental, regulatory, and socio- officers or directors of the Corporation act- economic aspects. ing in that capacity; The final awarding of any financial assistance b y the • All public reports and other public documents Corporation to projects submitted to the Corporation transmitted by the Corporation to Congress will require approval by the Board of Directors. including all quarterly and annual reports; • All public Corporation statements of policy and public interpretations of the Energy Se- SYNTHETIC FUELS CORPORATION ISSUES INTERIM curity Act; GUIDELINES ON DISCLOSURE AND CONFIDENTIALITY • Copies of all Federal Register notices issued by the Corporation: and On April 14. 1981, the U.S. Synthetic Fuels Corporation (SFC) published its Interim Guidelines on Disclosure and • Copies of all solicitations for proposals issued Confidentialit y in the Federal Register, at pages 21895- by the Corporation. 21897 inclusive. Public comment was invited. Submitters May Request Confidentiality These Interim Guidelines were implemented to carry out the requirements of section 121 of the U.S. Synthetic Any person who submits records to the Corporation may Fuels Corporation Act of 1980 (P.L. 96-294) relating to seek confidential treatment of marked portions of those public access to information. The Guidelines concern records on the basis of 18 U.S.C. 1905 (the Trade Secrets policies and procedures with regard to submission of Act), 5 U.S.C. 552(b) (the exemptions from the Freedom records to the SEC by applicants for financial assistance, of Information Act), or any other Federal law expressly and requests for records in the possession of the SFC by applicable to the Corporation, in order to facilitate the organizations and individuals. Corporation's compliance with these laws. The responsibility for these matters will be vested At the time records are submitted to the Corporation, primarily in the Corporation's Information Officer, Ms. the submitter must place the mark of "confidential" in a Dorothy Weed, Director of the Information Center, Uni- prominent manner on each page orsegregable portion of ted States Synthetic Fuels Corporation, Suite 460, 1200 each page for which confidential treatment is sought. New Hampshire Avenue NW., Washington, D.C. 20586. The cover of any record containing any confidential markings must also prominently display the name, ad- The Corporation's Board of Directors, when appointed, dress, and telephone number of an individual associated will review the Interim Guidelines and make changes in with the submitter who can be contacted on short notice light of public experience gained with administering the by the Corporation with regard to the confidential Interim Guidelines pending such review. markings.

1-18 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 While the Corporation will not generally require a justi- liquefaction, high-Btu coal gasification, low- and fication for the confidential markings at the time medium-Btu coal gasification, and oil shale. GAO did records are submitted, it reserves the right to do so in not examine in detail awards in the other technologies. appropriate situations. Submitters should not automati- In reviewing DOE's efforts, GAO obtained information cally mark as confidential every page of a proposal for from DOE officials and reviewed program and project financial assistance except for the required public sum- selection documents, but did not review individual pro- mary. posals to evaluate their merits.

Requests for Documents Must Be in Writing Each proposal made by companies in response to DOE's solicitation received a technical and cost evaluation by Any persons who wishes to obtain a copy of any record DOE technical evaluation teams and "Source Evaluation submitted to or generated by the Corporation which is Boards." The GAO reviewed the organization of the not available in the public reading room must file a evaluation teams and Boards and the procedures and written request with the Information Officer. The criteria they used in examining applications for feasi- Corporation will not process oral or anonymous requests bility studies and cooperative agreements. The GAO was for records, nor will it assure that requests addressed to favorably impressed with this review and reported that, other offices in the Corporation will be processed "We believe that the work performed by the evaluation teams and the oversight provided by the Source Evalua- Every request must be marked as a section 121 request. tion Boards was reasonably comprehensive and thorough. It must include the name, address, and phone number of It appears that the teams and Boards ranked proposals a contact person and must specify to the maximum with heavy emphasis on their potential commercial via- degree feasible, each record requested A request should bility. In our opinion, the criteria used to evaluate the include, if possible, the specific event or action to which proposals were reasonable and appeared to be applied the request refers, the t ype of record (such as an consistently." The GAO noted also that the officials of application or report), the Corporation personnel or energy companies with whom they met generally said outside parties who authored the record, the approxi- that the evaluation teams and Source Evaluation Boards mate date the record was prepared or submitted to the had done an excellent job in evaluating their proposals, Corporation, and citations to newspapers or publications especially in view of the short time available to them. which have mentioned the record. A "Senior Review Board" was responsible for recom- If a request for any type of record is denied, the mending specific proposals for funding to the selected Information Officer will mail a denial letter to the official. DOE's Under Secretary. The Board reviewed requester. That letter will indicate the legal basis of the reports of the Source Evaluation Boards and support- such denial and will inform the requestor of its right of ing evaluation teams and applied certain program policy appeal. factors in recommending projects for funding. This was the first level at which the program policy factors were considered. According to the solicitation, program policy factors are ". . . those factors which, while not GAO GIVES DOE GOOD MARKS ON SELECTION OF appropriate indicators of a proposal's individual merit PROJECTS FOR THE ALTERNATE FUELS PROGRAM (e.g., technical excellence, proposer's ability, cost, etc.), are relevant and essential to the process of choosing U.S. Representative John Dingell. Chairman of the which of the proposals received will, taken together, House Subcommittee on Energy and Power, requested best achieve the program objectives." that the General Accounting Office (GAO) review and report on the Department of Energy's management of The program policy factors were assigned no priority; the Alternative Fuels Program and the broader issue of DOE officials could appl y any or none of the policy the effectiveness of DOE's other ongoing efforts to factors in choosing among the proposals ranked by the advance synthetic fuels technologies to commercial pro- evaluation teams and Boards. According to the selection duction. statement, the Senior Review Board and selecting official used only four of the eight factors available in In response to this request, the GAO prepared Report developing their recommendations and selections. Ac- Number EM D-8 1-36 to the House Subcommittee entitled cording to agency officials, these factors were applied "Special Care Needed in Selecting Projects for the after reviewing the technical scores and ranking of the Alternative Fuels Program." proposals. The selecting official cited the program policy factors of geographic diversit y, technical divers- At the time the GAO report was completed, the DOE ity, cost considerations, and the desire to involve small was authorized to provide various forms of financial and disadvantaged businesses and/or Indian Tribes in the assistance to expedite the commercial production of program as reasons for selecting oror not selecting pro- alternative fuels from such sources as coal, oil shale, tar jects in accordance with their ranking. In sands, and biomass. and DOE had 113 proposed projects some cases more than one of these factors was cited. for awards totaling about $200 million in response to solicitations issued February 25, 1980. In the cooperative agreements area, only two projects were approved for funding in the four technologies The GAO reviewed the procedures and criteria used by reviewed—one each in coal liquefaction and high-Btu DOE to solicit, evaluate, and select the projects of the gasification. The technical evaluation teams and Source Alternative Fuels Program. The review, which covered Evaluation Board ranked both proposals the highest of the period February 25, 1980, through November 30, their respective technologies and the Senior Review 1980, focused on the proposals and awards for coal Board recommended both for funding.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-19 The feasibility study projects which the Senior Review Three Stages Comprise the Joint Review Process Board and selecting official chose differed substantially from the rankings developed by the evaluation teams and Stage I - Decision: Source Evaluation Board. The application of two of the eight factors—geographic diversity and technical mix— Since the JRP is a voluntary process. Stage I may he weighed heavily in the final selection of projects for initiated only by the proponent of a project. Once a request has been made by a project proponent, a decision feasibility study funding and generallyy accounted for this difference for the four technolog areas examined. must be made by the Executive Directors of relevant DOE, in choosing the 21 projects, passed over 15 projects state agencies based on consultation with other relevant which had received higher technical scores than some of parties (e.g., agencies and individuals) about whether the those selected. However, all of the projects selected project qualifies for Joint Review. received relatively high technical scores. Conducting the JRP will require a substantial commitment from the Joint Review Staff in the Department of Natural Resources, coordinating agencies at all three COLORADO ISSUES ITS JOINT REVIEW PROCESS levels of government, and the proponent. Most govern- MANUAL GOVERNING PROJECT PERMITTING mental agencies, including DNR, are not staffed to conduct Joint Reviews of every proposed energy and Colorado's Department of Natural Resources has just mineral resource development project. Consequently the published in final form its manual entitled "Colorado's State, since it is the administrator and facilitator of the Joint Review Process for Major Energy and Mineral Joint Review Process, must be judicious about the num- Resource Development Projects." - ber of projects it accepts for Joint Review. Stage I procedures provide a method of screening projects. The Colorado Joint Review Process (JRP) is a system Three criteria influence screening decisions. They arc: - designed to coordinate regulatory and administrative reviews conducted by the Federal, State, and local levels A proposed project should fit within the defi- of government, thus expediting those review processes nition of a "Major Energy and Mineral Re- and improving the quality of project planning and review. source Development Project." Major projects It provides the public and industry with increased oppor- include, but are not limited to, metals mining tunity to become involved with government in the review and milling, uranium mining and milling, oil of a major project. The State Department of Natural shale mining and processing, and/or coal min- Resources is to be congratulated on its development of ing; and may also apply to coal gasification. this time and cost saving cooperative plan which organ- coal liquefaction, petroleum upgrading facili- izes a complex set of requirements in a way that allows ties, and refineries. They also require major project proponents, the public, and the several govern- government actions by two or more levels of ments to operate more efficiently. government, including Federal, state, and/or local levels. Copies of the Joint Review Process manual and copies of a JRP Permit Directory are now available from: A proposed project should be offered for Joint Review in an early project phase. Pro- The Colorado Department of Natural Resources ject phases include designation, exploration. Room 723 design/feasibility, construction, operation. 1313 Sherman Street and post-operation. Denver, Colorado 80203 (Phone: 303/839-3337) State agencies should have the staff capability to meet commitments inherent to a Joint Review Process Summarized JRP. Since these agencies would also have to review major projects under conventional Colorado's newly developed Joint Review process is a review processes, some attention should be voluntary administrative procedure which (1) coordinates given to the time and staff workload savings review and decisionmaking processes between the three using an efficient coordinated review process levels of government and within each level of govern- for a particular project. Nevertheless, atten- ment; (2) provides the general public and special interest tion must be given to the total number of groups with additional opportunities to become involved JRP projects being conducted at one time in all phases of project planning, review, and decision- and their overall effect on the state regula- making; (3) provides informal forums in which govern- tory system. ment, industry, the public, and special interest groups have the opportunity to discuss issues and concerns on a Stage I should require about 24 to 31 days for comple- regular basis; (1) provides industry with an alternative to tion. conventional methods of obtaining required governmental decisions; and (5) promotes conflict resolution Stage II - Organization: through cooperation and compromise. Once a decision has been made to conduct the JRP. several organizational activities must occur to provide a sound framework for Stage Ill (implementation of a Project Decision Schedule). Stage II activities include:

1-20 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981

• Designation of a lead agency by the tion of various reports and studies and antici- Governor; pated dates of application submittal, construction commencement, and operation • Consultations with the other involved levels commencement) serves as the foundation for of government to obtain commitments to the coordinated decision schedule. These participate and designations of lead agencies; model activities are correlated with the government decisionmaking processes and • Signing a Joint Agreement which publicly JRP activities and scheduled on a time-line. commits the Federal, State, and local levels This proposed proponent's schedule provides a of government to participate fully in the more specific basis for scheduling various JRP; governmental actions, public participation events, and JRP activities. • Conducting several JRP Team meetings (about six are recommended) for the purpose Governmental actions are correlated, to the of organizing and planning Stage Ill events; extent possible, with the proponent's proposed schedule, prerequisite governmental • Signing a Statement of Responsibilities which actions, and required time frames. Specific details the responsibilities of each agency components of governmental decisionmaking and the proponent; processes are scheduled to enable coordination of public notices, public hearings or • Conducting several public participation meetings, submission requirements (e.g., events (four are recommended); and various environmental reports), and final decisions. The goal of such coordination is to • Preparation of the JRP Project Decision attempt to sequence events such that final Schedule (PUS). Appendix F of the JRP government decisions occur at or near the manual presents PUS development guidelines. same time, thus enabling the proponent to make timelyc orporate decisions about the It is anticipated that Stage II can be completed in about Proposed project. eight months. However, each Joint Review will be tailored to fit characteristics of the specific project. Public participation events are incorporated Thus. Stage II can be completed in a shorter time, given in this master PUS at critical an app points. Some ropriate set of circumstances. Publi c participation activities are already required by law or regulation, others will be Stage III - Implementation: suggested for consideration during the JRP. Suggested JRP public participation events The Project Decision Schedule (PUS) prepared in Stage II are not intended to be scheduled so as to provides detailed guidelines for coordinating regulatory conflict with legally required events, but processes, public participation events, and JRP admini- rather to enhance public input during the strative processes into one interrelated sequence of review process. events. Four model decision schedules are provided in Stage III of the new Joint Review Process Manual. Each JRP meetings continue on a regular schedule model was prepared for a different hypothetical energy to ensure optimum coordination of govern- or mineral resource development activity: (1) coal mental. public, and corporate activities; to surface mine on all existing federal lease, (2) a private ensure that delays in governmental decision- commercial scale oil shale development on private lands making are minimized; and to provide stabil- with private mineral ownership partially funded by the ity to the coordination effort. U.S. Department of Energy, (3) a uranium mine and mill complex on National Forest lands, and (4) a metal mine Stage Ill, for very major projects, could require 30 to 40 and mill complex on National Forest lands. Flow charts months. and general explanations are provided in the manual to describe each model. However, each model PUS is just JRP Ma y Serve as Model for Use by Other States that: a model depicting an imaginary project and review schedule. In reality each specific PDS will reflect time Colorado received a grant from the DOE to develop the frames dictated by the company's schedule in relation- intergovernmental review process, of which the JRP is ship to each agency's schedules. Some real-case sche- the product. One objective was to design a simplified, dules will be much shorter while others will be longer. coordinated permitting process that could be adapted for Generally, each model is comprised as follows: use by any state. The elimination of unnecessary steps and the cooperative coordination of necessary steps are Project phases serve as the organizational the major virtues of the JRP. framework within which the scheduling of specific development, regulatory, public Colorado Permit Directory Also Available participation, and JRP activities are arranged. To accompany the Joint Review Process Manual, the Colorado Department of Revenue offers a Colorado The proponent's hypothetical schedule of Permit Directory. Copies may be obtained from the specific project planning, design, and feasi- office address shown previously in this article. bility activities (i.e., preparation and eomple-

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-21 The Permit Directory contains concise descriptions of will also use Victorian brown coal. A 5 t/d test plant is each permit necessary to build a major energy or mineral in operation in Kyushu, and a 6,000 t/d plant will be built resource development facility - county, state, and by 1986 in Australia. A related article appears in the Federal. "Coal" section of this issue of the CameronSynthetic Fuels Report. The Japanese also cooperate in other Three Synfuels Projects in Colorado Have Requested international projects, such as SRC-II and EDS in the JRP Guidance United States. The Government's "Sunshine Project" will give support to various projects expected to yield Three major synthetic fuel project sponsors have made 260,000 bid by 1990 and 480.000 b/d by 1995. requests to the Colorado Department of Natural Re- sources to participate in the Joint Review Process Concerning methanol. Japan's Ministry of International scheme for obtaining necessary permits. The projects Trade and Industry has a 5-year program to convert are: existing power plants to methanol fuel. Some $59 million U.S. is budgeted for this purpose. Coal gasifica- W.R. Grace & Company, for a 5,000 ton/day tion is the probable technology involved coal-to-methanol plant in the Axial Basin area of Moffat County. Ethanol from biomass in Southeast Asian countries is expected to be investigated Rio Blanco Oil Shale Company for a 4.400 ton/day Lurgi oil shale retorting operation. For development of oil sands, two Japanese companies are taking part in proposed ventures in Canada. Multi-Minerals Corporation for a naheolite- bearing oil shale processing plant. Concerning oil shale, the Japan National Oil Corporation is studying cooperative-developments on deposits located in Australia, China, and Brazil. Details appear on page 2-4 of the March 1981 issue of the Cameron Synthetic JAPAN SHOWS INCREASED INTERESTS IN Fuels Report. SYNTHETIC FUELS Most of the projects are still in the initial stage of Japan is much more dependent upon imported oil than research. The New Energy Development Organization are other major oil consuming nations. As Japans hopes to advance quickly to effective project develop- dependence is practically 100 percent. any adverse ment status as soon as possible. changes in the oil supply situation would impact more seriously on Japan than on other nations. To effectively counter OPEC, Mr. Ikuta believes that the free world should develop 8 to 10 million bid production During 1980, the Japanese Diet approved a bill to of synfuels by the year 2000. promote the development of sources of alternative energy supplies. An entity known as "The New Energy Development Organization" was created by the joint investments of Government and industry. The Organiza- tion is designed to provide financial assistance for development of alternative energy sources. Projects involving coal gasification, coal liquefaction, oil shale, tar sands, methanol from natural gas, ethanol from biomass, and solar are being considered. Toyoaki Ikuta, President of Japan's Institute of Energy Economics, reviewed the prospects for development of alternative fuels for Japan in a paper presented at the conference in San Francisco in February entitled "Synthetic Fuels: Worldwide Out- look for the 80s." His observation will be summarized. Concerning coal gasification, application of this technology within Japan is constrained by dependence on overseas coal, difficulties in securing proper siting, stringent pollution controls, and an inadequate pipeline network. Building overseas plants for production of liquefied products (Fischer-Tropsch or methanol technologies) and importing the liquids could be a fairly effective strategy in commercialization of gasification technology. Concerning coal liquefaction, two private projects are important; that of Japan Brown Coal Liquefaction, Ltd. and that of Mitsui Coal Liquefaction, Ltd. The former is designed to produce a light fuel oil from Victorian brown coal in Australia. A 50 t/d test plant and a 5.000 t/d demonstration plant are due onstream in 1982 and 1985. The latter project will produce SRC for electrodes, and

1-22 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 U.S. GOVERNMENT SYNTHETIC FUELS PROCUREMENT NOTICES LISTED This listing of U.S. Government synthetic fuels procurement notices was excerpted from notices published in the Commerce Business Daily during the period February 2, 1980 through April 1, 1981. U.S. Department of Energy DEVELOPMENT SYSTEM MAINTENANCE AND OPERATION OF THE NAVY SYNTHETIC FUEL RESEARCH FILE. Negotiations with Battelle Columbus Laboratories.

MARKET STUDY ON VALVES FOR SYNTHETIC FUELS-1 Study—RFQ not available. Negotiations conducted on a sole-source basis with TRW, Incorporated for a Conceptual Design for a 543 MW(t) Coal-Fired MUD Combustor.

• ENGINEERING SUPPORT AND TECHNICAL EVALUATION OF DOE/GAS RESEARCH INSTITUTE (GRI) COMBINED HIGH-BTU GASIFICATION PROGRAM. Engineering support services for those programs being co- funded under the Department of Energy Gas Research Institute (GRI) high-Btu coal gasification program. The major areas of work will include the continuing review and evaluation of PDU and pilot plant operations; mechanical design studies; process studies (unit operations); preparation of conceptual commercial designs which will include comprehensive economic and process optimization studies; hazards analysis studies of different processes; design reviews, data analysis and engineering evaluations of proposals, cost estimated and contractors progress reports; metals properties council (MPC) program evaluations; and overall program evaluations to provide recommendations to the DOE/GRI, based on technical and economic considerations, as to the programs which show advantages over existing technology.

• INVESTIGATION OF PEAT WET OXIDATION PROCESS. Analysis, bench-scale tests, process concepts, and economic evaluations, to Minnesota Gas Company.

• REVIEW OF INDIRECT LIQUEFACTION ENVIRONMENTAL GUIDELINES. Negotiations being conducted with Mittlehauser Corporation. • DEMONSTRATION OF CATALYTIC COMBUSTION WITH LOW AND MEDIUM BTU GAS. RFP3-378366 will be issued on a non-competitive basis to Westinghouse Electric Corporation.

• NON-STANDARD AGING TESTS ON COAL DERIVED DISTILLATE FUELS. Negotiations with Southwest Research Institute.

• DEVELOPMENT OF OIL SHALE SURFACE MINING COST MODEL. Negotiations with Ketron. Inc.

• ANALYSIS OF APPROXIMATELY 775 TAR SAND CORES. Solicitation available upon written request about February 5, 1981 on first received-first served basis until supply is exhausted • ENGINEERING RESEARCH. Development Contract for Support of METC Coal Conversion Component and Process Development Projects. Negotiations on a sole source basis only with TRW, Inc. • EFFECT OF DEWATERING METHODOLOGY ON THE GASIFICATION CHARACTERISTICS OF PEAT. Negotiations now being conducted with Minnesota Gas Company. • BRAZIL COAL TECHNOLOGY STUDIES REGIONAL COAL GASIFICATION PLANT FEASIBILITY STUDY for the Department of Energy and the U.S. Trade and Development Program, expression of interest is being sought from companies knowledgeable in the studies or design of medium and low Btu coal gasification. Work to be performed consists of a preliminary design study of a gasification plant site to be located in the industrial center in Mogi-Guacu, State of Sao Paulo, Brazil. The plant will produce two million M3 (STP)# of medium Btu gas which will be distributed to serve the needs of energy-intensive industries located in the vicinity of the plant. The preliminary design studies shall include site screening, processing design, facility design, product gas distribution system, adaptability of retrofitting existing combustors in the service area to the use of medium Btu gas in place of oil, as well as project a comparison with same Btu output, but low Btu gasification plant is to be made.

STUDIES OF FRACTURE MECHANICS OF COAL. Negotiations on a sole source basis with West Virginia University, via Task Order under Contract DE-AT21-79MCI1284.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-23 U.S. Environmental Protection Agency

DEVELOP SOURCE APPORTIONMENT METHODS INVOLVING STATISTICAL TECHNIQUES AND CHEMICAL MASS BALANCE FOR SOURCE-RECEPTOR MODELING OF SYNPUEL-RELATED ORGANIC EMISSIONS. The application of apportionment methods to particular source categories will require consideration of such factors as in-plant variability of emissions, similarity of emissions from a given class of sources as well as other classes, meteorology, atomospherie transformation of pollutants, pollutant sinks, particle size distribution and chemical composition, relationships between organic particulates, organic gases, and chemical elements, and the quality and availability of required data.

1-24 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 U.S. GOVERNMENT NOTICES OF PROGRAM INTEREST LISTED The following Notice of Program Interest was published in the Commerce Business Daily by the Department of Energy on February 6, 1981: SUPPORT OF ADVANCE COAL MINING/PREPARATION SYSTEMS RESEARCH AT COLLEGES AND UNI- VERSITIES. Notice of Program Interest FE-NPI-81-003. The Office of Coal Mining in the Department of Energy is interested in research proposals from colleges and universities for research on advanced systems concepts related to coal mining and preparation. The purposes of this overall effort are to investigate novel concepts for improved coal mining and preparation systems, to furnish technical support in the education of graduating seniors in accredited baccalaureate courses in coal mining/preparation research, and to explore new approaches to coal production. The Office of Coal Mining/Department of Energy is particularl y interested in research related to coal mining preparation from the standpoint of mining/preparation systems.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-25 U.S. GOVERNMENT "RESEARCH AND DEVELOPMENT SOURCES SOUGHT' NOTICES LISTED The following notices of Research and Development Notices Sought was published in the Commerce Business Daily by the U.S. Army Research and Development Command on February 2, 1981: IN SITU TREATMENT TECHNOLOGY provide engineering and development services in the form of assigned tasks for the development of In Situ Treatment Technology for treating environmental contamination. A 45- month task order contract is contemplated. Specific tasks may include laboratory testing, pilot testing and small scale field testing. Potential technologies which may be investigated involve developing a method of compost organic contaminated sediment or sludge, and liner compatability testing with organic and inorganic chemicals. Respondees should have capabilities in the following area: (I) chemical engineering, (2) organic chemistry, (3) inorganic chemistry, and (4) microbiology.

1-26 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 U.S. GOVERNMENT SYNTHETIC FUELS CONTRACT AWARDS LISTED This listing of U.S Governmcnt synthetic fuels contract awards was excerpted from notices published in the Commerce Business Daily during the period from February 2. 1981 to April 1, 1981. U.S. Department of Energy

• MOLTEN SALT INTERACTIONS IN COAL PROCESSING. $156,872 Contract NO. DE-AT03-76ER70030 (Aol!) 1/29/81 Rockwell International Energy Systems Group Negotiations have been concluded for a contract modification for continuation of the Molten Salt Interactions in Coal Processing Program for FY81. • STUDY OF STRUCTURAL PARAMETERS AFFECTING SHALE GAS PRODUCTION. Contract DE-AC21- 81MC16360, West Virginia University. Cost reimbursement Contract - $58,296.

• MOLECULAR BIOLOGY OF ENVIRONMENTAL AROMATIC HYDROCARBONS. Modification AOOt to Contract DE-ACO2-80EV1, $175,000, University of Chicago.

• TESTS TO DETERMINE THE EFFECT OF DEWATERING METHODOLOGY ON THE GASIFICATION CHARACTERISTICS OF PEAT. Dollar amount: $230,423. Contr. AC01-76ET10283; Minnesota Gas Company. • EXERCISE OF AN OPTION FOR CONTINUED MANAGEMENT SUPPORT AND SYSTEM ENGINEERING FOR THE NAVAL OIL SHALE RESERVES. Dollar amount: $3,432,129, Contr. AC01-78RA32012, to TRW, Inc., McLean, VA 22101.

• SUPPORT SERVICE FOR COST CALCULATION FOR THE OFFICE OF FUEL CONVERSION. Dollar amount $713,338, Contr.: ACO1-81RG10324, Energy and Environmental Analysis, Inc.

• PREPARATION OF A COAL TECHNICAL DATA BOOK. Dollar amount: $235,865, Contr. AC01-76ET10255. Contractor: Institute of Gas Technology.

• GEOCHEMICAL AND GEOPHYSICAL MODELS OF THE FOSSIL FUEL CARBON DIOXIDE CLIMATE PROBLEM. Contr. DE-AC01-81EV106100, $135,667, New York University.

• PARTICLE SYNTHESIS AND PROPERTIES OF ZEOLITE CATALYSTS FOR SYNTHESIS GAS-GASOLINE CONVERSIONS to Worcester Polytechnic Institute, Worcester, MA 01609, $199,005, Grant DE-FG22-81PC- 40773.

• MECHANISTIC STUDIES OF CARBON MONOXIDE REDUCTION. DE-ACO2-79ER10345.A002, $50,000. Pennsylvania State University.

• ENVIRONMENTAL ASSESSMENT OF HYGAS PROJECT. Solicitation: Ratification, Dollar Amount: $173,543. Contract: ACO1-76ET10261 A005, Awardee: Institute of Gas Technology.

• COMPUTATIONAL TOOLS FOR COMBUSTION. Contract No. DE-AC22-81PC40265 awarded to Babcock & Wilcox Company, in the amount of $707,910.

• MEASUREMENT OF FUNDAMENTAL PROPERTIES CHARACTERIZING COAL MINERALS AND FIRESIDE DEPOSITS. Contract No. DE-AC22-81PC40266 awarded to Babcock & Wilcox Company, $285.851. • DEVELOPMENT OF CATALYSTS FOR THE DIRECT SYNTHESIS OF LIQUID HYDROCARBON FUELS (LHF) FROM SYNGAS awarded to Union Carbide Corporation. $2,384,850, Contract DE-AC22-81PC40077. U.S. Environmental Protection Agency

• FINALIZATION OF POLLUTION GUIDANCE DOCUMENT FOR DIRECT COAL LIQUEFACTION. Contract No. 68-02-3672. $307,367 awarded to TRW Inc.

• EPA ALKALI SCRUBBING TEST FACILITY. Contract No, 68-02-3114, Letter Modification No. 11, RFP No. DU-81-A083, $62,500 awarded to Bechtel National, Inc.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-27

ENVIRONMENT

NATIONAL COMMISSION ON MR QUALITY SUBMITS • honorable Robert T. Stafford. U.S. Senator. ITS FINAL REPORT TO CONGRESS Vermont • Mr. Harold Tso, Director. Environmental The Clean Air Act of 1970 (42 Usc 7401, et seq.), which Protection Commission for the Navajo Tribe, has been the most costly and most controversial of the Window Rock, Arizona environmental protection statutes, is now before Con- gress for consideration of amendments. As mandated by The Congressional mandate directed the National Com- Congress, the National Commission on Air Quality submission on Air Quality to address the following ques- mitted a report to Congress entitled "To Breathe Clean tions: Air: Findings and Recommendations." This report is the product of a three-year study of the Act by the Commis- sion. Presumably. Congress will rely heavily on its • What alternatives are available to current findings and recommendations as changes to the Act are policies that will protect and enhance the considered. quality of the nation's air resources?

The National Commission on Air Quality was established • What are the economic, technical, and envi- under Section 323 of the 1977 amendments to the Clean ronmental consequences of achieving, or not - - - Air Act-(PL 95-95). Congress in that section directed achieving, the purposes of the Act? the Commission to evaluate that Act and examine alter- • What are the differing technological, econo- native ways of achieving its goals of protecting public mic, energy health and public welfare. The NCAQ consisted of , and environmental effects of thirteen commissioners, comprised of four members of controlling oxides of nitrogen from mobile Congress and nine public members appointed by the sources relative to stationary sources? President. Congress designated as Commissioners the • Which air pollutants not presently regulated chairman and ranking minority member (or their Con- may pose a future threat to health or wel- gressional designates) of both the Senate Committee on fare? Environment and Public Works and the House Committee on Interstate and Foreign Commerce (now renamed the • Committee on Energy and Commerce). These two ro what extent are air quality research pro- committees drafted the Clean Air Act and have jurisdic- grams adequate? tion over changes in the law. Of the nine public members, only one could be considered a representative • Do federal, state, and local agencies have the needed resources to implement the Act's proof industry. Commission members were as follows: grams? • Honorable Gary Hart, U.S. Senator. Colorado (Chairman) • To what extent is the reduction of hydrocarbon emissions an adequate or appropriate • Honorable Tom McPherson, State Represen- method to achieve photochemical oxidant tative, Florida (Vice Chairman) standards? • Richard Ayres, Esq., Natural Resources De- fense Council, Washington, D.C. The Commission utilized a staff of 45 people and expended approximately $9 million during its 30-month • Honorable Tom Bradley, Mayor. City of Los effort. Angeles, California • Honorable James T. Broyhill. U.S. Represen- The final report. "To Breathe Clean Air: Findings and tative, North Carolina Recommendations." is organized into five parts. Port I provides a general introduction to the issues, and Part 2 • Dr. Annemarie F. Crocetti, Epidemiologist. presents the Commission's findings and recommenda- New York tions. Part 3 develops a detailed discussion of the • Honorable John D. Dingell, U.S. Representa- accomplishments and limits of specific health and welfare provisions of the Act under the following cate- tive, Michigan gories: • Mr. Edwin Dodd, Chairman, Owens-Illinois, Inc., Toledo, Ohio • Establishment of public health standards. • Honorable Jeanne Malehon, Former County • Institutional relationships and resources. Commissioner, Pinellas County, Florida • Air quality status designation. • Leonard A. Schine, Esq., Westport. Connecti- • Non-attainment program. cut • Prevention of Significant Deterioration (PSD) • Mr. John J. Sheehan, Legislative Director, program. United Steelworkers of America, Washington, D.C. • Mobile source control.

1-28 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 New source performance standards. • Keep in place emission control requirements Enforcement activities. adopted by states in 1979, and all compliance schedules for retrofitting existing sources; Atmospheric transport. Require EPA to provide states with more Part IV examines the economic and energy effects of air guidance on reasonably available control qualit y management and policy. Part 5 presents indivi- measures for retrofitting additional existing dual and supplemental views of the Commissioners. sources of air pollution in areas not meeting air quality standards; The vote to submit the report to Congress was nine in favor (Commissioners Bradley, Broyhill, Dingell, Dodd, • Require new initiatives to control "acid rain," Hart. Malchon. McPherson. Schine, and Tso), three with a significant reduction in sulfur dioxide o pposed (Commissioners Ayres, Crocetti. and Sheehan), emissions in the next 10 years; with one abstention (Commissioner Stafford). • Provide greater flexibility in the Act's NCAQ Makes 109 Recommendation currently rigid enforcement procedures to better encourage voluntary compliance with Of the 109 recommendations of the National Committee air quality requirements and to provide addi- on Air Quality, those which appear to be most significant tional means to enforce against frequent vio- include: lations;

• Reaffirm provisions in the Act calling for the • Limit the Act's requirements for mandatory setting of public health-based national air automobile inspection and maintenance (l&M) quality standards solel y on health grounds. programs to large urban areas with serious without regard to costs; air pollution problems;

• Retain requirements in the Act that major • Direct EPA to establish a fine particulate air new and modified sources of air pollution in quality standard to complement or replace clean air areas apply best available control the existing standard, which covers dust and technology; other particles too large to be inhaled; • Protect visibility in federal Class I areas • Provide simpler, quicker means of reviewing under the "prevention of significant deterio- industrial facilities' air quality permitting ration" (PSD) program; applications:. • Limit PSD Class II to wildlife refuges, • Eliminate unnecessary and redundant federal national recreation areas, national monument reviews of air quality plans devised by local areas, new national parks and wilderness and state agencies: and areas; • Reaffirm all the Act's current statutory • Allow states and Indian Tribes to establish emission standards for automobile and trucks, PSD Class II areas within their borders at except for the automobile carbon monoxide their discretion; standard which would be set at seven grams per mile rather than 3.4 grams per mile. • Eliminate most current Class 11 areas and eliminate the PSD Class Ill category: Costs Appear To Be of No Concern to NCAQ

• Direct the Environmental Protection Agency It is easy to conclude from the Commission's recommen- to proceed more quickly in regulating hazar- dations that the costs of complying with clean air dous and toxic air pollutants, only four of regulations appear to be of no concern to the NCAQ. We which have been specifically regulated so far; hope that Congress will not concur. Tom Alexander, writing in Fortune (May 4, 1981, "A Simpler Path to a • Require the same levels of pollution controls Cleaner Environment"), noted a special irony relating to for new industrial sources in areas meeting cost. He states that " ... for the rallying concept that the standards as in areas not meeting them, produced these laws was ecology - the awarness of the thereby providing increased uniformity and connectedness of things. Far from perceiving any con- more certainty for industrial planning and nection with economics, the prophets of ecology were siting; virtually disdainful of the subject." • Keep the sanctions to be applied to states not following any requirement to meet an air quality standard (the construction moratorium would stilt be mandator y, but the cutoff of federal funds would become discretionary); • Replace statutory nationwide attainment deadlines with an area-by-area approach;

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 1-29 EPA ISSUES EMISSION REDUCTION BANKING By banking and receiving credit for their surplus emis- MANUAL sion reductions, firms will legitimize their hold on these emission reductions. In addition, the future use of these An emission reduction banking system enables firms to emission reductions will be facilitated, because their receive credit for reducing their emissions beyond re- validity and size will already have been confirmed by the quired levels of control. It provides an incentive for air pollution control agency prior to the time when they additional investment in pollution abatement. are sold or applied to a permit application. A number of communities (Louisville, Seattle, San Fran- The manual describes the organization and operation of cisco) have incorporated banking into their regulatory emission reduction banking systems, accounting methods programs. The EPA appears to be encouraging the used, criteria to use, and the relationship of emission concept, as it has issued a publication entitled, "Emission banking and trading. Reduction Banking Manual," through its Office of Plann- ing and Management.

The concept of emission reduction banking is illustrated by Exhibit 1, reproduced from the Emission Reduction Banking Manual. The emission reduction credits which an emitting facility may earn, can be banked for future use or sale. The banked credits may be used for: Offsets—to allow firms to locate and expand In nonattainment areas without degrading- air-quality; Bubbles—to allow existing firms to reduce their costs of meeting current emission limitations; and

Prevention of Significant Deterioration (PS D)—to allow new firms locating in attainment areas to satisfy new source requirements.

Required by SIP p ft ' . j-' Required (yJr (yJt toiss Ion ill,by •'\ Reduction

U NEON I IWLLLU uniION .LUIIIr.ULO ,un,HER MISSION REDUCTION En I 55 Rrnui p tp BY SIP CREATES AN EMISSION CREDITS CAN BE BANKED Prnuciiou CREDIT FOR FUTURE USE DR SALE

FIGURE 1 CREATING AN EMISSION REDUCTION CREDIT

1-30 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 BLM TO PREPARE ONE HIS FOR ALL UINTA BASIN (UTAH) SYNFUELS PROJECTS The Bureau of Land Management, the State of Utah, and local officials are cooperating in a combined program for expediting the processing of anticipated right-of-way applications from synfuels developers for use of public lands in the Uinta Basin of Utah. It is proposed that the BLM cover an firm synfuels project proposals in a single environmental impact statement, thus avoiding the need for preparing separate EIS's one after another. The BLM Vernal District Manager is requesting that all oil shale, tar sands, and related synfuels industries contact the Vernal SLM office if they anticipate a need for a right-of-way across public lands within the next three years. The request was published at page 18 of the March 25, 1981 issue of the Federal Register. The ELM is requesting a formal expres tent to file right- of-way applications.

Completion of the £15 process will require about 12 months after receipt of adequate project descriptions. BLM's goal is to complete the EIS process by the end of May 1982, in order that public land right-of-way decisions can be made for projects planning construction starts in the summer of 1982. Three separate levels will be considered in the proposed EIS. (1) A site specific analysis, sufficient to meet NEPA and permitting requirements, will address those projects which file completed right-of-way applications. (2) A cumulative analysis will address synthetic fuels development on a regional basis and consider impacts of a full scale commercial synthetic fuel industry. (3) A conceptual analysis will address those projects which plan to proceed with development but are not yet prepared to submit detailed right-of-way applications. For this latter group supplemental Environmental Assessment may be required when detailed permit needs are finalized. Further information can be obtained by contacting the BLM Vernal District, 170 South Fifth East, Vernal, Utah 84078 (phone 801/789-1362).

#### SMALL SYNFUELS PLANTS NOW GOVERNED UNDER WYOMING'S INDUSTRIAL SITING ACT

During the 1981 session of the Wyoming legislature, House Bill No. 166 was passed and signed by the governor which places small synfuels plants under the State's Industrial Siting Act. Any plant capable of producing 15,000 barrels or more of liquid hydrocarbon products per day by any extraction process involving the direct or indirect conversion of coal, oil shale, or tar sands (or any addition, increasing capacity by 15,000 barrels/day) is now defined as an 'industrial facility" and comes under the regulatory provisions of the Industrial Siting Act.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-31

WATER

ifiA FORMULATING RULES FOR REGULATION OF Utah Water-1980," released in January by the Division of RESERVED WATERS ON INDIAN RESERVATIONS Water Resources, Utah Department of Natural Resources. The Bureau of Indian Affairs proposes to amend Chapter IX of Title 25 of the Code of Federal Regulations by In Utah, First Appropriator Has First Right To Use adding a new Part 260 to provide for tribal regulation of Water reserved waters on Indian reservations. The report, cited in the first paragraph, provides a The BIA first proposed this in 1977 (see the March 17, concise review of Utah water law, resources, present 1977 issue of the Federal Register, pages 14885 - 14887), usage. and State and Federal policies. Concerning water but apparent legal and practical difficulties with the law in Utah, the right to use water is based on the proposed rules prevented them from being issued in final doctrine of prior appropriation, which provides that the form. In the January 5, 1981 issue of the Federal first appropriator in time is first in right. Prior to 1903, Register, at pages 944 - 946, the BIA published revised the right to use surface water in Utah could be acquired proposed rules. These set forth the criteria the Secre- by simply diverting the water and placing it to beneficial tary will follow in approving tribal water codes and in use. Groundwater could he acquired in that manner prior promulgating a water code where a tribe tails to adopt a to 1935. Since that time, the onl y manner in which a -code. -Comments on the Januar y 5 notice were requested right to use waters of the State can be acquired is by to be submitted by March 5th, but this deadline was filing-an application with the State-Engineer and secllrr extended to June 6, 1981. (See notice in the March 16, ing his approval. 1981 issue of the Federal Register, page 16916). When an application is approved, the applicant is given a The following features highlights the proposed regula- specific time to divert the water and place it to benefi- tions: cial use. For good cause shown, this time may be extended. Once this work is accomplished and proof of • Tribes will be allowed considerable freedom appropriation is submitted, the State Engineer issues in developing individualized water codes. that applicant a certificate of appropriation as evidence of a perfected water right. • Tribes may authorize the use of reserved waters for any "beneficial" use. Such uses A water right in Utah is considered a species of real may include industrial uses. property and is protected as such. The owner of a water right is entitled to sell and transfer the right apart from • Tribal water codes must be limited to the the land upon which it is used. However, in order to reserved waters. accomplish such a change, an application must be filed with the State Engineer, and the State Engineer is • Codes must allow continued use of reserved required to consider whether other rights will be im- water by existing users until an authorized paired by the proposed change before approving or tribal permittee is prepared to make benefi- rejecting it. All rulings of the State Engineer are cial use of the water. subject to appeal in the district courts.

• Codes must exclude from regulation rights to In areas of the State still open to appropriation, there the use of water held by purchasers of land are numerous unapproved applications which, in most within an irrigation project located within a areas, would exceed the available water supply. Further. reservation and administered by the alA. in many of these areas, there are approved but unper- fected applications which could consume much of the • The issuance or transfer of a permit to a non- available unused water supply. member of the tribe requires Secretarial approval. In addition to the State-created water rights discussed above, there exist certain water rights in Utah which have been established under Federal law. These are commonl y known as "reserved" rights, since they have WATER FOR UTAH ENERGY PROJECTS WILL COME their origin in the establishment of a particular Federal FROM PRESENTLY UNUSED RESOURCES reservation. The reserved rights which are of greatest current interest are those relating to Indian reservations. In the vast majority of cases, most water for enegy The United States Supreme Court has held that when the project developments in Utah will not come from con- Federal government set aside an Indian reservation. version of agricultural water for use in the energy water was reserved from those streams traversing the facilities. Rather, the White River Shale Project, the reservation to irrigate land on the reservation. Tosco Sand Wash Project, Paraho's oil shale project. the Deseret Generation Transmission Cooperative thermal plant, and the Allen Warner Valley Energy system all contemplate the joint development of presently unused water resources. This comes from the report, "State of

1-32 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981

Present and Future Consumptive Uses of Water Quanti- Conversion of agricultural water for use in energy- fled related facilities has been described as an unfortunate but inevitable fact. Even if all projected energy-related The present consumptive uses and the consumptive uses water demands were satisfied in this manner, less than of water in the year 2000 in Utah are presented in Table 10 percent of the agricultural water use would be 1. transferred Considering the tremendous gains in employment opportunities and income generation, this Water Usage for Energy Production Examined would appear to be a desirable trade-off. To place the water-for-energy problem in perspective, In the vast majority of cases, though, most water for the Utah Division of Water Resources presented their energy will not come from agriculture. Instead, it will estimate of the consumptive use water requirements of come via joint development of presently unused water the anticipated energy projects in Utah. This is presen- resources. ted as Table 2. The philosophy of the Division of Water Resources is The Division acknowledges that it would be difficult to that undeveloped water resources in Utah are unde- project which of the many energy proposals will be veloped not because the water is not needed, but because carried to completion, but even assuming the most the economics of agriculture do not permit it. A optimistic construction schedule, additional water multipurpose agriculture/energy project, financed in requirements for this use should not exceed 100,000 large part by the energy-related participant, has advan- acre-feet by 1990. tages for all. One principal water for energy activity in Utah must be encouraging partnerships between energy The presently unused Colorado River System water is companies, agricultural water users, and where possible, about 500.000 acre-feet. Against this background, the towns and municipalities. Through this approach, both additional 100,000 acre-feet does not appear over- the water and energy resources of the state can be whelming. Although development of water for a parti- developed with maximum benefits for the entire state. cular energy project may encounter difficult technical or environmental problems, as yet there does not appear to be a physical availability problem in the aggregate.

TABLE 1 WATER USAGE IN UTAH

WATER USED PRESENT 2000 INCREASE (Consumptive Use) (Acre-feet) (% of Total Use) (Acre-feet) (96 of Total Use) (Acre-Feet)

Municipal 145.300 2.5 274,200 4. 3 128,900

Industrial 62,100 1.1 386,400 6.6 357,700

Irrigation & Livestock 2,921,700 51.1 3,067,100 47.9 145,400

Wetlands & Evaporation* 2,426,500 42.5 2,445,300 38.2 18,800

Pubic Lands 158,600 2.8 192.700 3.0 34,100

TOTAL 5,714,200 100.0 6,399,100 100.0 684,900 Does not include evaporation from Great Salt Lake.

TABLE 2 CONSUMPTIVE WATER REQUIREMENTS FOR ENERGY PRODUCTION IN UTAH

Energy System Consumptive Water Requirements Steam-electric Coalfired plant: Evaporative Cooling 15,000 acre-feet/yr/bOO MW Unit Dry Cooling 2,000 acre-feet/yr/bOO MW Unit Coal Gasification 10,000-45,000 acre-feet/yr/250 million SCF/day plant Coal Liquefication 10,000-130,000 acre-feet/yr/100,000 BPD plant Oil Shale 7,600-18,900 acre-feet/yr/100,000 BPD plant

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 1-33 Utah Water Policy Summarized In Utah, state water policy is grounded in state water law, and in the belief that water should be put to the highest beneficial use. Although there is often considerable controversy over what consitutes the highest beneficial use in a particular situation, there appears to be little doubt that the water laws as they exist enjoy considerable popular support. Unlike the Federal government, the State has relatively few direct means with which to affect the direction of water resouces development and management. At present, these are: (I) control over the appropriate process, vested in the State Engineer, (2) various environmental laws and regulations, administered by the Bureau of Environmental Health, and (3) provision of financial and technical assistance, handled by the Board of Water Resources. Under Section 73-3-8, the State Engineer may reject an - - - application to appropriate if it will interfere with a more - beneficial use, or if it--will prove- -detrimental, to the - public welfare. Historically, the State Engineer has not exercised this aspect of his authority, since he is also instructed to approve applications if unappropriated water is available. The position of the Federal government relative to water development projects has shifted markedly in recent years. Prior to the passage of the National Environ- mental Policy Act in 1971, development of natural resources, including water, was viewed to be essential to the economic well-being of the nation. With the passage of NEPA began a long series of Federal actions reflecting a belief and philosophy that environmental and aesthetic considerations must be included in the decision-making process. A basic assumption in the new philosophy was that the nation could now afford to forego significant economic benefits if, by doing so, the environment was protected or enhanced. Federal legislation which constrains water development in Utah includes the Clean Water Act, the Clean Air Act, Endangered Species Act, the Fish and Wildlife Coordination Act, the ELM Organic Act, the Wilderness Act, and the Wild and Scenic Rivers Act. In many cases, the public is not really aware of the tremendous impacts that environmental legislation is having on development of water and other natural resources. For example, as the Fish and Wildlife Coordination Act is being administered, any detrimental effects of a water development project on fish and wildlife must be mitigated by measures included in the project, and paid for by the project sponsors. Conflicts involving Federal laws and regulations are serious in states like Utah, where so much land is Federally owned. Nearly every potential water development or management action requires at some point a Federal permit, which, if denied, effectively stops the action. It has proven to be a false hope that if no Federal funds were involved, water development projects would not be delayed by Federal environmental legislation. Unfortunately, legal and administrative interpretation of this legislation is constantly changing.

1-34 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 ENERGY FORECASTS

EXXON UPDATES ITS U.S. AND WORLD ENERGY • Middle East crude oil prices will rise by 50 FORECASTS percent in real terms between 1980 and 2000. Natural gas prices will be governed by the Exxon Company, USA has published two energy fore- Natural Gas Policy Act of 1978. casts.y One of these is entitled "Exxon Company, USA's Energ Outlook: 1980-2000." The other is entitled • Real GNP will grow at a 2.6 percent rate "World Energy Outlook. Both are dated December 1980, through 2000. and both update publications issued one year earlier. • Environmental policies will not prohibit con- Exxon's U.S. Energy Outlook Reviewed struction of major new facilities inherent in the projections of future growth. Exxon Company, USA's Energy Outlook: 1980-2000" not only updates its December 1979 Outlook, but expands it • The U.S. will import increasing amounts of to portray the relationship between energy sources and oil from OPEC countries during the 1980s. their end uses. It compares the need for energy in liquid International energy trade will not be ham- form with the prospects for conventional oil and synthe- pered by economic instability or lack of tic fuels production. The update also presents a discus- international cooperation. sion of the contribution of renewable energy sources. The total U.S. energy demand is projected by Exxon to Exxon's projections for the U.S. are based on several grow at a rate of 0.7 percent annually in the years 1980- basic assumptions, which are: 1990. This rises to 1.2 percent per year in the 1990-2000 period, largely because of energy required for synthetic • Government energy policy will permit econo- fuels production and a decline in the rate of fuel mic growth by establishing a balance among efficiency improvement. The U.S. energy demand by energy, economic, and environmental goals. consuming sector and by the type of fuel consumed is illustrated in Figures 1 and 2, both of which are derived • Domestic crude oil prices will achieve parity from the Exxon report. with world oil prices in 1981.

GROWTH RATES, %/YEAR 60-7373-e080-90 904)0 NONENEROY, 4.1 - 1.3 1.4 MILLION INDUSTRIAL B/DOE 3.7 (0.1) LI 2.0 RES./COMM. 4.0 Os 0.7 0.1 -SHAI TRANSP. 4.1 0.3 (0.3) 0.3 TOTAL 4.1 0.3 0.7 1.2 .7 00 PRE-1973 - TREND - 1- 50 . SHARE -- CONSERVATION

NO NE NE RG Y

40 INDUSTRIAL

30 - RES IDE N TA L/ COMMERCIAL

21 - TRANSPORTATION 0 25 I I I I 1960 1965 1970 1975 1980 lOSS 1990 199 2000 NOTE: ELECTRICAL LOSSES ARE ALLOCATED TO EACH SECTOR

FIGURE 1 U.S. ENERGY DEMAND BY CONSUMING SECTOR

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-35 GROWTH RATES, %/YEAR 60-73 73-80 80.9090200 MILLION HYDRO, GEO. - B/DOE SOLAR 4.0 2.2 3.4 i.e NUCLEAR 40.8 ito 9.1 4.2 COAL 2.3 2.8 2.5 3.6 00 4.4 (1.0) (1.5) (0.3) OIL 4.5 (0.4) OA) (0.0) 50- TOTAL 4.1 0.3 0.7 1.2 SHARE HYDRO, GEO. SOLAR 40 NUCLEAR SHARE 30 COAL

27 20 22 19 GAS

10 45------44 33 —OIL C I I I I I I I I 1960 1908 1970 1976 1980 1955 1990 1995 2000

FIGURE 2 U.S. ENORGY DEMAND BY FUEL CONSUMED

MILLION SIDOE IN PLANNING/DESIGN STAGE

E]UNDERCONSTRUCTION 0 OPERATING - 4 NATIONAL PRODUCTION GOALS' 4 5 4

4. -T S - -

2 FT..

R1962 I1Pv1961 1992 2000 NATIONAL ESTABLISHED IN ENERGY SECURITY ACT FIGURE 3 SYNTHETIC FUELS PRODUCTION CAPACITY

1-36 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 U.S. coal use is forecast to increase substantially over prices are also assumed to increase in real terms, but the 1980-2000 period The increase will be for direct coal is expected to be economically more attractive than burning and for producing synthetic fuels. The absolute oil in a number of uses. The real price of natural gas volume of gas used declines from 10.2 to 8.5 MMB/DOE should rise, also. (million barrels per day of oil equivalent) over the outlook period. Oil's share of total U.S. energy supply World energy demand is expected to grow about 2 1/2 also declines (from 44 percent in 1980 to 33 percent in percent per year. This is less than half the 1965 to 1973 2000), but it remains the largest energy source. energy growth rate. Even at this lower growth rate, world energy demand will increase 65 percent by the The role of synthetic fuels is seen to be important. The year 2000. volumes predicted are believed feasible, by Exxon, if the nation chooses to take advantage of its synthetics poten- It is predicted that only a modest increase in world tial. The production levels envisioned are presented as production of conventional oil will occur. Thus, volumes Figure 3, derived from the Exxon report. The Energy available for international trade are projected to show a Security Act has set national production goals of 0.5 net decline as oil-exporting countries increase domestic MMB/DOE of synthetic liquids and gas by 1987 and 2.0 consumption. Consequently, the industrial countries no MMB/DOE by 1992. Because of the long lead times longer can rely on conventional oil for increases in their required for all types of energy development, actions energy requirements. must be taken in the early 1980s if the Exxon projections are to be realized. Most of the growth in the industrial, residential and commercial sectors, where consumers have a choice of Updated World Energy Outlook Includes Data for USSR, fuels, is projected to come from coal and from nuclear China, and Eastern Europe - energy. Oil use will be concentrated in specialized applications, such as transportation and lubricants. The This year's World Energy Outlook projects energy supply production of synthetic liquid fuels will be needed during and demand through the year 2000 and, for the first the late 1980s and through the 1990s. time, incorporates the centrally planned economies of the USSR, People's Republic of China, and Eastern The transition to reduced demand on oil will be achiev- Europe. able. but will not be easy.

Exxon foresees the real price of energy continuing to Exxon's forecast of world energy demand and world increase during the outlook period. Specifically, the energy supply are shown in Figures 4 and 5. which are price of Middle East crude oil will increase about 50 based on data from the report. percent in real terms between 1980 and 2000. Coal

250

225 VARIABILITY

200 CENTRALLY 3t% PLANNED 175 ECONOMIES

150 30%

24% OTHER 30%

::: JAPAN

EUROPE 0% 3%' 3%\ CANADA

25 UNITED 28% 23% 20 STATES 34% 0 Ins 1970 ipso 1990 2000

MILLION BARRELS/DAY OR EQUIVALENT

FIGURE 4 WORLD ENERGY DEMAND

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-37 260

226 10% NUCLEAR 200 HYDRO & a % OTHER 175

26% COAL 160

126

GASAS

78 SYNTHETICS & VHO

60 OIL 28 - 42% 0 1 1I 1955 1970 1980 1990 2000 MILLION BARRELS/DAY OIL EQUIVALENT

FIGURE 5 WORLD ENERGY SUPPLY

Concerning coal, the Exxon forecast sees it replacing result, they are expected to remain dependent on con- both oil and gas in major industrial and electric utility ventional fuels at least for the rest of the century. markets. Coal use will grow almost 3 percent per year, worldwide, and, considering coal used for synfuels, it will rival oil as the single largest source of energy. SYNTHETIC LIQUIDS PROJECTED TO BECOME THE Nuclear energy use is expected to grow at a 10 percent MAJOR SOURCE OF LIQUID FUELS rate each year. The Energy Information Administration, in its 1980 "Hydropower and other" energy use will increase from 6 Annual Report to Congress, predicts that synthetic to 8 percent of total energy use by the year 2000, with liquids production will become the major source of liquid much of the growth expected in Latin America. fuel for the U.S. by the year 2020. Table I, reproduced from the report, presents this projection along with the Concerning synthetic fuels and very heavy oil, these probability that synthetic liquids are projected to be- energy sources will become a major source of supply come cost competitive with imports by 1995. Also, after growth, particularly in the U.S., Brazil, Venezuela, Aus- the year 2000, growth in synthetic production will com- tralia, and a few other countries. They will supply 4 pensate for the projected decline in domestic crude oil percent of the worlds energy in the year 2000. Produc- production and will replace higher cost oil imports. Even tion of synthetic oil and gas from coal and oil shale is higher synthetic production than is forecast could occur expected to reach about I million barrels per day oil if liquids were to be exported. equivalent by 1990, increasing to 4 million barrels per day, or 9 percent of total energy supply, by 2000. In the EIA forecast, synthetic liquids production includes Exxon's Outlook assumes a major national commitment synthetic crude oil and methanol (converted to gasoline) to synthetic fuels, in line with announced government produced from indirect liquefaction, boiler fuel from goals for 1990. direct hydrogenation (all from coal), and alcohol from biomass. Most of the low-growth countries lack the resources and technological infrastructure necessary to develop syn- Shale oil is projected to be less expensive than coal thetic fuels or the large central electricity grids re- liquids in 2000, and, thus, is the preferred supplement to quired to make efficient use of nuclear energy. As a domestic crude oil. However, projected production of

1-38 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE 1 SENSITIVITY OF LIQUID FUELS SUPPLY TO WORLD OIL PRICE AND HIGH CAPITAL EQUIPMENT COSTS: 2000 AND 2020 (Quadrillion Btu per Year)

ZUUU 2020 Mi Uig Mi High Low Mid Hig OP OF b OF b Lo Mi Hig p b Liquid OF OF OR HCC 11CC OF OF OF 11CC 11CC b Domestic Oil' 19.4 20.6 19.4 21.2 21.2 10.9 9.8 9.8 12.2 11.6 Shale Oil 1.0 1.2 1.2 0.4 0.5 3.1 2.9 2.6 2.8 2.7 Coal Synthetics 1.4 2.0 1.5 0.5 0.4 14.8 14.6 11.3 10.9 9.3 BiomassSynthetics 0.3 0.4 0.4 0.2 0.2 0.8 0.9 0.8 1.1 1.0 Net Oil Imports 10.6 4.6 3.0 6.7 3.4 4.3 1.3 0.9 2.9 0.9 Total Liquids Supply 32.7 28.9 25.6 29.0 25.6 33.9 29.6 25.3 29.9 25.5 a0 = World oil price. bHCC = High capital costs. cEld shale oil. Note: Numbers may not add total due to rounding. shale oil is less than that of coal liquids throughout the CARTER PRESIDENTIAL PANEL REPORT CALLS FOR forecast period, because oil shale is concentrated in a ENERGY CONSERVATION, NOT ENERGY relatively small region of the country whereas coal is PRODUCTION available in many areas. When shale oil costs are increased by 50 percent in the high capital cost case, In October of 1979, then-President Carter established market penetration is delayed,but by 2020 the contribu- the President's Commission for a National Agenda for tion of shale oil is projected to approach that of the the Eighties. His purpose was to provide the President- midprice scenario. elect and the new Congress with the views of 45 Americans drawn from diverse backgrounds. The work- Synthetic liquids are projected to contribute a much ing group selected were alleged to be bipartisan, and larger share than synthetic high-Btu gas because domes- represented business, labor, science, arts, the humani- tic natural gas production can nearly satisfy gas demand, ties, and communications. The work of the Commission whereas domestic crude oil production is projected to was accomplished by nine panels. Each panel considered fall short of liquids demand. Liquid fuel use remains major subjects designated by the President. The final relatively constant over the forecast period. This is report of the Panel on Energy, Natural Resources and because alternative fuels are not projected to replace the Environment has been issued It is entitled "Energy, liquids in the transportation sector nor satisfy the de- Natural Resources and the Environment in the Eighties." mand for petrochemical feedstocks, asphalt, and lubri- cating oils. The principal conclusion in the Panel's report is that U.S. energy policy for the 1980s should be directed toward An alternative which is mentioned, but not discussed in achieving far higher levels of energy efficiency. Energy any detail in the EIA Annual Report, is the conversion of conservation, therefore, should receive the highest natural gas through the M-gasoline process, developed by priority. The Panel further contends that, ". . if public the Mobil Oil Corporation, into liquids suitable for funds are to be invested in the energy sector, they should transportation fuels. Pilot projects have been success- go where they are likely to elicit the greatest and most ful, and a commercial scale plant (12,500 barrels per immediate return - into energy conservation. They day) manufacturing synthetic liquids from natural gas is should not be disbursed to the most costly, and least expected to begin production in 1985 in New Zealand promising, energy technologies." With natural gas costing the equivalent of about $1.08 (U.S. dollars) in New Zealand, the resulting gasoline The Panel then recognizes that improvements in energy costs about $23 per barrel. At these or even higher efficiency will not represent the sole solution to the costs, synthetic liquids from natural gas could compete Nation's energy predicament. It notes that in the event economically with coal-based synthetic liquids, the price of an energy supply interruption, that conservation of which is projected to be $50460 per barrel. measures alone would not be sufficient to cope with the sudden shortages. It suggests that the remedy would be "government-enforced rationing, as well as the use of oil from a well stocked strategic petroleum reserve."

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-39 The Panel concluded also that, "Expectations of an early end to the nation's energy predicament though a surge of new supplies from any single domestic source or combination of sources - nuclear power, oil, natural gas, coal, solar energy in all its forms, or synthetic fuels - have been overblown and unwarranted."

1-40 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 ECONOMICS

STUDY CLAIMS THAT AS OIL PRICES RISE, COSTS OF about $70 per barrel under this analysis, which would NEW SYNFUELS PLANTS RISE PROPORTIONATELY appear patently "uneconomical," compared with oil, now about $40 per barrel. However, to have this plant A report prepared for the House Committee on Science operating at the time when the present oil price doubles and Technology presents the interesting conclusion, as would be an attractive commercial venture. In fact, had oil prices rise, projected costs of producing synfuels such a plant been built about 6 years ago, when oil was from a new planned plant using currently foreseeable $9 per barrel, its product cost of $28 per barrel would be technology increases proportionately. No matter how "economical" today. high the price of oil rises—even to $100 per barrel—a new plant built subsequent to arrival of oil at that price Table 1 summarizes the principal findings of Jelinek's will not be economic as an investment prospect. report. Economic projections are presented in terms of oil price over the range of $9 to $100 per barrel, with This comes from a report entitled "Costs of Synthetic capital and operating costs correspondingly escalated in Fuels in Relation to Oil Prices," which was authored by a base ease for each process. Expressed as dollars per Robert V. Jelinek, a consultant for Environment and equivalent barrel of oil, these projected synfuel cost Natural Resources Policy Division of the Congressional figures show the necessary product selling price for full Research Service. The report is dated February 1981. equity recovery in new plants competitive with other opportunities for capital investment. Jelinek's analysis assumes that the structure of the U.S economy will remain essentially unchanged, and that According to .Jelinek, substantial misunderstanding has design and construction of a new svnfuel plant will take developed over the years on the subject of synfuel longer than the time required for the effects of oil price economies. Early comparison of petroleum refining with rises to ripple through the economy. As the dominant synthetic fuels manufacture, as practiced in Europe source of our energy, oil price "drives" the cost of all during World War II, tended to overlook energ y cost, very modern industry, including synfuels. He contends that low at the time, as a significant input. From these there firm correlation is shown in his study between oil price grew lasting impressions and predictions of synfuel cost and prices of other forms of energy and key commodities in relation to oil price, which now prove to be unrealistic such as steel and cement. As manufacturing plants and misleading. What .Jelinek attempts to do is to become more expensive to build and operate, the costs clarify this thinking and provide more reliable economic of their products rise, including the cost of synfuels. projections based on sound engineering evaluation of synfuel process requirements. His methodology is des- Plant operating costs, however, will increase more cribed in detail in the report slowly than rising oil prices. Consequently, a synfuel plant built at any oil price, with the required capital investment committed, will become progressively more economic with increasing oil prices; its product cost over time will attain parity with oil price. Thus, the sooner a plant is built, the better, assuming continuing oil price escalation.

However, even with continuously increasing oil prices, a synfuels plant would not necessarily appear to be a sound investment from the private sector investor point of view at a given point in time. Without subsidies and assuming any reasonable rate of oil price increase,the length of time between expenditure of the capital investment and recovery of capital from future higher prices may be unattractive, given the current and expected interest rates and the associated "time value of money." If oil prices should stop rising permanently, then no new synthetic fuels venture could be justified economically now or in the foreseeable future.

Jelinek contends that a realistic evaluation of synfuels, therefore, must always look ahead. Today's decision needs to be made in terms of its effect several years hence. The full economic benefit of building a plant now may not be realized for several years in a smoothly running, fully depreciated facility selling synfuel very competitively with the then-current price of oil. For example, under present conditions, a new coal hydrogenation plant could produce synthetic liquid fuel for

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-41 TABLE I ECONOMIC COMPARISON OF PROPOSED SYNFUELS PROCESSES

Oil Price: $1 Barrel 9 30 50 75 100 Projected Synfuel Cost in New Plants: Process $/Barrel of Oil Equivalent

H-Coal (Syncrude Mode) 27.82 61.78 81.60 100.72 117.72 EDS 25.10 55.57 73.88 90.72 105.76 Fischer-Tropsch 62.03 137.41 183.22 227.06 267.13 Lurgi/Methanation 25.15 54.82 72.54 90.47 106.87 Methanol Synthesis from Coal 34.66 76.75 101.77 125.93 147.59 Tosco II Shale Oil 17.11 36.18 49.97 63.75 76.80 Ethanol from Corn 50.03 101.66 125.52 152.76 177.24 NOTES: (t) Figures based on 100% equity recovery. - - (2) Divid&$/BOEby 5.8 to obtain$/MM-Btu. - - -

1-42 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 COMING EVENTS

MAY 31 - JUNE 3, HALIFAX, NOVA SCOTIA - "Coal-Phoenix of the 1980s," a coal symposium scheduled to be held in conjunction with the 64th Chemical Conference and Exhibition of the Canadian Institute of Mining (CIM).

JUNE 8 - 10, DENVER, COLORADO, AT THE BROWN PALACE HOTEL - A conference entitled, "Charting the Course of Western Coal," sponsored by Coal Outlook. Session titles include:

• Western Market Overview • Environmental Regulations • Transportation Outlook • Export Markets • Federal Coal Leasing • Surface Mining Regulation • Domestic Markets

JUNE 8 - 10, SAN FRANCISCO, CALIFORNIA. AT THE SHERATON-PALACE HOTEL - The 5th annual (1981) Symposium on Instrumentation and Control for Fossil Energy Processes, sponsored by the DOE, Argonne National Laboratory, and the Society for Control and Instrumentation of Energy Processes. Papers to be presented include:

• Monitoring Temperatures in Coal Conversion and Combustion Porcesses via Ultrasound • Ultrasonic Thermometry in Oil Shale Retorts • High Frequency Electronic Burn Monitoring of Underground Coal Gasification • On-Line Analysis of Coal by Neutron Induced Gamma Spectrometry • The Monitoring and Control of Thermal Shields in Coal Gasifiers • The Sonic Doppler Flowmeter • Microwave Coal-Water Slurry Monitor • Dynamic Models for Coat Gasifiers • Instrumentation and Control Aspects of a Shale Retort Plant

JUNE 8- 10, CALGARY, ALBERTA, AT STAMPEDE PARK - The National Petroleum Show

JUNE 10 -11, NEW YORK CITY, AT THE BILTMORE HOTEL - A symposium entitled, "The Dynamics of World Coal Trade," sponsored by the National Coal Association, the Journal of Commerce, and the N.Y. Maritime Association.

JUNE 11 - 17, DUSSELDORF, WEST GERMANY, AT THE DUSSELDORF FAIRGROUNDS - "Bergbau 81," the international trade fair for mining, held every five years.

JUNE 14 - 16, ST. LOUIS, MISSOURI, AT THE MARRIOVF PAVILLION HOTEL - The National Coal Association's 64th Anniversary Convention.

JUNE 14 - 17, SAN ANTONIO, TEXAS, AT THE CONVENTION CENTER - The Eleventh Biennial Lignite Symposium, sponsored by DOE, U. of N. Dakota, and the Texas Energy and National Resources Advisory Council. The symposium focuses on the use of low-rank coals. Titles of papers to be presented include:

• Fluidized-Bed Gasification of Lignite for Utility Steam Generator Retrofits • Structural Characteristics and Relationships in Low-Rank Coals • Western Coal Versus Eastern Coal and Its Implications for Synthetic Fuels • Liquefaction of Low-Rank Coals with the Exxon Donor Solvent Coal Liquefaction Process • Liquefaction Behavior of a Gulf Coast and a Northern Great Plains Lignite • RD&D Initiatives for Low-Rank Coals: Follow-up to the Low-Rank Coal Study • Research and Development in Low-Rank Coals • Slagging Fixed-Bed Gasification of Lignite

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-43 • Coal Conversion in New Zealand - The South Island Lignite Programme • Developments in Use of Low-Rank Coal in Australia • Status of Gulf Coast Lignite Activity • Activities in Low-Rank Coal in the Northern Great Plains • Prospects for Industrial Lignite Use Along the Gulf Coast • On Some Inconsistencies in Current Concepts of Coal Chemistry JUNE 15- 17, DETROIT, MICHIGAN, AT THE DETROIT PLAZA HOTEL - Non-Petroleum Vehicular Fuels II, the second symposium on this subject sponsored by the Institute of Gas Technology. Titles of papers to be presented include: • Methanol From Coal • Ethanol as a Fuel for Diesel Tractors • Diesel Engine Modifications Required for Alternative Fuels • The Economics of Compressed Methane as a Vehicle Fuel for Fleet Applications • Alcohols as Fuels and Feedstocks JUNE 18 - 19, WASHINGTON, D.C., AT THE SHOREHAM HOTEL - The McGraw Hill/Inside EPA conference entitled, - _"Hazardous Waste Disposal: How, Where— and at What Cost?' JUNE 18 - 20, CASPER, WYOMING, AT THE RAMADA INN - The 26th Annual Convention of the Wyoming Mining Association.

JUNE 22 - 27, MONTREAL, QUEBEC, AT PLACE I3ONAVENTURE EXHIBITION HALL - The 73rd Air Pollution Control Association's Annual Meeting. This is a very large meeting, having 68 sessions. Session titles of interest include: • Industrial Combustion • Air Pollution Impacts of Coal Mining, Benefieiation, and Utilization • Energy, the Environment, and Economies • Fugitive Emissions • Ecological Implications of North American Energy Policies JUNE 28- JULY 1, VAIL, COLORADO, AT MARRIOTT'S MARK IN LIONHEAD VILLAGE - The 77th Regular Meeting of the Rocky Mountain Coal Mining Institute. JULY 21 - 24, SARATOGA. WYOMING, AT THE SARATOGA INN - "Confab '81," a technical conference on fossil fuel chemistry, is sponsored annually by the Laramie Energy Technology Center of the U.S. Department of Energy. Papers presented at these annual summer meetings are not published.

AUGUST 10 - 13, VAIL, COLORADO, AT THE LODGE - Oil Shale; The Environmental Challenges II, a symposium sponsored by The Oil Shale Task Force and the U.S. DOE. The tentative program includes: • "Australian Oil Shale Developments," by Peter Hawley, keynote speaker. • Technical subjects covered - Water Management and Retort Abandonment - Solid Waste Management - Reclamation - Socioeconomic Impacts - Health Effects - Air Emissions - Safety AUGUST 9 - 14, ATLANTA GEORGIA, AT THE HYATT REGENCY - The 16th Intersociety Energy Conversion Engineering Conference. A major meeting, with 79 sessions. Session titles include: • Tar Sands/Heavy Crude • Coal Liquefaction • Synfuels Processes • Unconventional Gas Sources and Extraction

1-44 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 • Hydrogen • Coal Combustion and Gasification • MUD Systems • Unconventional Fossil Fuel Extraction and Conversion • Coat Gasification and Power Generation • Nuclear Fossil Fuel Production

AUGUST 16 - 19, DETROIT, MICHIGAN, AT THE DETROIT PLAZA HOTEL - A.LCh.E.'s Detroit National Meeting. A major meeting concerning synfuels. Session titles include:

• Energy From Eastern Shale (2 sessions) • Hydrogen After 2000 A.D. • Energy and the Role of the Engineer • Commercialization of Coal Gasification Processes • Wastewater Treatment From Synfuels Plants • Coal Preparation Required for the Synfuels Industry • Indirect Liquefaction of Coal • Synthetic Motor Fuels • Modeling coal Conversion Processes

AUGUST 23 - 26, CALGARY, ALBERTA, AT THE CALGARY INN - The Third International Coal Exploration Symposium, sponsored by World Coal/World Mining.

AUGUST 30 - SEPTEMBER 4, CHRISTCHURCH, NEW ZEALAND, AT THE UNIVERSITY OF CANTERBURY - The 9th Australian Conference on Chemical Engineering. One session concerns energy technologies.

SEPTEMBER 1 - 2. CHICAGO, ILLINOIS. AT THE DRAKE HOTEL - The Conference on the Economics of Mined-Land Reclamation, sponsored by Argonne National Laboratory. Papers were invited on the subject of oil shale tailings disposal and reclamation.

SEPTEMBER 7 - 11, FALLEN LEAF LAKE, CALIFORNIA, AT THE STANFORD SIERRA LODGE - The Seventh Annual Underground Coal Conversion Symposium, sponsored by the Lawrence Livermore National Laboratory. Program not finalized.

SEPTEMBER 28 - OCTOBER 1, LOS ANGELES, CALIFORNIA, AT THE BONAVENTURE HOTEL - The 1981 International Gas Research Conference, sponsored by the GRI, AGA, and DOE. The program contains about 40 papers on the subjects of coal gasification processes, coal gas upgrading, and economics of coal gasification.

OCTOBER 4 - 9, MONTREAL, QUEBEC, AT THE QUEEN ELIZABETH HOTEL - The Second World Conference of Chemical Engineering. Session titles of interest include:

• Advances in Coal Utilization Technology • Opportunities and Challenges Provided by Heavy Oil Resources • Coal Processing • Hydrogen as Fuel

OCTOBER 13 - 15, 1981, GAITHERSBURG, MARYLAND, AT THE NATIONAL BUREAU OF STANDARDS - The Sixth Annual Conference on Materials for Coal Conversion and Utilization, sponsored by EPRI, DOE, NBS, and GRL

OCTOBER 26 - 29, NASHVILLE, TENNESSEE - Synthetic Fuels From Oil Shale II, a symposium sponsored by the Institute of Gas Technology. Program not finalized.

NOVEMBER 8 - 12, NEW ORLEANS, AT THE FAIRMONT HOTEL - A.l.ChE's 1981 Annual Meeting. Session titles include:

• Chemical Feedstocks From Coal • Status of International Coal Conversion Projects • Two-Stage Coal Liquefaction • Coal Liquefaction Tutorial

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-45 RECENT GENERAL PUBLICATIONS

Argonne National Laboratory, "Review of Instrumentation Needs for Process Control and Safety in Advanced Fossil Energy Processes," report number ANL-FF-49628-TMO2, 1980. "A Simpler Path to a Cleaner Environment," staff article in Fortune, May 4 issue. 1981. Allan, D. E., et at., "Recent Developments in Thermal Conversion Technology," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Anthony, R. G., "Kinetics of Methanol Conversion to Olefins," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Baker R. L. and D. H. McCrea, "The Benfield Lo Heat Process: An Improved HPC Acid Gas Absorption Process," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Barr, M. 0., "Major Litigation Impacting on the Permitting Process." presented at the Special Institute on Mineral Resource Planning sponsored by the Rocky Mountain Mineral Law Foundation, Tuscon, Arizona, March 1981. Bartholomew, C. H., !Hydrogenation of CO on Nickel," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Bergman, D. and L. Yarborough, "Low Temperature CO 2—Il ydrocarbon Phase Equilibrium and Solubility Data," presented at the A.1.CFLE. 1981 Spring Meeting, Houston, Texas, April 1981. Bowden, Jimmie R., "The Government's Synthetic Fuels Policy—A Critique," presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas, March 1981. Bowen, C., "Thermal Regenerative Cracking," presented at the A.I.Ch.E. 1981 Spring Meeting. Houston, Texas, April 1981.

Brooks, Robert, "Pressurized Fluidized Bed Combined Cycles for Utility Application," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI. GRI. and NCA, held in Washington, D.C. on March 9-11, 1981. Cobb, C. B., "Synthesis Gas Economics," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. "Colorado Permitting Directory for Energy and Mineral Resource Development," by the Colorado Department of Natural Resources, 1313 Sherman Street, Denver, Colorado 80203, 1981. "Colorado's Joint Review Process for Major Energy and Mineral Resource Development Projects," by the Colorado Department of Natural Resources, 1313 Sherman Street, Denver, Colorado 80203, 1981. "Costs of Synthetic Fuels in Relation to Oil Prices," a report by the Congressional Research Service for the House Committee on Science and Technology, March 1981. Council on Environmental Quality, "Global Future: Time to Act," a report to the President on Global Resources, Environment, and Population, January 1981. Cowser, K. E. and C. R. Richmond, "Synthetic Fossil Fuel Technology—Potential Health and Environmental Effects," the Proceedings of the First (1978) Annual Oak Ridge National Laboratory Life Sciences Symposium, published by Ann Arbor Science Publishers, Inc., 1981. Clark, G. M., "Setting Up and Carrying Out a New Facility Permitting Program," presented at the Special Institute on Mineral Resource Planning sponsored by the Rocky Mountain Mineral Law Foundation, Tuscon, Arizona, March 1981. Cockrell, William F., Jr., "Overview and Summary of Recent Synthetic Fuels Developments." presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas. March 1981. Connery, R. T., "Expediting Lease or Permit Processing and Issuance," presented at the Special Institute on Mineral Resource Planning sponsored by the Rocky Mountain Mineral Law Foundation, Thscon, Arizona, March 1981. Craven, D. B., "Evolving Federal Policies in the Administration of Synthetic Fuels Incentives," presented at the Bureau of National Affairs' 2nd Industrial Energy Users Conference, Washington, D.C., March 1981. Culbe'son, S. Frank, "The Human Resources Component of Synthetic Fuels Development," presented at the Morgan Stanley Oil Shale Seminar, Grand Junction, Colorado, March 1981. *Reviewed in this issue.

1-46 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS - GENERAL

Defrawi. M.. "Chemicals from Syngas: A Technical-Economic Perspective," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Doering, R. W., "Process Control Instrumentation for Advanced Fossil Energy Processes," presented at the A.I.CtLE. 1981 Spring Meeting, Houston, Texas, April 1981.

Doerksen, Harvey, "Research on the Adequacy of Water Resources for Energy Development," presented at EPA's Fifth National Conference entitled Interagency Energy/Environment R&D Program, Washington, D.C., May 1981. Donlon, dos., "Strategy for Avoiding a Manpower Crunch," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Drayton, Wm., "Synfuels: A Marginal Source of Supply?" presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Ebzery, T. E., "Facility Siting," presented at the Special Institute on Mineral Resource Planning sponsored by the Rocky Mountain Mineral Law Foundation, Tuscon, Arizona, March 1981.

Edgar, T. F., et al., "The Sulfur Balance in Pyrol ysis and Combustion," presented at the A.I.CltE. 1981 Spring Meeting, Houston, Texas, April 1981.

Eickmeyer, R. G. and E. A. Wiherg, "Purification of COS Rich Gas," presented at the A.I.CKE. 1981 Spring Meeting, Houston, Texas, April 1981.

Eickmeyer, R. G., "The Role of Acid Gas Removal in Production of Synfuels," presented at the A.LCh.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Elliot, J. D. and J. C. Dunmeyer, "Alternate Conversion Schemes for Residual Feedstocks," presented at the A.1.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

"Energy in a Finite World," a 2-volume report by the Energy Systems Program Group of the International Institute for Applied Systems Analysis, Ballinger Publishing Company, Cambridge, Massachusetts, 1981. Volume 1 - Paths to a Sustainable Future, Volume 2 - A Global Systems Analysis.

"Energy. Natural Resources and the Environment in the Eighties," the report by the Panel on Energy. Natural Resources and the Environment, one of nine panels within the President's Commission for a National Agenda for the Eighties, 1980. "Environmental, Operational, and Economic Aspects of Thirteen Selected Energy Technologies," report number NTIS PB81-153926 prepared by Hoffman-Munter Corporation for the U.S. Environmental Protection Agency, 1980. *Exxon Corporation, "Exxon Company, USA's Energy Outlook: 1980-2000," December 1980.

-Exxon Corporation, "World Energy Outlook," Exxon Background Series, December 1980.

Fitzgerald, C. H., "Construction Labor Availability in Synfuel Plant Site Areas," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981 Fossella, J. F. and E. L. Phillips. "Gasohol and the Gasoline Pool," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Galiasso, R., at al., "Regeneration of Hydrodesulfurization Catalysts." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Gluckman, Michael. "Energy Facility Siting and Environmental Considerations," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-11, 1981. Green, D. C. and D. H. Broderick, "Hydroprocessing Residual Feedstocks in the 1980s," presented at the A.I.Ch. E 1981 Spring Meeting, Houston, Texas, April 1981.

Grover, R., "1981 Politics Reshape the Synfuels Development Program," presented at the Engineering News Record conference Making Synfuels Plant Business You! Business, Washington, D.C., March 1981 ilafele, Wolf, "Results of the Seven-Year Global (Australian) Energy Study," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11, 1981. Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-47 RECENT PUBLICATIONS - GENERAL

Hanfling, R.I., "Where Is The Synthetic Fuels Development Program Headed?" presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981 7 Harsch, William G., "Federal Policy of Synthetic Fuels Financing and the Synthetic Fuels Corporation,' presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas, March 1981. Haskell, A. C. (V.P. Planning, SFC), "Financing Synfuels Development Under the Reagan Administration," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C.. March 1981 High, Michael, "Atmospheric Fluidized Bed Combustion for Utility Application," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11, 1981.

Hill, R. B., "Overview of Synfuels Technologies, Commercial Plant Sizes and Special Design Requirements That Will Impact the Equipment and Engineering Construction Industry," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Holaday, Bart, "Gulf's Outlook for Conventional Gas Supplies," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-11, 1981. Homeyer, H. C., "Planning and/or Managing a Synthetic Fuels Project," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. ------

Kelly, Wm. C., Jr., "How Will the Cost of Proposed Synfuels Plants Be Financed?" presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Kent, Harry, "The Outlook for Remaining U.S. Gas Resources Based on Recent Exploration & Development Activity," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11. 1981.

Kirk, Garrett, Jr., "Securing Financing from Private Financial Institutions," presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas, March 1981.

Kocher, N. K., "Ethylene From Ethanol." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Kronenberger, L., "Environmental Factors in (Synfuels) Project Facilitation," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Lanham, R. L., "Synthetic Fuels Project Financing," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Lash, .1., "Synthetic Fuels and Environmental Controls: Why Be Concerned?" presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Lemon, J. R., "Social Costs of Alternative Synfuels; International Dimensions," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Leonard, J. P. and L. H. Weiss, "Ethylene—Can Non-Conventional Sources Compete?" presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Loper, D. R., "Cooperation Versus Crunch for Energy Impacted Communities," presented at Synthetic Fuels Prospects Under the Reagan Administration, sponsored by U.S. National Committee of the World Energy Conference, Washington, D.C., April 1981.

Louks, Bert, "Methanol: An Opportunity for the Electric Utility Industry to Produce Its Own Clean Liquid Fuel," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11, 1981. Lukens, L. A., "Potentials for Industrial Participation in the Developing Synthetic Fuels Industry: Investment and Other Opportunities," presented at the Bureau of National Affairs, 2nd Industrial Energy Users Conference. Washington, D.C., 198L

Lukens, Larry, "Understanding the Synthetic Fuels Corporation," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

1-48 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS -GENERAL

Luo, H. and C. A. Atwood, "Vapor-Liquid Equilibria for the t-Butanol-Methanol-Water System," presented at the A.I.CItE. 1981 Spring Meeting, Houston, Texas, April 1981.

Marlowe, D. B., "Outlook for Engineering Manpower Required by the Synfuel Plant Construction Program," presented at the Engineering News Record conference Making S ynfuels Plant Business Your Business, Washington, D.C., March 1981 Maulbetsch, John, "Energy Facility Siting and Water Quality Control," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR!, and NCA, held in Washington, D.C. on March 9-11, 1981. McCormick, William, Jr., "AGA's Gas Supply Committee Forecast," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR!, and NCA. held in Washington, D.C. on March 9-1I, 1981.

Moore, H. J. and A. L. Tyler, "The Effect of An Acidic Catalyst on Simultaneous H ydrodesulfurization and Hydrodenitro- genation of Heterocyclic Sulfur and Nitrogen," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 198L

Mosier, M. L. (National Constructor's Association), "Project Agreements for Synfuels Plant Projects," presented at the Engineering News Record Conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981. Musgrove, C., "The Colorado Joint Review Process," presented at the Engineering News Record conference Making Synfucis Plant Business Your Business, Washington, D.C., March 1981

'National Commission on Air Quality, "To Breathe Clean Air," the final report to Congress by the NCAQ. March 1981. "No Health Risks Are Seen Yet For Synfuel Workers," a staff article in Chemical Engineering, February 9 issue, 1981. "Options for Fueling America's Transporatation," the Proceedings of the July 1980 Workshop of the Aspen Institute for Humanistic Studies, 1981.

Parker. H. W.,"Criteria for Synfuel Process Selection," in the November 17, 1980 issue of ESCOE ECHO.

Parnell, D. C., "Differences in Design of Claus Units for Various Applications (Syr) Gas, Natural Gas, Refineries)," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Pctzrick, Paul, "Status Report of Government (S ynfuels) Programs," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1. and NCA, held in Washington, D.C. on March 9-11, 1981. Princiotta, Frank, "Environmental Guidance for Synfucls Facilities - Pollution Control Documents," presented at EPA's Fifth National Conference entitled Interagency Energy/Environment R&D Program, Washington, D.C., May 1981. Proctor, John P., "The Permitting of Synthetic Fuels Projects: e.g., Minimizing Environmental Difficulties," presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas, March 1981.

Redding, M. J., "Overview of (S ynfuels) Project Facilitation," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Rennard, R. J. and H. E. Swift, "Effect of Ilydrotreating Distillate Pyrolysis Feedstocks," presented at the A.1.Ch,E. 1981 Spring Meeting, Houston, Texas, April 1981.

Robinson, D. B., "Critical Phenomena in a Mixture of CH 4' CO 2 and H 25." presented at the A.LCh.E. 1981 Spring Meeting, Houston, Texas, April 1981. Rocks, Dr. Lawrence, "Fuels For Tomorrow." PennWcll Books, Tulsa, Oklahoma, 1981.

Roe, K. A. (Burns & Roe, Inc.), "Let's Take A Sensible Approach to the Development of a Synthetic Fuels Industry," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Rovick, A. M., "Environmental Permits for Water Used in Mineral Resource Development." presented at the Special Institute on Mineral Resource Planning sponsored by the Rocky Mountain Mineral Law Foundation, Tuscon, Arizona, March 1981.

Sansom, R. L., "Energy Efficiency and Economics of Gasohol vs. Other Liquid Fuels," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. 'Reviewed in this issue,

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-49 RECENT PUBLICATIONS - GENERAL Savage, D. W., "Selective Absorption of Hydrogen Sulfide and Carbon Dioxide into Aqueous Solutions of MDEA," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Scheppele, S. C., "Characterization of Fossil Liquids and Implications for Use in Processing," presented at the A. I.Ch. E. 1981 Spring Meeting, Houston, Texas, April 1981. Shirk, W. Bruce, "Effective Contracting for Synthetic Fuels Projects," presented at The Oil Daily Forum on Profitable Synthetic Fuel Development, Houston, Texas, March 1981. Skamser, R. 0., "Refinery High Sulfur Crude to Low Sulfur Products," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston. Texas, April 1981. Stohl, F. V. and B. (iranoff, "The Relationship Between Properties of Iron Sulfides and Their Catalytic Activity," presented at the A.I.CILE. 1981 Spring Meeting, Houston, Texas, April 1981.

Storer. R. L., "Labor Supply and Demand for the Energy Industry in the 1980's," presented at the A.LCh.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Street, W. B. and J. R. S. Machado, "Thermodynamic Properties of 112/0114 Mixtures," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. "The Emerging Global Synthetic Fuels Industry." published by Madsen Russell Associates, Ltd., 222 Mamaroneck Avenue, Suite 201, White Plains, N.Y. 10605, 1981, price: $950.

"The U.S. Ethanol Industry: 1981 to 2000," published by Madsen Russell Associates, Ltd., 222 Mamaroneck Avenue, Suite 201 9 White Plains, N.Y. 10605, 1981, price: $950. "The Windfall Profits Tax: The Price for Decontrol," a report published by The Oil Daily, 1981, price: $37.50.

Tomkins, B. A., "Rapid Sequential IIPLC Determination of Benzo(a)pyrene in Natural Synthetic and Refined Crudes," presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981. U.S. Department of Energy, "Comparing Energy Technology Alternatives from an Environmental Perspective," report number DOE/EV-0109, February 1981. U.S. Energy Information Administration. "1980 Annual Report to Congress." DOE/EIA-0173 (80)1. 1981. 'U.S. Environmental Protection Agency, "Emission Reduction Banking Manual." prepared for EPA by ICF Inc., 1980.

United States General Accounting Office, "Environmental Protection Issues in the 1980's," report 4iCED-81-38 of the GAO, December 1980. Copies available from the Document Handling and Information Services Facility of the GAO. P.O. Box 6015, Gaithersburg, MD. 20760. U.S. General Accounting Office, "Possible Ways to Streamline Existing Federal Energy Mineral Leasing Rules." report number EMD-81-44, January 1981. Copies available from U.S. GAO, P.O. Box 6015, Gaithersburg. MD 20760. 'U.S. General Accounting Office, "Special Care Needed in Selecting Projects for the Alternative Fuels Program," Report No. EMD-81-36, December 8, 1980.

'Utah Division of Water Resources." State of Utah Water-1980." published by Utah Department of Natural Resources, January 1981.

Weber, L. A., "Measurements of the Specific Heat, C, of Ethylene," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Weber, S. L. and L. J. Sealoek, "Catalyst Behavior in Biomass Gasification," presented at the A.I.CI'LE. 1981 Spring Meeting, Houston, Texas, April 1981. 'Reviewed in this issue.

1-50 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 GENERAL - PATENTS

Englehard Minerals and Chemicals Corporation, Wm. C. Pfefferle - Inventor, U.S. Patent 4.239,499, December 16. 1990, "Production of a Fuel Gas and Synthetic Natural Gas From Methanol." Methanol is passed over a catalyst at an elevated temperature and pressure to produce a fuel gas containing a high proportion of methane in a one-step catalytic conversion process. Removal of water and carbon dioxide from the fuel gas produces a synthetic natural gas. For example, methanol with water is passed over a precious metal catalyst such as ruthenium on alumina at a temperature in the range of about 350' C to 500' C and a pressure in the range of about 800 to 2,500 psig to produce a gaseous mixture comprising methane, carbon dioxide, minor amounts of hydrogen and essentially no carbon monoxide. Upon condensing the water vapor and scrubbing out the carbon dioxide, synthetic natural gas is obtained having a methane content above 90 percent by volume.

Occidental Petroleum Corporation, N.W. Green - Inventor, U.S. Patent 4,243,489, January 6, 1981. "Pyrolysis Reactor and Fluidized Bed Combustion Chamber." A solid carbonaceous material is p y rolyzed in a descending flow pyrolysis reactor in the presence of a particulate source of heat to yield a particulate carbon containing solid residue. The particulate source of heat is obtained by educting with a gaseous source of oxygen the particulate carbon containing solid residue from a fluidized bed into a first combustion zone coupled to a second combustion zone. A source of oxygen is introduced into the second combustion zone to oxidize carbon monoxide formed in the first combustion zone to heat the solid residue to the temperature of the particulate source of heat.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 1-51 Pr, PROJECT ACTIVITIES

RUNDLE PROJECT IN QUEENSLAND IS SHELVED On August 1, 1980, Exxon Corporation completed its purchase of ARCO's 60 percent share of the Colony Esso Australia Ltd. and Southern Pacific Petroleum/Cen- property. Effective that date, Tosco contributed to the tral Pacific Minerals (SPP/CPM) announced in April that Colony Shale Oil Project its 40 percent of the property. plans to develop the Rundle deposit in Queensland, The value of the mineral properties contributed, approxi- Australia, have been shelved pending a new agreement mately $9 million, has been accounted for as a part of between the participants and a re-evaluation of the Tosco's investment in the Colony Shale Oil Project. feasibility of the project. Capital cost estimates rose to A$2 billion from A$700 million because of geological and According to the annual report: "The Operating Agree- technical difficulties. ment with Exxon provides that either party may carry the interest of the other upon failure of the other party Eo had signed a Deed of Agreement with SPP/CPM to to fund cash calls made by the operator and to obtain, develop the Rundle oil shale deposit in accordance with after certain conditions have been satisfied, a portion of the Rundle Oil Shale Agreement Act of 1980, which was the interest of the party whose cash call was 'covered.' enacted by the Queensland Legislative Assembly. The If Exxon shall have carried Tosco, after Exxon has terms of the agreement called for Esso to bear all recouped 150 percent of any amounts advanced on behalf development costs, up to US$330 million, for Phase I to of Tosco from the net proceed of the sale of shale oil retain its 50 percent equity. Esso would have funded 50 and other products, Tosco will retain an interest in the percent of Phase II, which would have produced from commercial development of the Colony Property of at 180,000 BPD to 240,BPD. least 20 percent even if Tosco fails to advance any funds to the operator. Tosco has the right to sell all or any The original concept of the Rundle project was for part of its interest in the Colony Property to Exxon at a surface mining, retorting using Lurgi-Ruhrgas and specified price substantially equal on a pro rata basis to Superior retorts, and upgrading. Phase I was to involve the price paid by Exxon to Atlantic Richfield Company the development of an open cut mine to produce 25,000 and to be reimbursed for costs expended subsequent to tonnes per day of oil shale and construction of an 18,000 May 9, 1980, plus interest. It is estimated that total tonne-per-day Superior retort and a 10,000 tonne-per- 1981 expenditures for the Colony Shale Oil Project will day Lurgi to produce 18,000 BPD. Product shale oil was aggregate $260,000,000." to have been pipelined to a bulk terminal at Gladstone. Phase I was to have been operational in mid-1985. After a US$30 million, 12-month feasibility study, Esso WHITE RIVER SHALE PROJECT PLANS PHASE I and SPP/CPM determined that due to significant techni- CONSTRUCTION TO BEGIN IN DECEMBER cal uncertainties associated with mining and retorting it would not be prudent to proceed with Phase I. Grahame White River Shale Project (WaSP) plans to begin con- L. Baker, in presenting a paper entitled "Australian struction on Phase I of a three-phased development in Developments in Oil Shale Processing" at the 14th Oil December of this year. Plans call for submittal in June Shale Symposium at the Colorado School of Mines, of a Detailed Development Plan (DDP) for approval by reported that mudstone between oil shale layers in the the Oil Shale Office. coastal Rundle deposit would cause ground instability in and around the mine. Baker is Deputy Director of the The clouded title and Utah in lieu land selection issues, Queensland Department of Commercial and Industrial which prompted the courts to suspend the terms of the Development in Brisbane. leases to Federal Prototype Oil Shale Lease Tracts U-a and U-b, are close to being resolved to the satisfaction The companies are currently considering a revised joint of WRSP. White River is an equal partnership between venture agreement enabling them to determine whether Phillips Petroleum Company, Sohio Shale Oil Company, or not a commerical project is technically and economi- and Sunoco Energy Development Company (Sunedco). a cally feasible and in what time frame, without the need wholly owned subsidiary of Sun Company Inc. to build a demonstration plant. This decision could be made by the first quarter of 1984, which could lead to Phase I Will Test Superior and Union B Retorts production in the early 1990s. It is likely that commercial production would be a more modest 125,000 BPD. Phase I comprises mining and retorting designed to generate specific information on ore body characteris- #### tics and information on the retorting processes. One Superior retort and one Union B retort will be construc- TOSCO/EXXON OPERATING AGREEMENT ted. Up to 27,300 TPD of oil shale will be mined to FOR COLONY PROJECT IS SUMMARIZED produce 16,120 BPSD of upgraded shale oil by the end of 1985. Upgrading will be accomplished on-site. Tosco Corporation's 1980 annual report discusses the Operating Agreement between itself and Exxon Corpora- Phases II and III will expand shale oil production levels to tion. Tosco will retain at least 20 percent interest in approximately 50,000 and 100,000 BPD, respectively. Colony Shale Oil Project, even if it does not advance its White River plans to begin construction on Phase II in share of funds for development.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-1 January 1987, with initial production planned in early Energy Oil Shale Corp. to be solely dedicated to its 1989. Phase Ill will begin construction in 1990, with Cottonwood Wash project, which is located in R21E, initial production in the summer of 1991. Full produc- T10S, SLM in Utah. Negotiations are underway with tion at 100,000 BPD will be achieved by 1993. Tosco for a two-section land trade, subject to approval by the State of Utah. WRSP estimates the following water requirements: A feasibility study has been completed. Preliminary Phase 1-2,500 AFY engineering, full-scale permitting, environmental and' Phase II - 10,000 AFY socioeconomic programs, product marketing, project Phase 111-21,000 AFY financing, and risk assessments are underway. Ultimate production of 30,000 BPD is currently planned. Resource Phillips and Sunedeo Request Loan Guarantees assessment indicates that this level can be sustained for at lease 30 years based on a projected recovery rate of Phillips and Sunedco, each one-third owners of the White approximately 27 GPT of oil shale. River Shale Project, are requesting financial assistance from the Synthetic Fuels Corporation (SFC) in the form Magic Circle has selected the T 3 retorting process, of loan guarantees in the amount of 60 percent of their developed by Science Applicqtions Inc. (SAl) for the project costs, or 40 percent of the total project costs. It Moroccan government. The T process is a variation of is estimated that the amount of government guaranteed the N-T-U process. This system makes use of batch debt financing for the project will approximate $550 retort technology developed over the last 30 years in ths million. U.S. Magic Circle and SAl claim that innovative T design features, compared to previous technology, are Sohio, the third owner of the projecthaselected not to lower water consumption, improved safety, sensible-heat apply for financial assistance from SFC. The three recovery, increased process yield, efficiency, flexibility, WRSP partners are also among the participants in the and continuous process operations. Paraho-Ute oil shale project. Sohio is a 60 percent partner in the Pacific Project, with Superior Oil and Magic Circle is also negotiating a data-exchange agree- Cleveland-Cliffs each holding 20 percent. ment with Morocco to further reduce any risks involved in the two commercialization efforts. They are confi- Work Force Will Peak at 4,000 by 1988 dent that this limited risk approach will be an important consideration for project sponsors and investors. In The work force to construct the Phase I facility will addition, the project will have the option of incorpora- peak at 1.500 persons during 1983, dropping rapidly to an ting other retorting systems, such as Lurgi and Paraho, operating work force level of approximately 850. Con- as they become commercial. struction of later phases will require a peak of 4,000 persons by 1988 and an operating work force of about The mining horizon is at a depth of 1,500 to 1,900 feet. 3,200 after 1993. Conventional room-and-pillar mining will be used to achieve production of 70,000 TPD of raw shale to Construction of the facility will require the influx of a support a 30,000 BPD production. Innovative mine relatively large number of skilled construction workers design features employ natural barriers to provide signi- into northeastern Utah. Project operations will produce ficant mine ventilation improvement over conventional steady, long-term growth in the area. To help mitigate mine design. Four shafts (one service, two ventilation, adverse socioeconomic effects in the area, a temporary and one production) are required. Magic Circle esti- campsite will be established to provide housing, services, mates that 400 employees will be required during full and recreation for construction workers and for those scale operation for both the mining and the material indirectly employed who will provide goods and services. handling operations. The campsite will consist of modular, transportable bachelor units and eating, shopping, and recreational Estimated oil in place on the 6,400-acre Magic Circle facilities. It will be naturally landscaped to fit the block totals over 3.4 billion barrels. Recoverable oil terrain and will provide modern utilities. Since the using surface processing alone is estimated at 583 mil- campsite will be nearly self sufficient, there should be lion barrels. This yield could more than triple to 1.9 minimal increases in demand for other local services. billion barrels, according to Magic Circle, with the eventual application of vertical modified in situ tech- Plant and mine operations begin to make a major contri- nology. bution to employment in 1985, when the operations work force reaches 850. Since the operations employment at Magic Circle has applied to the U.S. Synthetic Fuels full commercial production will be stable over a long Corporation for a loan guarantee of $1.45 billion and a period of time, this population is expected to be assimi- limited time-phased purchase agreement, covering the lated into the local communities, which will result in an initial two years of production under developing market expansion of housing and population in the area. conditions, to an overall maximum of 10 million barrels. The total on-site work force during the construction period is expected to peak at slightly over 2,600 during MAGIC CIRCLE ENERGY CORP. ANNOUNCES 1984. The breakout of on-site personnel during this COTTONWOOD WASH OIL SHALE PROJECT period is not yet available. However, during full commercial production operations personnel requirements Magic Circle Energy Corporation, which partly evolved are approximately 220 for administration, 480 for main- from the Western Oil Shale Corporation, has formed M C tenance, 60 for technical support, 700 for production, and 440 for mining.

2-2 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TECHNOLOGY

STUDY RANKS PARAHO OVER HYTORT FOR ranges from 15 to 20 feet in thickness throughout most EASTERN OIL SHALE of the area. These two oil shales are separated by the Berea Sandstone and Bedford Shale, which combined are A DOE-funded study was recently completed by Davy approximately 100 to 120 feet thick in northern Lewis McKee Corporation for the Buffalo Trace Area Develop- County, decreasing southward to 30 to 35 feet in Flem- ment District in Maysville, Kentucky. The main objec- ing County. tives of the study were to make a resource assessment, a mining study, and a process economic evaluation of oil Carbon concentration in the oil shale averages 11.42, shale in Lewis and Fleming Counties, Kentucky. Two 9.04, and 5.61 percent in the Sunbury, Cleveland, and surface retorting processes. Paraho and HYTORT, were Huron intervals respectively. The concentration de- selected, and the process and economic anlayses were creases from top to bottom in the Cleveland and in- made for a 30,000 TPD oil shale retorting facility. The creases from top to bottom in the Huron. The carbon results were presented at the 14th Oil Shale Symposium data define two economic zones in the oil shales. These at the Colorado School of Mines, April 22-24, in a paper zones are the entire Sunbury Shale and a high grade zone by Dr. Kirit C. Vyas entitled "Syncrude from Eastern Oil (HGZ) in the Cleveland, which extends from the top of Shale." the unit to a point where the carbon drops below 8 percent. The Cleveland HGZ is 30 feet in thickness and The study indicated that the total capital required for a averages 11.11 percent carbon. Hydrogen averages 1.2 grass roots Paraho plant facility, having a capacity to percent in both the Sunbur y and Cleveland 1101 and retort 30,000 TPD of eastern oil shale, will be about increases by about 15 percent in the Sunbur y from north $647 million, and the HYTORT plant having the same to south. Fischer Assay values for the Sunbury and capacity will require about $890 million. The initial Cleveland HGZ average 10.3 and 11.9 OPT respectively plant investment cost for Paraho and HYTORT are $504 for all the cores, and range from 9.2 to 11.6 OPT and million and $695 million respectively. For the same 10.8 to 13.0 GPT respectively. Oil yield increases in a return on equity, the Paraho process is cheaper than the north to south direction in the study area. Sulfur I-IYTORT process by about $20 per barrel. averages 3.54 percent and 2.57 percent in the Sunbury and Cleveland HOZ respectively, and is principally pyri- Resource Evaluation Is Performed in Kentucky tic in nature. The shales are siliceous (approximately 66 percent SiO 2 and 16 percent Al 2O 3), low in calcium (less The Cleveland-Cliffs Iron Company and the Institute for than 1.0 percent). and high in potassium (4.3 percent), Mining and Minerals Research were responsible for the which indicate a significant quartz content, a low car- resource assessment and mining parts of the study. Oil bonate mineral content, and a clay content that is shales in the west have higher oil yields than in the east. probably illitic in nature. The chemistry of the shales is The organic carbon content of both is similar, but highly consistent among the cores. western oil shales contain more hydrogen. The overall energy content of both shales is similar, but eastern Several trace elements occur in interesting, but probably shales yield higher amounts of by-products such as gas, sub-economic, concentrations: coke, and steam/electricity. The USGS has estimated the total "known resources" of Devonian shale at 400 Concentration, ppm billion barrels, and probable extensions at an additional 2,600 billion barrels. Element Sunbury Cleveland HGZ Cu 108 ppm 106 ppm The resource assessment work included core driling, Cr 218 ppm 213 ppm geological mapping, sample analyses, shale characteriza- Me 365 ppm 124 ppm tion, reserve estimation, and mine site selection. Ten Ni 282 ppm 146 ppm cores were drilled along the oil shale outcrop, and 74- V 1,533 ppm 1,024 ppm minute geologic quadrangle maps and field notes were U 37 ppm 20 ppm used to determine the quality and quantity of oil shale in Zn 1,126 ppm 622 ppm Lewis and Fleming Counties. The pertinent geologic strata comprise, from top to bottom, the Borden Forma- Sulfur and trace element concentrations are low in tion (series of siltstones and shales), the Sunbur y Shale potential overburden materials, indicating that they (oil-bearing black shale), the Berea Sandstone (shaly probably would not be a source of pollution during siltstone), the Ohio Shale (oil-bearing black shale), the mining. Bisher Limestone (dolomite), and the Crab Orchard Shale. Rock mechanics tests indicate the oil shales have com- pressive strengths in the 10,000 to 13,000 psi range. Ash The Ohio Shale is divided, top to bottom, into the fusion testing indicates the shales to be refractory with Cleveland Member (50-65 feet thick), the Three Lick Bed a temperature of 2,260°F recorded for the initial ash (12-20 feet thick), and the Huron Member (135-208 feet deformation. Bulk densities of the economic oil shale thick). The Ohio Shale ranges from approximately 300 to intervals average 142 pounds per cubic foot. Total 200 feet in thickness in the study area, thinning from volatile hydrocarbon yields from the shales range from I north to south and from east to west. The Sunbury Shale to 17 cubic feet per ton, indicating that gassy mine conditions may be encountered in underground shale mines

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-3

Shale reserves for the economic shale intervals were Mining operations would employ conventional equipment calculated by overburden category on a 74-minute quad- such as diesel-powered drill rigs, electric and diesel rangle map basis for those quadrangles where the shale hydraulic shovels, and 85-ton end-dump haulage trucks could be recovered by surface mining. A total reserve of feeding a toothed, single-roll primary crusher. Crusher 5.2 million acre-feet or 16.4 billion tons of shale, conser- feed would be scalped -48", +12" material. Crusher vatively representing 4.4 billion barrels of oil, were product would be conveyed to the retort facility. found. Of this, 6.7 billion tons, representing 1.3 billion barrels of oil, are in a configuration with a stripping Processed shale would be conveyed to the primary ratio of less than 2.5:1 overall. Most of this strippable crusher area for direct loading into ore trucks, or it shale lies in eastern Fleming and southwestern Lewis would be stockpiled for transport to a disposal site near Counties. the mining face. Scrapers would be used for topsoil stripping and also for topsoil spreading during reclama- Mining Operating Cost Estimates Range from $2.19 to tion. $2.54 per Ton Haulage road maintenance would require a portable The mining study had two major categories: crushing plant, scrapers for distributing road material, and road graders. A service building would provide Evaluate the technical and economic aspects office, warehouse, maintenance and repair, and change- of recovering both the Sunbury and Ohio room facilities for 72 salaried and 345 hourly personnel. Shale. Process Evaluation Indicates Paraho Is Preferable to Determine capital, - operating, and maintenance costs to +25 percent. - Based on preliminary evaluation, Paraho and HYTORT The mining study was based on ridge-top strip mining were selected for detailed process and economic with an overall stripping ratio of 2:1. The study called analysis. Paraho is a low pressure process and produces for a supply of 30,000 TPD of primary crushed (-12") oil from 90 to 95 percent of Fischer Assay. The oil yield shale to a surface retorting facility. However, the from HYTORT is related to the organic carbon content Paraho and HYTORT require 33,600 TPD and 37,500 TPD rather than Fischer Assay. HYTORT retorts oil shale at respectively. The cost of mining was obtained, there- high pressure in the presence of hydrogen. HYTORT fore, by increasing the cost of 30,000 TPD by 12 percent converts about 46 percent of the organic carbon to shale for Paraho and by 25 percent for HYTORT. Costs cover oil, which corresponds to 116 percent Fischer Assay. all mining functions based on ridge-top strip mining, primary crushing, conveying to the retort, processed Paraho has developed direct heated and indirect heated shale disposal, and land reclamation. The proposed mine mode retorts for western oil shale. For eastern oil shale, and retort are located in Fleming County in northeast a combination heated retort has been developed, as Kentucky, approximately I mile north-northeast of shown in the process flow diagram in Figure 1. The Plummets Landing. Paraho retort is a refractory-lined vertical kiln in which a moving bed of crushed oil shale is contacted counter- For the selected site, the Sunbury and Ohio Shales yield currently with an upward flow of hot gases. Tempera- about 12 to 14 GPT. Mining would take place in two tures near the top of the retort are controlled so that separate locations, initially at Pea Ridge and later at the oil vapor is condensed in the gas stream as an North Ridge. Based on an 80 percent recovery factor, entrained oil mist. Retorted eastern oil shale, high in each area would yield about 137 million tons of ore over carbon content, is passed through a dynamic seal and a 10 year life, providing a 20 year total. Stripping ratios goes to a combustor, where the residual carbon is were calculated to be 1.5:1 at Pea Ridge and 1.9:1 at burned. The shale is then cooled and discharged by grate North Ridge. at the bottom of the retort. Hot flue gas is used to heat recycle gas and is then passed through a boiler to Design engineering and construction would require 3 generate high pressure steam for in-plant use and power. years prior to start of production mining at Pea Ridge. Material and energy balances for a Paraho plant process- For a 30,000 TPD mine, preproduction development costs ing eastern oil shale are shown in Figure 2. would be $5,872,000 and preproduction capital costs would be $65,104,000. In addition to 30,000 TPD raw oil shale, a Paraho plant would require about 2,000 gpm of makeup water, 1,066 Except for the service building and the crude ore trans- TPD of crushed limestone, and 428,600 scfm of air. The fer station at the retort, construction of new facilities plant would produce 8,132 BPD of shale oil, 2,282 BPD of at North Ridge would begin in the eighth year. Produc- light oil, 14,473 scfm of high-Btu gas, and about 48.3 MW tion mining at North Ridge would start in the eleventh of excess power. About 44.2 percent of the input energy year. Preproduction development costs are estimated to is recovered as liquid products, 14.8 percent as high-Btu be $7,440,000, and preproduction capital costs would be gas, and 8 percent as excess power. The plant would $36,052,000 at North Ridge. require about 65 acres.

Operating costs for both areas are estimated to be $0.88 The HYTORT process concept is based on direct, non- per ton for shale and stripping. Based on shale only, catalytic hydrogenation of kerogen at high pressures and estimated operating costs are $2.19 per ton at Pea Ridge controlled heat-up rates. Figure 3 shows a HYTORT and $2.54 per ton at North Ridge. These costs do not process flow diagram. The HYTORT retort is a include associated capital cost. refractory-lined, high pressure, vertical vessel through

2-4 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 MINING SHALE OIL STORAGE

I TAIL GAS SULFU A LIGHT OIL SCREENING CLEANUP RECOVERY RECOVERY ASTORAGE I

I I .11, GAS I ACIDGAS I______AMMONIA ErORTSNG:.___J__.___{1_ I COOL j REMOVAL LREMOVAL

RUNOFF CT. AND NASTEWATST TREATED r (OILER TREATMENT WATER (LOWDOWN I CZ1A

SPORLISTION____•7__•j__ TOSTACE TI AM AN DI fl1-. COOLING SCRUASINOf r osopJ SLUDGE TO DISPOSAL

GIALE U TILITI ES

FIGURE I PARAHO PROCESS FLOW DIAGRAM

(Salt 00 SIT AIRIF III ROE 10PM 33110 •1P:i.;.t:r4.._. - LOsT OIL A 2.112 00 aND IF534 IS CR01335 DLISIESTTNE .7(4 IIICIIRTUSA...... 401 50.7Th lot PM 322$ I74GRT POWER t1tLw_P_ TS ITU:EAR-TI IRA RI TOTAL AIJOS .1--•. SLILPIJR TIN .340 TO : - - - SIENT Es ALEAILSIDGE 71.501 TOOl' IS -- - I Co:Ic o; COOLING TONE' LTSSISITC. 34540 34.333 003 TOTAL MISI 00407

•ACTU&L PLAIT INPUT IS 33400 TO 3500 TI001IALEPINEN GINEPATEOOLIRIRI Co ISA INC & IC REt N NO

FIGURE 2 OVERALL MATERIAL AND ENERGY BALANCES PARAHO PROCESS 30,000 T/D EASTERN OIL SHALE PLANT

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-5 FIGURE 3 HYTORT PROCESS FLOW DIAGRAM

which oil shale flows downwardly and is contacted The gross annual operating costs for the Paraho and countercurrently with an upward flow of hot gases. The HYTORT plants are $63.1 million and $86.1 million retort is operated at about 550 psia, so high pressure respectively. The consumable costs include catalyst for shale feed and discharge systems are required. The shale chemicals, water, electricity, and operating and main- is progressively heated to retorting temperatures of tenance supplies. The labor and overhead costs include 1,200°F. The heat required for retorting is supplied by the costs of operating and maintenance labor, payroll combusting part of the hydrogen stream with oxygen and burden, general and administration. The net annual raising its temperature to 1,450°F. The retorted shale is operating costs are $10.6 million for Paraho and $74.1 cooled using the hydrogen-rich stream in the bottom million for HYTORT. section of the retort. The cooled spent shale is removed from the retort through lock hoppers. Material and Cash flow analyses were made several different ways, energy balances for a HYTORT plant processing eastern and some of the results are presented in Table 2. At 100 oil shale are shown in Figure 4. percent equity, the Paraho plant provides a return of about 12 percent at $40 per barrel and about 14 percent In addition to 30,000 TPI) of raw oil shale, the HYTORT at $50 per barrel shale oil price. The HYTORT plant, at plant would require about 4,100 gpm of makeup water, 100 percent equity, provides about 12 percent return at 565 TPD of oxygen, 45.3 MW electric power, and 269,700 $60 per barrel and 14 percent at $70 per barrel. For the scfm of air. The plant would produce 10,217 BPD of Paraho plant, further cash flow analysis was made shale oil and 104 TPI) of anhydrous ammonia. About assuming 75 percent debt at 12 percent interest and 25 44.9 percent of the input energy would be recovered as percent equity. The return on equity at $40 per barrel liquid product. The HYTORT plant would also require shale oil price is about 24 percent on a pass-through about 65 acres. basis. Based on detailed process analyses, +25 percent capital costs were developed. The initial plant investment costs for the Paraho and HYTORT are $504 million and $695 million respectively. These costs are for grass roots plants and include mining, material handling, retorting, oil recovery, facilities to meet enviromental standards, and all of the necessary off-site facilities. Total initial capital required for the Paraho and HYTORT plants is $647.2 million and $890.3 million respectively, as shown in greater detail in Table 1.

2-6 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 r-- C

inn it,., - - I,o 'I'

FIGURE 4 OVERALL MATERIAL AND ENERGY BALANCE HYTORT PROCESS 30,000 T/D EASTERN OIL SHALE TABLE 1

CAPITAL AND OPERATING COSTS 30,000 TONS/DAY EASTERN OIL SHALE PLANT (4th Quarter 1980 Dollars) A. Capital Cost ($MM)

Paraho H YTO RT

Initial Deferred* Initial Deferred

Total Direct Cost 382.5 539.7 Professional Services, Field Indirects, Insurance, etc. 122.0 155.3

Plant Investment Cost 50475 695.0 Working Capital 17.4 21.8 Interest During Construction 125.8 173.5' -'4 Startup Cost Expensed Expensed

Total Capital 647.7 126.1 890.3 140.8 B. Operating Cost ($1000)

Consumables 23,614 39,525

Labor & Overhead 23,556 24,571

Taxes & Insurance 15,908 21,955

Total Gross Operating Cost 63,078 86,051 By-Product Credit (52,499) (11,946) Net Operating Cost 10,579 74,105 Additional Investment from year 2 to 20 •On the 75% of the initial plant Investment at 12% interest Expensed at 50% of the first year's revenue

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-7 TABLE 2 ECONOMIC ANALYSIS 30,000 TONS/DAY EASTERN OIL SHALE PLANT

A. 100% Equity

Return on Equity, % --

Selling Price Stand-alone Pass-through Stand-alone Pass-through $/bbl Venture Venture Venture Venture 40 11.4 12.1 5.7 5,9 50 13.7 14.4 8.8 9.1 B. 75% Debt, at 12%/25% Equit 40 10.4 24.1 50 18.2 30.8 C. 100% Equity Selling Price $/bbl Return on Equity Stand-alone Pass-through Stand-alone Pass-through Venture Venture Venture Venture 12 42.50 39.70 61.90 58.00 14 51.80 48.20 72.00 68.40

PLATEAU PLANS 20,000 BPD REFINERY ADDITION include a raw shale oil pipeline from the supply sources FOR SHALE OIL (notably Paraho-Ute) to the refinery and a products pipeline from the refinery to Salt Lake City where it will Plateau, Inc., a wholly owned subsidiary of Suburban connect with the Chevron products pipeline. Products Propane Gas Corporation, has submitted a proposal to could then be supplied by pipeline to the DOD use the U.S. Synthetic Fuels Corporation for a loan guaran- locations. tee, product purchase agreements, and price guarantees for a raw shale oil upgrading and refining project at its A preliminary review of estimated utility requirements Roosevelt, Utah, refinery. Plateau plans to build and (electricity, natural gas, raw water, and effluent water) operate a 20,000 BPCD commercial raw shale oil upgrad- have been made and discussed with the appropriate ing and refining complex adjacent to its existing refinery suppliers. At this time, all suppliers are extremely in Duchesne County. The complex will be located less encouraging and could not see any major problems in than one mile west of Roosevelt and approximately 140 supplying the necessary utilities in the time-frame re- miles east of Salt Lake City. quired.

The proposed 20,000 BPD raw shale oil hydroprocessing Plateau plans to complete a feasibility study for the addition will produce 7,000 BPD of JP-4, 2,000 BPD of project in early 1982. Field construction of the complex gasoline, and 1.000 BPD of diesel fuel for the Depart- will start in early 1983, and shale oil processing facilities ment of Defense (DOD). The remaining shale oil pro- will be producing by late 1984. This early start-up can ducts, 7,000 BPD of gasoline, 2,000 BPI) of diesel fuel, only be realistically attained by expediting all portions and 1,000 BPD of Jet-A, will supplement the refinery's of the project and managing the project most efficiently. crude oil derived products and be sold to Plateau's Such critical-path items as purchasing of long delivery present customers and to the new local market resulting equipment and times for review and approval of permits from synfuels development in the area. will have to be minimized to attain the early start-up objective. The refinery additions will comprise a raw shale oil hydrotreater, hydrocracker, naphtha hydrofiner, and The Ralph M. Parsons Company will be the major sub- catalytic reformer, and the attendant hydrogen, sulfur, contractor for the project. They will provide adminis- and waste water treating plants plus the necessary trative services for coordination and control of the utilities and environmental facilities. The shale oil project as well as performing detailed engineering, cost processing units are an extension of well proven refinery estimating, and field construction. processes to shale oil. All processes have been or are currently being tested by UOP, Chevron, and others in DOE-or DOD-supported projects. The complex will

2-8 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 COLORADO SYNFUELS, INC. PLANS MICROWAVE Prototype Will Be Designed and Built FIELD TEST IN WYOMING At the time of the SEC filing, no prototypes of the On February 18, 1981, the Colorado Synfuels, Inc. (CSI) Jeambey device existed. CSI has arranged with Sage filed a registration statement (Form S-I) with the U.S. Laboratories, Inc., a designer and manufacturer of Securities and Exchange Commission to enable CSI to microwave devices with experience in the area of indus- offer its stock to the public. CSI proposes to field test a trial microwave heating, for the design and construction true in situ microwave technique, the Jeambey process, of certain hardware to be used in experimental testing on a 40-acre tract leased from the State of Wyoming. and a field prototype of the Jeambey device. The underwriter is M.S. Wien & Co., Inc. CS! will seek to acquire the right to perform initial Initially, the principal efforts of CSI will be directed testing in an existing oil shale mine to facilitate experi- toward the development of the Jeambey process for the mental observation, to reduce experimental expenses for extraction of shale oil. Later CSI hopes to investigate basic engineering and drilling, and to eliminate logging the potential of the processfor use in tar sands and costs, If CSI cannot acquire the right to experiment in a heavy oils. mine, the tests will take place on its pilot test site. Tests will be performed in the Wilkins Peak Member of After completion of the mine experiments, if further the Green River Formation, where oil shale deposits development of the Jeambey process is warranted, CSI exist in vertically discontinuous horizontal beds. There will have two prototypes built. Sage Laboratories esti- are approximately 20 such beds averaging 3 feet in mates that the cost will be $300,000. thickness, each of which is separated by low grade oil shale. These discontinuous beds lie in horizontal planes. Pilot Program Planned

Jeambey Process Described The planned pilot program involves drilling a borehole, sealing off the upper aquifer, inserting a production pipe Colorado Synfuels received from its President, C. with the Jeambey device at its end, positioning the Graham Jeambey, a contribution of U.S. Patent No. microwave energy into the rock. The organic material in 4,193,448, issued on March 18, 1981, in exchange for oil shale is the primary component that absorbs micro- 3,720,000 shares of stock. The device has not been built, wave radiation. and therefore it has not been tested in the laboratory or the field. Pyrite, analcime, and illite clay occur in Wilkins Peak Member oil shale, and these minerals have absorptive The proposed apparatus includes an elongated shell con- characteristics. They are believed to be present in small taining a microwave generator, a microwave disbursing quantities, but their amount and the extent to which chamber, and an oil recovery chamber. The microwave they absorb microwaves must be experimentally deter- generator will be electrically powered, and its operation mined. Carbon coke, which is a product of pyrolysis, will require electrical current. may also absorb microwaves.

The device is intended to be placed in a borehole and The precise distance of penetration over which micro- emit microwaves in defined patterns with varying inten- wave energy can be absorbed by the organic material sities. The design permits it to be moved through a requires experimental determination. The distance is vertical borehole to the location of an oil shale bed. critical in evaluating the potential of the Jeambey device for commerical use. Feasibility Study Completed It is important for the gas production created by micro- A feasibility study was co-authored by John Ward Smith wave heating to supply sufficient energy to support and Thomas Beard, both shareholders of CSI. Smith was power for microwave generation. The amount of product subsequently appointed to the CSI board of directors. gas can be varied by altering heating rates. The precise composition of product oil and gas for various frequency The feasibility study notes that, because of its produc- and power applications is not known and must be experi- tion of planar radiation patterns, the Jeambey device mentally determined in the pilot project. In the event utilizes a technology which may be feasible for recovery gas production is insufficient, auxiliary fuel will be used of oil from vertically discontinuous oil shale deposits. to generate electricity. The study notes that the process contains environmental advantages, including minimal terrain changes and con- Lease Agreement Contains Options, Commitments trolled impact on the aquifers in the area. The study concludes that radio frequency heating of oil shale Colorado Synfuels has a 5-year lease on a 40-acre tract deposits to produce oil utilizing the Jeambey device in Sweetwater County, Wyoming on state land (NE* SE, appears promising and warrants investigative develop- T24N, R108W, 6PM). CS! has committed to spend at m ent. least $300,000 in the first year, $200,000 during the second year, and $100,000 during the three remaining The feasibility study was based only on a theoretical years of the lease. Additionally, there is a 5 percent evaluation of the Jeambey process. The conclusions of production royalty for any hydrocarbons produced and the authors were partly based upon studies of microwave sold from the experimental operation. heating of oil shale previously conducted by others. The authors did not subject oil shale to microwave radiation in the laboratory or the field. There was no testing of the Jeambey device.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-9 At any time during the term of the lease, CSI may a cube measuring approximately 34 feet square, will certify to the State of Wyoming that it has produced yield approximately 34 barrels of shale oil and 6,000 hydrocarbons in commercial quantities and that its pro- cubic feet of gas. Since the process removes most of the duction process is economically and technically feasible. shale rock, sulfur, nitrogen, and heavy metals, the kero- Wyoming has agreed, in that case, to offer additional gen can be introduced directly into existing refineries in lands on a competitive bid basis: a manner similar to crude oil. T24N, R108W, 6PM (excluding the NE*, SEfl The mineral brine produced by this technology is parti- T24 N, RI09W, 6PM cularly rich in aluminum and iron compounds. Additional T23 N, 11109W, 6PM recovery processes applied to the mineral brine can, it is T23N, 11108W, 6PM claimed, recover a wide variety of other metals and T22N, 11109W, 6PM inorganic chemicals. The Horizon "Fact Sheet" lists the T22N, 11108W, 6PM following: The offer to lease would occur within 60 days of Magnesium notification of the State by CSI. CSI would have the Potassium right to match any other bid received and to be granted Calcium the leases. In considering whether CS! has successfully Sodium matched any competing bid, the State will consider and Copper determine whether the competing bidder has the capa- Lead bility to produce the oil shale deposits on a timely, Gold feasible, and economical basis. Thallium Zinc Wyoming agreed that it will not offer the lands for three Titanium - years unless one of the following occurs: Manganese Sodium Carbonate The State determines that it is economically Sodium Bicarbonate feasible to develop the oil shale on these Calcium Carbonate lands by another process. Magnesium Chloride CSI notifies the state that its production As applied in situ, the solvent is piped from the process- process is economically and technically ing plant and injected into a shaft. There it begins to feasible on a commercial scale. dissolve the oil shale, forming a mineral brine in which undissolved kerogen is suspended. The mineral brine and CS! elects to surrender or is in default of the kerogen are removed from the expanding cavity and agreement. pumped to the processing plant. After the cavity reaches its full size, it can be used for disposal of the Colorado Synfuels paid $10 initially for the agreement processed shale. Since the spent shale is hard and non- and must pay $1 per acre per year for the 40-acre tract. porous, leaching of saline mineral constituents is eliminated. Comment NEW PROCESS IS CLAIMED TO DISSOLVE OIL SHALE Horizon's "Fact Sheet" makes several apparently ex- Horizon Technology, Inc., of Fort Collins, Colorado, has aggerated claims, such as the amounts of gas and iron submitted patent applications for a process that uses a that can be recovered. Such exaggerations lead to recycling chemical solvent to dissolve oil shale rock and skepticism. On the other hand, the development team is to separate metal and mineral by-products from the composed of highly educated, competent, and reasonable kerogen. Horizon projects costs of shale oil produced scientists. Two members, Don R. Jorgenson and Dr. Joel with its process to be less than oil produced in conven- B. Dubow, have done fundamental research at Colorado tional retorts. Information presented here appeared in a State University into electrical and thermal properties "Fact Sheet" distributed to the company's shareholders. of oil shale. The third member, Dr. Soma Kurtis, is retired from Marathon Oil and has been associated with At the dissolution site, a chemical solvent removes most oil shale for a number of years. We anxiously await of the carbonates and some of the silicates, leaving publication of patents and papers that report verifiable behind an enriched process kerogen containing only S to process data and costs. 15 percent shale rock. As it reacts with the oil shale, the solvent is transformed into a mineral-rich brine which becomes the source material for the recovery of a variety of commercially important metal and mineral products. After further processing to separate the by- products from the brine, the solvent is regenerated, using a proprietary method, and recycled back to the processing plant. This final step also yields a cement- like processed shale which is returned to the mine. Kerogen, as it is isolated by the process, is a dark, wax- like solid. When heated above 700°F, one ton of kerogen,

2-J 0 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 FOREIGN

EXTRACTION OF 31.3 MILLION TONNES OF OIL Chekalyuk asserts that the total reserves of fuel con- SHALE IN ESTONIA REPORTED FOR 1980 tained in oil shale exceeds all other USSR mineral fuels combined. In particular he describes oil shales in the Yu. Tambet, general director of the Production Associa- western oblasts of the Ukrainian SSR. Deposits of tion tEstonslanetstT (Estonian Shale), reported that the menilite shale are encountered widely at various depths association extracted 31.3 million tonnes of oil shale in within the limits of the inner zone of the Carpathian 1980. The report appeared in the January 14, 1981, issue depression and the contiguous strip of folded Carpa- of Sovetskaya Estoniya in an article entitled "Raising the thians. He estimates that 5 trillion tonnes are contained Efficiency of Extracting Shale." Production growth was in the deposit with an average concentration of combus- achieved primarily by increasing extraction at the two tible matter of 12 to 15 percent. newest enterprises, the "Estonia" mine and the "Oktyabr'skiy" open pit mine. Chekalyuk expresses concern that the "geological ministries of the USSR and the Ukrainian SSR have still not The "Oktyabr'skiy" mine produces 5 million tonnes per received state assignments to explore and estimate the year associated with an enrichment factory. The industrial reserves of fuel in the menilite shale deposits. "Sirgala" open pit mine produces 3.5 million tonnes per Nor is the USSR Ministry of Petroleum and Gas Industry year. Eighty percent of the oil shale extracted in showing any special interest in developing these shale Estonia is used to produce electrical and thermal energy. deposits. To make matters still worse, the procedures for extracting the fuel have still not been perfected as Tambet reports that it takes at least 15 years to design, they should." put into operation, and assimilate the planned capacity of the large mines. Between 1990 and 1995, the Chekalyuk continues: "Our Institute of Geology and "I{okhtla" and "Tammiku" underground mines and the Geochemistry of Mineral Fuels of the Ukrainian SSR "Vivikond" open pit mine will shut down due to depletion Academy of Sciences proposed integrated processing of of the resource. The total capacity of these mines is shale into scarce construction materials and into raw nearly 6.5 million tonnes per year. Tambet recommends materials to be used in ceramics and chemical industry. a new mine and railroad branch near Kuremyae. In in the acquisition of activated charcoal and Portland addition, the "Sirgala" open pit mine needs a new receiv- cement additives, and so on. The tar and gas fuel (a ing and crushing complex that is located closer to the total of up to 80 kilograms per tonne of shale) produced basic faces; the old complex is now too far away. He as by-products could have competed even at that time also recommends the modernization of the "Viru" mine. with improbably low-priced petroleum. Even a small facility was created in the Carpathians to work out the Another article, entitled "The Future of the Estonian plant procedures for integrated shale processing. Fuel and Power Industry," reports that shale-based electric power production at Pribaltiyskaya and Estonskaya "It is now becoming profitable to process menilite shale State Regional Electric Power Stations is among the into fuel as well. However, this must be done at a lowest in cost in the northwest USSR. While the basic modern level, with a consideration for environmental load is gradually being switched to nuclear electric protection. Subsurface gasification or subsurface heat- power stations, the shale-based electric power stations treatment of menilite shale, as well as other methods of Estonia must be more flexible, which requires the borrowed from the best experiences of Soviet oilmen, creation of new equipment and a search for and rapid may be the only way to satisfy all requirements." adoption of new technology. Researchers are investigating the burning of oil shale in vortical furnaces and fluidized beds. JORDAN PURSUING ADDITIONAL OIL SHALE STUDIES

SOVIET GEOLOGIST URGES EXPANDED USSR The Natural Resources Authority of Jordan has awarded OIL SHALE DEVELOPMENT a contract to Kleckner and Lurgi of West Germany for feasibility studies on producing oil from the Lajjoun oil Professor E. Chekalvuk, Diredtor of the Section for the shale deposits. The study will be completed in mid-1982. Problems of Subsurface Hydrocarbons at the Ukrainian The Authority is also expected to sign a contract soon SSR Academy of Sciences Institute of Geology and with a West German group for a $1 million feasibility Geochemistry of Mineral Fuels, has suggested the need study for a 50,000 BPD retort. for expanding research on USSR oil shale reserves must be reflected in the "Fundamental Directions of Economic The USSR is already conducting a study of developing and Social Development of the USSR in 1981-1985 and in these deposits. This Soviet study will cost $750,000 and the Period to 1990." Chekalyuk's article, "Shale Awaits is expected to take 26 months. Its Master," appeared in the December 5, 1980 issue of "Pravda Ukrainy." "Fundamental Directions" is a draft The Jordan Electricity Authority has awarded a contract report by the Communist Party's Central Committee to to Technoproxeport of the USSR for carrying out techni- the 26th Communist Party Congress, and it constitutes cal studies of a power station to be fueled by direct the USSR's 11th Five Year Plan. combustion of oil shale. About 800 million tonnes of oil

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-11 shale from Lajjoun (17 km west of Qatrana) would provide fuel for a proposed power plant at a new site near Qatrana, 80 km south of Amman.

2-12 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981

SOCIOECONOMICS

RIO BLANCO COUNTY PLANNING COMMISSION RBOSC stated that it might propose permanent housing RECOMMENDS SOCIOECONOMIC CONDITIONS FOR near the tract during the commercial phase. Although it C-a PERMIT APPROVAL is not part of this particular permit application, the Commission specifically rejects this concept. Pursuant to obtaining a special use permit for its Lurgi retort and associated surface mine, Rio Blanco Oil Shale Transportation Company (RBOSC) submitted an Impact Analysis State- ment to the county. The Rio Blanco County Planning The county has designed the C-a to Rangely road in such Commission addressed each element and made many a way that it conflicts with the site for the Lurgi recommendations about conditions and additional demonstration project. The Commission recommends measures. that RBOSC pay for any rerouting costs. It also recommends that RBOSC provide a fair share of the funds to RBOSC's experience with Rio Blanco County parallels construct this road and that final construction start that of Union Oil with Garfield County. The conditions within two years or at a time when total employment at placed on some of Union's special use permits were Tract C-a reaches 600. discussed on page 2-29 of the March 1981 issue of the CameronSynthetic Fuels Report. RBOSC objects to The Commission found RBOSC's contribution of $45,000 many of the conditions and recommendations, and the for maintenance of the Piceanee Creek Road acceptable. final decision may be somewhat different from the It recommended that RBOSC be required to contribute conditions reviewed here. $100,000 as its share of the cost of a bypass around Rifle. Housing Law Enforcement RBOSC proposed bachelor quarters on or near Tract C-a as part of a long range strategy. The Commission RBOSC stated their belief that no mitigation is needed recommends that this not be approved as housing impact at this time, but that it would fund one deputy and mitigation. RBOSC also proposed an increase in the overhead when a need is demonstrated. The Commission existing on-tract bachelor quarters from 6 units to 18 believes that present need has already been demon- units. The Commission recommends disapproval. strated and that RBOSC should provide the salary and overhead costs for one deputy sheriff for Rio Blanco RBOSC proposed development of Ute Terrace Mobil County and one police officer for the Town of Meeker. Home Park as bachelor and family housing. The Commission recommends that this proposal be accepted RBOSC made no commitment to jail facilities. The subject to the following: Commission believes that this need is already here and that RBOSC should be required to commit to a fair share • A minimum of 100 spaces should be of the cost of jail expansion. developed during 1981. Recreation • Up to 20 percent of the spaces should be made available to the general public. RBOSC agreed to assist the West Garfield County Recreation District. The Commission agrees and recom- • RBOSC should provide adequate internal mends that $13,500 be committed. security for Ute Terrace with such security arrangements to meet with the approval of RBOSC stated its willingness to work with the Eastern the sheriff or the Meeker Police Department. Rio Blanco County Recreation Commission. The Plann- ing Commission recommends that RBOSC fund a recrea- • An additional access road to the mobile home tion coordinator for the Recreation Commission for a park should be provided, satisfactory to the minumum of 18 months. The Commission also recom- county, the Town of Meeker, and School mends that RBOSC pay a portion of the costs of capital District Re-1. facilities for recreation. During construction, RBOSC proposed a family housing Miscellaneous program which would provide mobile homes for starter housing and assist families in locating housing. The The Commission believes that the idea of an industrial Commission enthusiastically endorsed this proposal. association as a means of dealing with impact mitigation has a good deal of merit. The Commission agrees that The Commission noted that the Impact Analysis State- the companies, towns, and county establish a contractual ment made no mention of recreational vehicles (RVs), relationship to deal with impact mitigation. and it noted that there have been problems of RVs locating on public lands near Tract C-a. The Commis- The Commission recommends that RBOSC and other sion recommends that RBOSC provide a minimum of 20 energy companies establish an impact mitigation fund. liv spaces in Ute Terrace or some other location It recommends that an amount equal to 7 percent of the approved by the county.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-13 yearly budget for a project be set aside for impact mitigation during the construction phase of a project. Credit could be granted against taxes paid, if permitted by statute, once the project is operational.

2-14 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 ENVIRONMENT

LOS ALAMOS PUBLISHES HEALTH AND - ENVIRONMENTAL PROGRAM STATUS REPORT Chemical Composition of Shale Oil Waters Los Alamos Scientific Laboratory has published "The Los - Ames/Salmonella Mutagen Assay of Oil Alamos Integrated Oil Shale Health and Environmental Shale Process Water Program: A Status Report." The report is available through P.O. Box 1663, Los Alamos, New Mexico 87545 - Exogenous Metabolic Activation of Pro- as report number LA-8665-SR. The work is being cess Waters in Mammalian Cell Cul- Performed under U.S. Department of Energy Contract tures W-7405-ENG 36. The status report was compiled by - L.M. Holland and C.G. Stafford. Determination of Direct-Acting Muta- gens in Shale Oil Retort Process Water The report is comprehensive and is an excellent - Light Activation of Shale Oil By-Pro- reference source. It includes the status of many envi- ducts ronmental and health research projects, as follows: Effects of Process Waters from Oil Shale Industry on In Vitro Induction of • Field Studies Sister Chromatid Exchange - Paraho Industrial Hygiene Study - The Prenatal Toxicology of Oil Shale - Air Sampling during Anvil Points Fire Retort Water in Mice Extinguishment - Analytical Chemistry of Oil Shale Pro- - Medical Studies of Oil Shale Workers cess Waters - Air Sampling at Occidental Oil Shale, - Assessment and Control of Water Con- Inc. Facility at Logan Wash tamination Associated with Shale Oil Extraction and Processing - Field Sampling—Rio Blanco Oil Shale Project - Nickel Arsenide Solubility in Oil Shale Aquifer Water and Cell Culture Medium - Piceance Deer Project • Arsenic and Nickel Species of Concern • Airborne Effluents - - Arsenic, a Toxic Oil Shale Constituent: Inhalation and Intratracheal Exposures Its Effects on Cell Proliferation and - Neutron Activation Studies of Lung Histone Phosphorylation Burden - Nickel Arsenides: Potential Biological - Oil Shale Aerosols for Inhalation Toxi- Hazards in the Oil Shale Retort Process cology - The Toxic Effects of Particulate Nickel - Development of a Laboratory Retort Arsenide on Cell Proliferation for Inhalation Experiments ## ## - Analytical Chemistry of Respirable Size Oil Shale Dusts DOE INSPECTOR GENERAL INVESTIGATES ANVIL - In Vitro Tests for Determining the Car- POINTS EIS DELAY cinogenic Potential of Spent Shale Par- ticulates The Office of the Inspector General (IC) has completed an investigation into the delays surrounding preparation S Oils of an environmental impact statement (EIS) for addi- - Ames/Salmonella Mutagen Assay of tional research at Anvil Points near Rifle, Colorado. Shale Oil The entire process may ultimately take five years. - Exogenous Metabolic Activation of In May 1972, the Department of the Interior leased the Shale Oils in Mammalian Cell Cultures Anvil Points Facility to Development Engineering, Inc., a - Effect of Shale Oil on In Vitro Induction wholly owned subsidiary of the Paraho Development of Sister Chromatid Exchange Corporation, for the purpose of conducting oil shale research. In 1974, Paraho proposed to expand its efforts - Cytogenetic Effects of Shale-Derived at Anvil Points to include the construction and operation Oils and Related By-Products in Mice of full sized module of the Paraho retort. Paraho also - Long-Term Epidermal Carcinogenicity requested an increase in the amount of oil shale that Studies could be mined under the lease from 400,000 tons to 11,000,000 tons. - The Effect of Exposure Conditions on Dermotoxicity

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-15 In November 1975, the Energy Research and Develop- • Changes in FE and EV staff responsible for ment Administration (ERDA—now a part of DOE) the review of various versions of the draft advised Paraho that an EIS would have to be prepared EIS. before proceeding with the proposed effort. An initial draft EIS was prepared in January 1977 by the Laramie • Changing perspectives over time of EV staff Energy Research Center on its own initiative and was and changes in regulatory requirements which subsequently provided for review to the office of the led to more comments and proposed changes Assistant Administrator for Environment and Safety, on each succeeding draft EIS. now the office of the Assistant Secretary for Environ- ment (EV) in DOE. As of November 1980, nearly four • Requests by EV staff for site specific and years after the initial draft EIS was prepared, there was design data which were not available, or still not a final EIS. There are indications that a final which Paraho was reluctant to provide until EIS will not be available until late 1981. an EIS was approved because of the cost involved. Four revisions of the draft EIS were provided to EV for comment during the period January 1977 to March 1980, • New regulations issued by the Council for when the 10's review began. The IC attributes much of Environmental Quality. the delay to a cumbersome and unrealistic review process within DOE. Furthermore, review of the draft EIS • Lengthy periods, one as long as four months, by EV and its management support service contractor, taken by FE to review and transmit the draft Aerospace Corporation, resulted in requests for informa- EIS to EV. tion, some of which was either not available or would be costly to obtain. The -reviews also seemed to result-in • Similarly lengthy periods, some as long as increasing criticism and more proposed changes with - five months, required by EV to review- and each succeeding draft. Some of the changes resulted provide comments on the draft EISs. from changes over time in regulatory requirements. The IC strongly urges the highest priority be given to the At the beginning of the IC's review in March 1980, EV publication of an acceptable final EIS with the participa- had not yet approved a draft EIS for release for public tion of the EV and FE Assistant Secretaries. comment. The quality of the latest available draft EIS was described by EV staff as not reflecting the state-of- the-art in EIS preparation. However, in response to interest expressed in November 1979 by the Office of the Secretary in the delays, EV reluctantly considered approving that version of the draft EIS for release for comment. Rather than approving the draft EIS, EV delayed its review because of indications that Paraho might abandon Anvil Points for a site in Utah. In EV's opinion, such an action would obviate the need for an EIS. However, EV was advised by Fossil Energy (FE) in late March 1980 that Paraho desired to continue work at Anvil Points and that FE wanted EV to expedite its review of the latest version of the draft EIS on a priority basis. As a result of the increased attention, a draft EIS was released for public comment on August 22, 1980. The comment period ended on November 24, 1980. The IC was informed that extensive comments were received, many of which were critical. Much of the criticism concerned lack of detail, specific plans, and certain data in the draft. A proposed schedule for the final EIS indicates another draft would not be provided to EV for review until September 1981, with the record of decision scheduled for January 1982. The 10 identified the following as contributing to the failure by DOE to obtain an approved EIS after three years of effort and four versions of the draft EIS: The confusion caused by the resultant transfer and reassignment of responsibilities when ERDA was abolished and DOE was created.

The geographical separation of elements of EV staff and FE staff.

2-16 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 LAND

STATUS OF OIL SHALE LEGAL PROCEEDINGS NOTED 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 1

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 contestces 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 2-1, for discussion. As a result of the adverse decision, Shell Oil, one of the claimants, took the ease to the U.S. District Court in Denver, under Civil Action 7417-739. 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 Docket No. 77-1346. Decision affirmed in Shell's favor 1/25/79. The case is now under appeal to the U.S. Supreme Court, Docket No. 78- 1815.

Contest No. Cob. 193 & 260: USA vs. TOSCO These contests will be decided by the courts in Civil Action 8680, 8685, 8691, and 9202, an of which cases are before the U.S. District Court and the 10th U.S. Circuit Court of Appeals in Denver. BEFORE THE U.S. DISTRICT COURT IN DENVER:

Civil Actions 9252 H.H. Hugg VS. Secretary of the Interior 9458 J. 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. On March 24, 1967, the Court suspended proceedings in these cases pending final disposition of related cases (8680 et at.). Judge Finesilver, on January 27, 1981, ordered the cases re-opened even though 8680 was still active. A related article appears in the March 1981 Cameron Synthetic Fuels Report, page 2-24.

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 1-1). 02/04/69 10th Circuit Court of Appeals upheld District Court Decision. (SFl, page 1- 6). 12/08/70 Supreme Court reversed decision and remanded case to District Court. (SFR, 3/71, page 1-1).

03/15/74 District Court ruled DOI could not deny patents based on circa-1930 proceedings, directed DO! to reprocess patent applications. (SFR, 6/74, page 2-4).

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-17 09/22/75 10th Circuit Court of Appeals remands cases to District Court with instruc- tions to DOl 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. (SFR, 9/76, page 2-7). 01/17/77 District Court remanded case to DO! for further proceedings in expedited manner.

07/01/77 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 1, 1978, showing exact timetable contemplated 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 DO!. 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 7/11/72 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 2-1. Trial held 2/23/77. Order issued on 5/25/77 stating that no valid ground exists for ciiillation of the patent. 7/22/77 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 8680, 8685, 8691 and 9202 (combined). These are discussed under separate heading. On 2/17/77 Judge Finesilver remanded the case to DO!. DO! is to expeditiously process patent application affecting claims involved in the action. Any and all objections must 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 7/1/77, 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 fiijiiction without contest.

2-18 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981

Civil Action C-80-0240A Sohio Shale Oil Co., et at. vs. Secretary of the Interior, et al. Sohio, Phillips, and Sunedco, lessees of Tracts U-a/U-b, tiled 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."

COLORADO BLM OFFICE PUBLISHES MAP OF PRE-1920 CLAIMS The Colorado State Office of the U.S. Bureau of Land Management has published a map of the Piceance Creek basin showing the unpatented pre-1920 mining claims that were re-recorded in accordance with the Federal Land Policy and Management Act of 1976. Copies of the map, entitled "Piceance Creek Basin Oil Shale Status," were inserted in the March 1981 issue of the Cameron Synthetic Fuels Report. Additional copies are available at $2.00 each from the Bureau of Land Management, Colorado State Office. 2000 Arapahoe Street, Denver, CO 80205. A related article, describing the location and ownership of these claims, appeared on page 2-21 of the March 1981 issue of the Cameron Synthetic Fuels Report. The map does not indicate ownership. The Utah State Office of BLM does not plan to publish a similar map of the Uinta basin.

####

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-19 STATUS OF OIL SHALE PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name Amoco Rio Blanco Oil Shale Company (C-a) ...... 2-23 Atlantic Richfield Company Paraho-Utc Project ...... 2-23 Braun, C.F., & Company Naval Oil Shale Reserve Development ...... 2-25 Central Pacific Minerals Rundle Project ...... 2-23 Chevron Shale Oil Company Chevron Clear Creek Project ...... 2-22 Paraho-Ute Project ...... 2-23 Cleveland-Cliffs Iron Company Paraho-Ute Project ...... 2-23 Pacific Project ...... 2-23 Conoco, Incorporated Paraho-Ute Project ...... 2-23 Chevron Clear Creek Project ...... 2-22 CSR Limited Julia Creek Project ...... 2-25 Davy -McKee Corporation ParahorUte Project ...... 2-23 Equity Oil Company Equity Oil Company ...... 2-24 Esso Australia Ltd. Rundle Project ...... 2-23 Exxon Company USA Exxon Colorado Shale Project ...... 2-25 Colony Development Operation ...... 2-22 Geokinetics, Inc. Geokinetics, Inc ...... 2-25 Gulf Oil Corporation Rio Blanco Oil Shale Company (C-a) ...... 2-23 Gulf Research & Development Co. Naval Oil Shale Reserve Development ...... 2-25 Husky Oil Company Paraho-Ute Project ...... 2-23 Mobil Research & Development Corp. Paraho-Ute Project ...... 2-23 Mono Power Company Paraho-IJte Project ...... 2-23 Multi Mineral Corp. Multi Mineral Corporation ...... 2-25 Nahcolite Mine #1 ...... 2-25 Occidental Oil Shale, Inc. Cathedral Bluffs Shale Oil Company (C-b) ...... 2-22 Occidental Oil Shale, Inc ...... 2-22 Placid Refining Paraho-Ute Project ...... 2-23 Paraho Development Corporation Paraho-Ute Project ...... 2-23 Petrobras Petrosix ...... 2-23 Phillips Petroleum Company White River Shale Project (U-a/b) ...... 2-24 Paraho-Ute Project ...... 2-23 Rio Blanco Oil Shale Company Rio Blanco Oil Shale Company (C-a) ...... 2-23 Southern California Edison Paraho-Ute Project ...... 2-23 Southern Pacific Petroleum Rundle Project ...... 2-23 Standard Oil Company (California) Chevron Shale Oil Company ...... 2-22 Paraho-Ute Project ...... 2-23 Standard Oil Company (Indiana) Rio Blanco Oil Shale Company (C-a) ...... 2-23 Standard Oil Company (Ohio) White River Shale Project (U-a/b) ...... 2-24 Paraho-Ute Project ...... 2-23 Pacific Project ...... 2-23 Sunedco White River Shale Project (U-a/b) ...... 2-24 Paraho-Ute Project ...... 2-23 Superior Oil Company Pacific Project ...... 2-23 Tenneco Cathedral Bluffs Shale Oil Company (C-b) ...... 2-22

2-20 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Company or Organization Project Name

Texaco Incorporated Paraho-Ute Project 2-23 Texas Eastern Synfuels, Incorporated Paraho-Ute Project 2-23 Tosco Corporation Colony Development Operation 2-22 Naval Oil Shale Reserve Development 2-25 Tosco Sand Wash Project 2-24 TRW Naval Oil Shale Reserve Development 2-25 Union Oil Company of California Union Long Ridge Project. 2-24 U.S. Bureau of Mines Multi Mineral Corporation. 2-25 U.S. Department of Defense Naval Oil Shale Reserve Development 2-25 U.S. Department of Energy Equity Oil Company 2-24 Geokinetics, Inc...... 2-25 Naval Oil Shale Reserve Development 2-25 Occidental Oil Shale, Inc..... 2-22 Paraho-Ute Project 2-23

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-21 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since March 1981)

SYNTHETIC FUELS FROM OIL SHALE

COMMERCIAL PROJECTS

CATHEDRAL BLUFFS SHALE OIL CO. - Occidental & Tenneco (T3S, 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. Fluor is managing contractor, Bechtel Petroleum is engineerin design contractor for material handling and power generation. Dravo is engineering design contractor for mine design and underground operation, and Drown & Root is the construction contractor for surface facilities. PSD application submitted 4/81 for 117,000 BPD operations. Three headframes, two of concrete and one of steel, have been erected. As of mid May the shaft depths were: Ventilation/Escape -1,601'. Service - 1,757' (complete), Production - 1,856'. Designated gassy mine 1/2/80.

Project Cost: $237 million spent to date. Estimated to total $5.9 billion by 1990.

CHEVRON CLEAR CREEK PROJECT - Standard Oil Company of California (T55, R98W, 6PM) Chevron plans to have a semi-works 350 TPD plant in operation in Salt Lake City by late 1983 using Chevron's Staged Turbulent Bed (STB) retort. The company has not chosen the processing technology it will use, and process evaluation by Foster Wheeler will continue while the STB 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. Plans include a water s ystem built jointly with Gettv and Cities Service. consistinv of an intnke ctriiettire in the Cnlnrndn

Project Cost: $5 million in 1979 $20 million in 1980

COLONY DEVELOPMENT OPERATION - Exxon (60%) and Tosco (40%) (TSS, 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 2/1/80. On August 1, 1980, Exxon acquired ARCO's 60 percent interest in project for up to $400 million. Preferred pipeline destination is now Casper, Wyoming, and draft EIS is being prepared. Work on Battlement Mesa community commenced summer 1980. Colorado Mined Land Reclamation permit approval October 1980. Site development is proceeding. C.F. Braun awarded $300 million contract 12/80 for final design and engineering of Tosco II retorts Brown & Root will construct the retorts. Stearns-Roger awarded contract 2/81 for design and construction liaison on materials handling and mine support facilities.

Project Cost: Estimated in excess of $2 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 3/25/78. Retort 6 produced 55,000 bbls, of which 48,000 bbls were recovered and stored. PSD permit for Retorts 7 & 8 awarded 11/1/79. Retorts 7 and 8 which will measure 165 x 165 x 246 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

2-22 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since March 1981) COMMERCIAL PROJECTS (Cont)

PACIFIC PROJECT - Superior (20%), Sonia (60%), and Cleveland-Cliffs (20%) (T6S, R98W, 6PM) Superior, the project developer, plans to construct a 22,000 TPD circular grate retort to produce 15.000 BPD by early 1986. Superior is engaged in a $7.5 million engineering design program, of which DOE is funding $5.6 million. Negotiations with DOE are underway for an additional cooperative agreement for detailed design of the retort, which would bring Superior to the point of procurement and construction. Project Cost: $300 million for single module.

PARAHO-UTE PROJECT - Chevron, Conoco, Davy McKee, Mobil, Mono Power, Phillips, Sohio, Sunedco, Texas Eastern, Cleveland-Cliffs, Texaco, ARCo, Husky, and Placid Refining (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 18-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. 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 18-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 1985, and full capacity will be reached in 1987. Cold now tests have been completed on 11-meter kiln. Nearly $10 million has been budgeted by the National Energy Commission for 1981.

Project Cost: Total expenditures in excess of $200 million Projected cost of 50,000 BPD plant is $2 billion RIO BLANCO OIL SHALE COMPANY - Gulf & Standard (Indiana) MS, R99W, 6PM) Proposed project on federal Tract C-a in Piceancc 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 5/77. Combination of modified in situ retorts and surface retorts 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. Bubbling begun May 8, 1980, completed June 27, 1980, on 30' x 30' x 166' test Retort 0. Burn, begun October 31, 1980, produced 1,750 barrels. 1,040 as shale oil and 710 as vapor. Bubbling began late October 1980 on 60' x 60' x 400' Retort 1, completed 1/14/81. Burn scheduled for Summer 1981. CE Lummus has been awarded engineering and construction contract for 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 $140 million No cost estimate available for commercial facility.

•RUNDLE PROJECT - Central Pacific Minerals/Southern Pacific Petroleum (50%) and Esso Australia (50%) Development of the Rundle deposit in Queensland, Australia. In April 1981, two-module Phase I was shelved due to economic and technical uncertainties.

New or Revised Projects.

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 2-23 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since March 1981) COMMERCIAL PROJECTS (ConL) TOSCO SAND WASH PROJECT - Tosco Corp. MS, R21E, 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 'FOSCO 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 economies and mining feasibility plans for the commercial project. Permits for this new work have been received from the state. Tosco plans to begin construction in 1983 on a plant similar in layout and scale to the Colony plant. The plant will process 66,000 TPD of 35 GPT oil shale to produce 47.000-48,000 BPD by 1987. Peak construction force will be about 2,500 persons for three years. Post-construction operating force will be 1,200. Ralph M. Parsons has contract for preliminary design.

Project Cost: Approximately $1 billion UNION LONG RIDGE PROJECT - Union Oil Company of California (TSS, 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. Construction is underway On a 10,000 BPD (12,500 TPD) prototype facility with start-up scheduled for 1983. 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. Application has been made for permits for an upgrading plant, pipeline, and rail line. Production of 50,000 BPD is scheduled for 1988. Fluor is contractor for upgrading plant, Morrison-Knudsen for the mine, and Stearns-Roger for the retort. Underground construction continues. 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 (DDP) 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. The injunction order suspending the U-a and U-h federal lease terms is uncontested and is in full force and effect. On Ma y 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 11/15/77 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 DDP due to be submitted for approval summer 198L WRSP is planning construction of one Superior and/or one Union B demonstration retort. 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. DOE funding will end 9/30/81.

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

2-24 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since March 1981) 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 Piceanee 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. - (T145, R22E, Sec. 2, SLM) 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 (217' x 230' x 30' in 22 OPT shale), ignited early December 1980; production in early May averaged 50 BPD with cumulative production of 8,389 barrels. Retort 23(50' x 100' x 24'). i gnited Inte Mnrnh 1 QR1 • •ndi,nth,,.

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 OPT by Fischer Assay. Detailed feasibility study planned before final technology selection. Goal is to reach full-scale production by 1990. Although no firm decision on process selection has been made, CSR's feasibility study is based on TOSCO IL Feasibility study indicates additional study is warranted

Project Cost: A$300 million for a 5,000 BPD pilot plant. MULTI MINERAL CORPORATION - U.S. Bureau Of Mines Shaft (T15. R97W, See.30, 6PM) USBM began drilling 10-foot diameter, 2.400-foot deep shaft 3/77. Objective is to mine samples of oil shale. naheolite, and dawsonite from shale formation. Shaft may he 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 and slope rubblization at the 2,130' level stope will measure 64 x 40 x 110' tall. Draft EIS issued August 1980, withdrawn September 1980. Construction is proceeding on an 8' diameter, 40' tall, 80- ton true adiabatic retort in Grand Junction. Startup is scheduled for Fall of 1981. Project Cost: Over $8 million for shaft sinking. NAUCOLITE MINE #1 - Multi Mineral Corporation (T1S. 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 submitted to USGS (Denver) January 1981 and is currently under environmental review. Permitting is via the Colorado Joint Review Process. Shaft sinking scheduled for late 1981. Production of 500,000 TPY scheduled in 1984, 1 million in 1985. USGS completed Environmental Assessment on mining plan 5/81 with a finding of no significant impact. Construction planned to begin in 2nd quarter of 1982. NAVAL OIL SHALE RESERVE DEVELOPMENT - TRW Inc. Navy issued RFP 6/77, calling for preparation of Master Development Plan for Naval Oil Shale Reserves I, 2, and 3. Objective is to put NOSR in position for large scale development of resources within five years. Contract awarded 6/22/78 to team composed of TRW, CF Braun & Compan y, Gulf Research & Development Company, Williams Bros. Engineering Company, and Tosco Corporation. Comparative analysis of NOSR I and eight other Piceanee 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

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT OIL SHALE PUBLICATIONS

Adams. Thomas F., "Explosive Bubbling Calculations with the Bedded Crack Model," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energ y Technology Center. at Denver. Colorado, March 24-26, 1981. Baker, C. U., "Australian Developments in Oil Shale Processing," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Barr y, Hamlet J.. "State Policies and Concerns about Rapid Federally Assisted Oil Shale Industrialization," presented at the 14th Annual Oil Shale Symposium, jointly soonsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado. April 1981. Bates. Edward and Kurt Jakobson, "Status of EPA's Pollution Control Guidance Documents for Oil Shale," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Braun, R.L. and H.Y. Sohn, "Analysis of Multiple Gas-Solid Reactions During the Gasification of Oil Shale Char," presented at the A.I.Ch.E 1981 Spring Meeting, Houston, Texas, April 1981. Braun, K. U., et al., "Analysis of Multiple Gas-Solid Reactions During the Gasification of Char in Oil Shale Blocks." presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Braun, R. L., "Mathematical Modeling of Surface Retorts," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Bridges, J. E., "Physical and Electrical Properties of Oil Shale Effect of Grade and Origin of Sample." presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center. at Denver, Colorado, March 24-26, 1981. Burnham. A. K., "Oil and Sulfur Chemistry During Oil Shale Pyrolysis." presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Campbell, John H., "Analysis of the Operation of Occidental's Field Retort 6," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Campbell, J. H., "Analysis of the Operation of Occidental's Field Retort 6," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Campbell, J. H., "LUNL Participation in the Rio Blanco Oil Shale Company's MIS Retort 0," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Campbell, John H., "Modified In Situ Retorting: Results from LLNL Pilot Retort Experiments," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Carlson, R. D., "Development of the lIT Research Institute RF Heating Processes for In Situ Oil Shale/Tar Sand Fuel Extraction - An Overview," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center. Golden, Colorado, April 1981. Cha, C. Y. and D. Chazin, "Survey of Current Technologies for the Production of Oil from Oil Shale by In Situ Retorting Process: Their Technological and Economic Readiness and Requirement for Further Development," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Chappell, Willard R., "The DOE Oil Shale Task Force - A Progress Report." presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Clements, William E., "A Drainage Wind Study in the Piceance Basin," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

2-26 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS - OIL SHALE

Cook, Thomas L., "Calculation of Mass and Heat Flow in the MR-3 Retort," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver. Colorado, March 24-26, 1981. Culberson, S. F. and P. D. Rolniak, "Refined Products From Shale Oil Feedstock," presented at the 46th Midyear Refining Meeting of the API, Chicago, May 1981.

Dalverny, L. E., et al., "Explosive Hazards in Gassy and Nongassy Oil Shale Mines," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

del Rio, S. M.. "Large Area Underground Retorts," presented at the 14th Annual Oil Shale S ymposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Dienes, John K., "Statistical Crack Mechanics." presented at the Fourth Annual Oil Shale Conversion Conference. sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

Dougan, Paul M., "Status Report on the Bx In Situ Oil Shale Project," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

Dougan, P. M., "The Bx In Sitti Oil Shale Project," presented at the 14th Annual Oil Shale S ymposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Doyle, John B., "Fluid Bed Combustion of Coal-Oil Shale Mixture," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado. March 24-26, 1981.

Duflow, Joel, "Applications of the Thermophysieal Properties of Oil Shale," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

Fausett, D. W., "Simplified Kineeties of Oil Shale P yrolysis," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden. Colorado, April 1981. Feldkirehner, Harlan L., "Progress Report on Institute of Gas Technology's Hytort Process." presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado. March 24-26. 1981.

Funk, James E., "Prospects for Kentucky Oil Shale: A Progress Report." presented at the 8th Energy Technology Conference, sponsored by AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-11, 1981.

Goldstein, Selma, "Characterization of Blasting Explosives," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Holland, L. M. and C. G. Stafford, "The Los Alamos Integrated Oil Shale Health and Environmental Program: A Status Report," LA-8665-SR Los Alamos Scientific Laboratory. January 1981.

Holmes. S. A., "Nitrogen-Type Distribution in Hydrotreated Shale Oils: Correlation with Upgrading Process Parameters," presented at the 14th Annual Oil Shale Symposium, jointl y sponsored by the Colorado School of Mines and the Laramie Energy Technology Center. Golden. Colorado, April 1981.

Hommert, P. J., "Instrumentation and Data Analysis Results from Occidental Retorts MR-3 and MR-4." presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Hommert, P. J., "Thermal Instrumentation and Data Analysis - Results from OOSI Mini-Retort 4," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center. at Denver, Colorado, March 24-26, 1981.

Jackson, K. F., "Metals Distribution in Shale Oil Fractions," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden. Colorado, April 1981.

Johnson, Edward. "Coal and Oil Shale Reclamation and Revegetation Research Activities." presented at EPA's Fifth National Conference entitled Interagency Energy/Environment R&D Program. Washington, D.C., May 1981.

Jones, Bonnie M., "Factors Limiting Biodegradation of Oxy-6 Process Water Constituents," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24- 26, 1981. Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-27 RECENT PUBLICATIONS - OIL SHALE Karwoski, William J., "Mini-Retort Sill-Pillar Analysis," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center. at Denver, Colorado, March 24-26, 1981. Kilkelly, Al. K., "Revegctation Studies on Tosco II and USBM Retorted Oil Shales," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Kipp, M. E., "Dynamic Fracture and Fragmentation of Oil Shale Application of a Numerical Model to a Blast Design," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Kronenberger, L.. "Environmental Factors in Project Facilitation," presented at 1981 Spring National A.I.Ch.E. Meeting, Houston, April 1981. Kuuskraa, V. A.. "The Marketing Potential of Shale Co-Products," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Larson, 0. A., "Fundamental Constraints to Improved Shale Conversion Processes," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. - - - - - Leenhcer, J. A., "Chemical and Physical Interactions of an In Situ Oil Shale Process Water with a Surface Soil," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Leffert, C. B. and R. K. Schroeder. "Fischer Assay Analyses of the Antrim Oil Shale of the Michigan Basin," Wayne State University, NTIS document #FE-2346-83, 1980, 164 pp. Lekas, James ed.," Progress Report on Geokinetics Horizontal In Situ Retorting Process," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24- 26, 1981. Lckas, M. A., "The Geokinetics Horizontal In Situ Retorting Process," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Levy, A., "High Temperature Corrosion of Metals and Coatings in Oil Shale Environments," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Lewis, Alan G., "Oil Shale Mining Economics Model (OSMEM)," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado. March 24-26, 1981. Loper, D. Roger, "The Perspective of a New (Oil Shale) Venturer," presented at the 8th Energy Technology Conference, sponsored by AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-I1, 1981. Lyon, R. K., "NO Production During the Combustion of Spent Shale," presented at the 14th Annual Oil Shale Symposium, jointly sponsored"6v the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Madsen, Rees C., "Status of (Paraho) Surface Retort Module Design Project," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Mallon, K. 0., "Technical and Economic Feasibility of Shale Oil Production by Radio Frequency Heating," presented at the 14th Annual Oil Shale Symposium, jointly sponsored b y the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Margolin, Leonard G., "The Bedded Crack Model," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Mathews. R.D., J.M. Dennison, and J.C. Janke, "Devonian Oil Shale of the Eastern United States: A Major American Energy Resource," presented at the AAPG meeting at Evansville, Indiana, October 1-3, 1980. Authors may be contacted at the IGT, Chicago.

2-28 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS - OIL SHALE

McTernan, W. F., "Status of the DOE Environmental Effort for Its Surface Retort Program," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

McWhorter, David B., "Laborator y Leaching of Ui-Modal Porous Media," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Mehran, M., "Hdrogeologie Consequences of the Modified In Situ Retorting Process, Piceance Creek Basin, Colorado," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Miknis, F. P., " 13C NMR Studies of Oil Shales," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Miller, A. K., "Structural Analysis of Modified In Situ Oil Shale Retorts," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energ y Technology Center, Golden, Colorado, April 1981.

Nash, Joe, "The Toxic Substances Control Act and Its Application to Synfuels," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Nelson, Reid M., "DOE/OXY Cooperative Agreement Phase II Update," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

Norris, T. G., "Shale Oil," presented at Synthetic Fuels. Prospects Under the Reagan Administration, sponsored by U.S. National Committee of the World Energy Conference, Washington, D.C., April 1981.

O'Shaughnessy, J. C., "Biological Treatment of Oil Shale Retort Wastewater Using Rotating Biological Contractors," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Parekh, U. N., "Ignition Studies on Oil Shaley Beds," presented at the Fourth Annual Oil Shale Conversion Conference. sponsored by the Laramie Energy Technolog Center, at Denver, Colorado, March 24-26. 1981. Parrish, R. L., "Geokinetics Retort 23: A Joint Sandia/GET Retorting Experiment," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981.

Perry, H., "Oil Shale and Tar Sands," presented at the Engineering News Record conference Making Svnfuels Plant Business Your Business, Washington, D.C., March 1981

Raley, J. H., "Retort Analysis from Fluid Product Data, ' presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver. Colorado, March 24-26, 1981.

Ratigan, J. L., "Analysis of Subsidence in Modified In Situ Retorts." presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Rinaldi, G. M., "Venturi Scrubbing for Control of Particulate Emissions from Oil Shale Retorting." presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Rosain, Robert M., "Water Re-use in Steam Generation Systems for Oil Shale Plants," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center. Golden, Colorado, April 1981.

Sareen. S. S. and D. L. Bidlack, "Parametric Analysis of In Situ Retorting O ptions for NOSR 1," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Schamaun, J. T.," Lumped Mass Modeling of Overburden Motion During Explosive Blasting," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-29 RECENT PUBLICATIONS - OIL SHALE Schirmer, R. M., "Low-NO Burner for High-Nitrogen Fuels," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado 9chool of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Schrnal, M. and I.P. Silva, "Hydrotratamento de Oleo de Xisto," presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara. Au. Rio Branco, 124, Rio de Janeiro, April 1981. Slawson, G. C., Jr., "Analysis of Groundwater Quality Sampling Methods," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Sohn. H. Y., "A Mathematical Model of the Combustion of Char in Retort," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center. at Denver, Colorado, March 24-26, 1981. Travis. Bryan J., "A 3-D Model of Tracer Flow in Bubbled Oil Shale," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Travis. B.. "Modeling a Modified In Situ Retort," presented at the 14th Annual Oil Shale Sympodum, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981. Travis, Bryan J., "Progress on A 2-0 Oil Shale Retorting Model." presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, aLDenver, Colorado. March 24-26, 1981.

Tyler, A. L., et al., 'Steam Cracking of Shale Oil Liquids," presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Tyner, C. E., "Low Void Retorting Studies," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver, Colorado, March 24-26, 1981. Tyner. C. E.. "Tracer Determination of In Situ Oil Shale Retort Flow Characteristics," presented at the Fourth Annual Oil Shale Conversion Conference, sponsored by the Laramie Energy Technology Center, at Denver. Colorado, March 24-26. 1981. "The U.S. Shale Oil Industry: 1981 to 2000." published by Madsen Russell Associates, Ltd., 222 Mamaroneck Avenue, Suite 201, White Plains, N.Y. 10605. 1981, price $950. Udon. P.C., et al.,' Liquid Chromatographic Class Separation and High Resolution Gas Chromatography of Shale Oil Polar Comoounds," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Vawter, R. G., "Shale Oil Plants," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981

Vyas, K. C.,"Syncrude from Eastern Oil Shale" presented at the 14th Annual Oil Shale Symposium, jointly sponsored by the Colorado School of Mines and the Laramie Energy Technology Center, Golden, Colorado, April 1981.

Oil Shale - Maps "Pieeanee Creek Basin Oil Shale Status." by the U.S. Department of the Interior, Bureau of Land Management, Scale 1:126,720, 1/2 inch = I mite, on paper 27" wide x 32" high, March 1981. (Shows unpatented mining claims).

Reviewed in this issue. OIL SHALE - PATENTS 'Jeambey, Calhoun G. - Inventor, U.S. Patent 1.193.448, March 18, 1980. 'Apparatus for Recovery of Petroleum from Petroleum Impregnated Media." A method and apparatus for the recovery of petroleum from petroleum impregnated media. The apparatus includes a microwave generator and a guide for directing microwaves to a microwave dispersing chamber for heating the media. The apparatus has a pluralit y of holes for the flow of heated petroleum into a petroleum chamber. The method of the invention inlcudes inserting the apparatus into an opening In the media, dispersing microwaves into the media to heat it and recovering petroleum in the recovery chamber. Patent subsequently assigned to Colorado Synfuels Inc. *Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 2-30 In \ ci 11. amixami GOVERNMENT

CONFLICT OVER CANADIAN NEP CONTINUES Alberta Implements Production Cutbacks Since October 1980, when the Canadian National Energy Alberta's stand was not softened by Ottawa concessions Policy (NEP) was first announced, little headway has and in March 1981, the threatened oil production cut- been made in bridging the gap between Provincial and backs were invoked. Premier Peter Lougheed announced National concerns. The NEP was designed to change the two days after the unveiling of the NEP in October that composition of the economic power structure in Canada, Alberta would cut back its oil production in three stages where the energy producing provinces had gained "an as a protest against the pricing and taxation structure unacceptable" level of control over the economic contained within that document. While Ottawa can stewardship of Canada at the expense of Ottawa. It was decide the price of oil sold outside of the province, intended to expedite Canadian ownership of the energy Alberta is the owner of the resource and can therefore industry and foster self sufficiency. However, surveys control production rates. have shown that Canadian ownership during 1971-1979 rose from 22.4 percent to 38.5 percent and a similar The cutback was officially meant to be 60.000 barrels a increase in Canadian ownership in this decade would day on March 1, increasing to 120.000 barrels a day June achieve the government's goal without foreign-company I, and 180,000 barrels on September 1. However, the discrimination. The NEP has detracted from Canada's actual cutback was initially more because it is based on ability to produce oil and gas rather than added to it. the projected average production for the next three The NEP, in fact, provides less incentive to search for months. April and May are traditionally months of low and develop new supplies of oil and gas. The setbacks to production rates. Alberta is aiming to maintain the the industry as a whole, and the oil sands project delays, same production over the three months. So the effective will cost the country millions of barrels of oil production cutback for March is 100,000 barrels a day less than and foreseeably billions of dollars in increased foreign normal, but in May, it will probably be only about 15,000 purchases. barrels a day less. The pricing policies introduced with the new energy Only those fields which are owned in full by the provin- program last October were designed to keep producers cial government are being cut back. The flow will be from reaping windfall profits as the world price rose. reduced primarily from the large old, established oil However, the Federal government intends to hold to the pools of northern Alberta, such as Judy Creek, Rainbow 1975 formula until it works out a new oil pricing and Lake. Swan Hills and Nisku. The cutback doesn't apply taxing agreement with Alberta officials. This formula to about 20 percent of Alberta lands which are freehold pays a subsidy to refiners for using synthetic oil to bring (not owned by the provincial government), oil sands. the price down to the controlled price of conventional oil heavy oil production, marginal wells producing less than of approximately $18 a barrel. Thus, the subsidy is 30 bId, enhanced recovery fields, and fields which went currently worth $25 per barrel. Under the 1975 pricing on production after October 1, 1980. formula, Syncrude Canada Ltd. currently receives $43 per barrel for its production sold in Montreal. It may not, initially at least, he necessary for Canada to import more oil to make up the losses from Alberta. The Federal Government must put new legislation Most eastern refineries, particularly in Quebec, have through Parliament before it can set a new price for been stocking up in anticipation of the cutback. Some synthetic oil, which is currently averaging 75,000 barrels are estimated to have two or three months of crude a day and was expected to reach between 100,000 and supplies in storage. Eventuall y, however, if Canada were 120,000 daily by next fall. Pricing is currently based on to have to import an extra 100.000 barrels a day, it cost of production and many feel that, instead, it should would cost the federal government at least $2 million be based on the replacement cost of the resource itself. dail y. This is because Ottawa has a policy of subsidizing imports, so that refiners pay the same whether they are Initially, Federal Energy Minister Marc Lalonde had buying domestic or foreign crude. This in turn holds hoped to reach a separate agreement with Alberta on the down the price for the consumer. development of oil sands. However, Alberta's Premier Peter Lougheed made it clear that the province would In response to the production cutback and in order to not accept a separate agreement for fear of losing finance the subsidies for replacement production. bargaining power, and will continue to stall the Alsands Lalonde implemented a "special temporary levy" on all and Esso projects for lack of an over-all oil and natural petroleum products. The tax, effective March 3. gas pricing agreement. amounts to an average of 0.5e/liter. Lalonde said the tax probably would be dropped if Alberta restored pro- In an effort to show his flexibility, Marc Lalonde made a duction to its earlier level. But, the tax would be peace offering move by expanding subsidies, softening increased if Alberta's planned cuts of June 1 and Sep- Canadian ownership rules and simplifying regulations for tember 1 are implemented industry. Specifically, he lowered, from 75 percent to 65 percent, the Canadian Ownership Rating required to The federal government has also said it will give addi- receive the maximum available grant. He also intro- tional subsidies to eastern Canada refiners if they have duced a new intermediate level of grant for 60 percent to buy oil on the spot market. Mone y for this subsidy Canadian content. Companies would have five years to will come partly from the new tax. Refiners importing comply with the Petroleum Incentives Program. oil already receive a subsidy of nearly $25/bbl to cover

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-1 the cost difference between domestic and imported oil. excess workers must be laid off. Man y companies are Ottawa will pay an additional subsidy to refiners who hanging onto trained workers, hoping the situation will have to pay more than $43/bbl for imported oil. Re- reverse in the near future. In contrast, other companies finers in western Canada won't be affcctd by the cut- are having trouble attracting skilled professionals be- back. Major producers such as Esso Resources Canada cause of the economic uncertainty. Ltd.. Mobil Oil Canada Ltd., Amoco Canada Petroleum Co., Ltd., Chevron Standard Ltd., and Texaco Canada The Fort McMurra y and Cold Lake communities have Inc., will be the hardest hit by the provincial production found themselves in an awkward situation. In anticipa- cut. tion of the oil sands industry growth, the communities have prepared for an influx of workers and a strain on Alberta will lose an estimated $750,000/day in royalties. the existing infrastructure. Mone y has been allocated Saskatchewan could lose $320,000 per day as a result of for public services and accomodations, that due to the reduced production based ona price of $17.80 per barrel, NEP, are no longer in demand. Because of an unsure of which about half would normally flow to the pro- future market, private construction and facility imple- vincial government. Crude oil production in southeast mentation efforts have come to a halt. Yet the com- Saskatchewan has been cut by 45 percent to 23,000 munities must contend with the reality that the boom barrels per day because of spin off impacts from may still come. Alberta's cut of 100,000 barrels per day. Eastern refineries blend Saskatchewan's light sour crude with Alberta's light sweet crude, but with the drop in Al- berta's deliveries, there is less demand for Saskatchewan ERCB ALLOWS ESSO COLD LAKE PROJECT TO USE crude. NATURAL GAS

Oil Talks Bring-Hope-for A Compromise A report on the Alberta Energy Resources Conservation Board's decision on an application to use natural gas The deadlock between Federal and Alberta energy rather than coal as make up fuel for the Cold Lake oil ministers was broken on April 13 in Winnipeg, when the sands project was released in February 1981. The report two parties met as agreed upon. According to published discusses the application by Esso Resources Canada Ltd. sources, Federal Minister Marc Lalonde and Alberta and the hearing assessment of the application, compari- Minister Mervin Leitch were to discuss several points of son of coal and natural gas, and the Board's decision. possible compromise: Background to Application Discussed • The concept of a two-tier price system with a higher price for oil and new discoveries. In the original application, Esso Resources Canada Ltd. applied to the Energy Resources Conservation Board for • A mechanism under which Ottawa would approval of a scheme t produce and upgrade 25,400 raise the price of oil from established wells cubic metres per day (m /d) of crude bitumen from its above the planned $2 in the energy program. leases in the Cold Lake area. At the same time, Esso applied for an industriel development permit to author- • A price around world levels of $43 a barrel ize the use of 2.3 x 10 tonnes per annum (t/a) of coal as for synthetic crude compared with the energy the make-up fuel for the project. After the hearing of program's $38. this application, Esso submitted an amended application in April 1979 which sought the use of natural gas in lieu • Some form of index to raise the synthetic of coal as a preferred make-up fuel. Having regard for price other than the originally proposed con- environmental, economic and supply matters, as well as sumer price index. for policy considerations, the Board found that coal should be used as the make-up fuel, and ruled that any Alberta Energy Minister Mer y Leitch said a two tier approval it may issue would require its use. The price system might not stimulate a new oil development Applicant, having found that make-up fuel requirements as much as the federal government expects, and adminis- are further reduced, filed the current application, again tering such a system could cause bureaucratic problems. seeking to use natural gas as the primary make-up fuel Alberta has rejected previous proposals for a two tier for the project. price system because most of the province's 900.000 b/d of production would fall into the lower priced old oil Reasons for Fuel Requirement Decrease Identified category. Esso's request for the use of natural gas as a make-up Neither party was expected to present a detailed pro- fuel results from a reduction in the amount of fuel posal for solving the conflict, but both had agreed to required for the project. The Applicant believes that it explore areas of disagreement as a prelude to the has been successful, through further design definition, possibility of more detailed negotiations during the process integration and inclusion of energy conservation summer. measures, in reducing the expected amount of primary make-up fuel, %xpressed in terms of coal, from 1.3 x 10 NEP Causes Significant Socioeconomic Impact tfa to .43 x 10 t/a. Esso believes that tt make-up fuel requirement could be as high as 0.64 x 10 t/a or, on the The National Energy Policy has also taken its toll on the other hand, could reduce to zero once the plant becomes planning and future of several communities. As the operational. demand for oil field servicing and construction slackens,

3-2 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981

The total fuel requirements for the project were esti- production of offgas, and laboratory tests which suggest mated to be 271 tgraioules (one terajoule (TJ) is equiva- a higher than previously assumed heating value for the lent to 948.5 x 10 Btus). per calendar day (TJ/CD). The low joule gas. upgrading process would produce a surplus of gaseous fuel which, together with production offgas, would only However, while Esso pointed out that the current fuel partially satisfy the needs of the utility and injection balance is based on the best design data currently steam plants. The shortfall in fuel requirements would available, it acknowledged uncertainties which are illus- be met by make-up fuel obtained off-site. Since the trated in Table 1. For the most part, these relate to original application, the total project fuel requirement internal generation of fuel and to the oil/steam ratio has decreased by 13 percent through further engineering (OSR) actually achieved in the production operation. definition and the inclusion of energy conservation measures. At the same time, internally generated fuels Esso contended that if coal must he used in the project. have increased by 9 percent, resulting in a decrease in it would have to be used in a utility or low pressure external fuel requirements of 58 percent. The external boiler system, since the high pressure injection boiler fuel would be made up of balancing fuel and supplemen- system is, in its view, not y et technically and operation- tary fuel. The supplementary fuel, required during ally proven. Esso also argued that investment costs for periods of low fuel gas production and in flare stack and either the high or low pressure coal-fired boilers would furnace pilots, amounts to 19.7 TJ/CD and must be be substantially higher than for gas-fired units, that coal supplied by natural gas. The balancing fuel would transportation and unloading facilities would comprise a amount to some 22 TJ/CD and could be supplied by significant portion of the additional investment, that the natural gas or coal. If ''abamun coal were used, this large on-site labor force required for construction of the would amount to 0.43 x 10 t/a. coal-fired facilities are not a sound economic investment for the project. and that steam generation by gas rather The lower project fuel requirement is due primarily to than coal would raise the project internal rate of return economies in the steam generation systems. Additional by 0.5 percent. The rate of return differential is due low pressure steam generation in the Flexicoking, hydro- primarily to the higher capital costs for coal-fired gen generation, and hydrotreating units has resulted in facilities, which would not be offset by future fuel cost energy and high pressure steam savings of some 10 savings through the use of coal. TJ/CD, while heat exchange integration, furnace air preheat optimization and improved insulation of steam The Applicant considered coal gasification at a mine site lines has led to further saving of some 18 TJ/CD. as a potential alternative to both natural gas and coal, but rejected this proposal on the grounds of the very Increases in internally generated fuels are based on large additional investment. continuing field measurements, which indicate greater

TABLE I VARIABILITY OF MAKE-UP FUEL REQUIREMENTS TJ/CD (I-tHy) (adopted from Applicant's submission) Balancing Supplemental Fuel Fuel* Total Fuel

BASE CASE OSR = 0.40 22.0 19.7 41.7 SENSITIVITIES

Low Balancing Fuel Upgrading Export •ll% Production Offgas +25% 6.2 17.9 24.1 + OSR = 0.35 22.6 17.9 40.5 instead of base 0.4 High Balancing Fuel Upgrading Export -11% Production Offgas -25% 41.1 19.7 60.8 4-OSR = 0.35 58.5 19.7 78.2 instead of base 0.4

* Pilot Fuel Requirement is assumed constant at 5.3 TI/CD and supplemental fuel is natural gas.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-3 Continued field pilot studies have provided additional Coal and Natural Gas Options Are Compared well performance data which caused Esso to change the design basis for water-oil ratios (WOE) and oil-steam In comparing the full options, it was determined by the ratios (OSR) now expected. The current design basis Board that a variation in make-up fuel requirement does provides the capability of handling water production up not alter the relative merits of gas over coal in areas of to a WOR of 2.2 and providing steam to an OSR of 0.4. project efficiency. water-use, flexibility in operations, These are both less attractive than those considered in social impact or manpower availabilit y. Insofar as previous applications. It is Essos view that alternative environmental effects are concerned, there ma y be some recovery processes such as thermal flooding or bank marginally greater advantage in using gas rather than displacement would be implemented after about 6 cycles coal if fuel requirements were to increase. All of these of stimulation to achieve a 20 percent hydrocarbon matters suggest the application to use gas as a make-up recover y. Esso now has a more favorable water balance fuel should be approved notwithstanding uncertainties in than that discussed in previous applications. The amount estimating the amount of fuel which might be required. of recycled water is increased, fresh make-up water decreased, and disposal to both surface and deep wells On the other hand, the economic attractiveness of coal has been reduced. is enhanced by increased make-up fuel requirements. Larger coal throughputs would have lower unit costs and In summar y. Esso stated that if required to use coal at increase future fuel costs savings relative to gas. currently projected rates, it would carry a high cost Accepting the possible variation in make-up fuel require- component that is not economically or environmentally ment acknowledged by Esso, the impact of higher coal justified. throughput on the coal case project economics could reverse the economic advantage of gas use. Under these The OSH is a measure of the thermal efficiency of the circumstances, from a provincial viewpoint, the gas case reservoir operation and -relates directly-to the amount of net benefits could be less than the coal case net benefits fuel required for raising injection steam. Esso uses a after incorporating the potential benefits from the addi- design OSR of 0.4 based on 6 cycles of historical data tional coal mine and coal transportation expenditures. obtained from the Leming experimental scheme. It does not have historical data beyond 6 cycles, but predicts ERCB Decision is Summarized that the OSR will be 0.4 at the end of 6 cycles and then decline to 0.35 at the end of 9 cycles. An OSR of 0.35 In summar y, the Board believes that the use of natural would require 14 percent additional steam and, hence, on gas as a make-up fuel in the Cold Lake Project would be additional 14 percent project fuel steam generation; and in the Alberta public interest unless the volumes actually this would increase make-up fuel requirements by be- required turn out to be much greater than those cur- tween 16.4 and 17.4 'I'J/CD or 42 percent. rentlyestimated by Eso. Because of the uncertainties in the amount of fuel that may be required over the life In order to maintain thermal efficienc y . Esso plans to of the project, the Board is not prepared to uncondi- follow steam stimulation with thermal flooding or a bank tionally grant the application. It would approve the use displacement process, and based on current data from of natural gas as a make-up fuel as long as actual use the Leming operation, this conversion could occur after does not significantly exceed the requirements antici- 6 cycles. However, further field-pilot work is required pated in the application. Esso currently estimates to test this plan. requirements at some 42 TJ/CD and the Board would not consider the fuel usage to significantly exceed the Originally. Esso submitted that 20 percent of the bitu- current estimate unless it averaged over 50 'Li/CD for at men could be recovered bS' cyclic steam stimulation, but least one full year after full stable operations were now expects only 13 percent to be recovered after 6 achieved. If it should be found that, after full produc- cycles. The remainder must then be recovered by tion capacity is reached, make-up fuel requirements follow-tip processes. were in fact significantl y higher than currently expected, Esso would be required within a specified time The Board believes that Esso's historical and predicted period to file a review with the Board justifying the data are the best currentl y available, and accepts that it continued use of gas. If necessary, the Applicant may may he necessary to convert to an alternative recovery then be required to convert to coal or other appropriate technique, such as steam drive or combustion after a make-up fuel. number of cycles in order to recover 20 percent of the bitumen in place. Otherwise, additional steam raising facilities would have to be added and more fuel would be required. The optimum number of cyclic stimulations before converting to a displacement process is still unknown but should be determined through future pilot operations at Leming.

The board also recognizes that the 0511 and bitumen recovery rates could also be improved by drilling infill wells, but agrees that capital and production costs would increase substantially. It would therefore look to this measure only as a last resort to maintain high 0511 and high recovery levels.

3-4 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 PROJECT ACTIVITIES

RIO VERDE ENERGY PLANS KENTUCKY The process has been tested extensively at the bench- OIL SANDS PRODUCTION scale level and is currently being patented. It is claimed that the A.D.I. process will produce 2.5 barrels of Rio Verde Energy Corporation has entered into a joint bitumen per ton of tar sands, based on a 9 weight venture agreement with Reading and Bates Petroleum percent bitumen content! The only operational problems Co., to explore and study the economic feasibility of are expected to be associated with the abrasive nature commercial oil recovery from its tar sands leases in of tar sands and the resulting wear and tear on equip- West Central Kentuck y. Rio Verde is a wholly owned ment. subsidiary of Highlands Coal & Chemical Corporation, Cincinnati, Ohio. Reading and Bates Petroleum Com- Aarian expects to begin construction in early 1982. pany is a subsidiary of the Reading and Bates Corpora- assuming no problems arise in land negotiations or equip- tion of Tulsa, Oklahoma. The agreement calls for ment orders. Two property sites. Asphalt Ridge and P.R. Reading and Bates to conduct core drilling on a 1.000 Springs, have been singled out as within the economical acre test property within three months ending July 1981. and feasible parameters of the project. Plant construc- Reading and Bates will also test the feasibility of tion is to be completed in three phases. Phase one will commercial production from the acreage using enhanced produce 5,000 to 8,000 barrels per day, phase two will recovery techniques. Specificall y, the SCOT oil extrac- increase to 14.000 barrels per day in the third year, and tion process using CO and steam will be tested. Read- phase three will reach 20,000 barrels per day in years ing and Bates has the option to acquire an additional four and five. 5.000 acres. According to the two companies, Rio Verde has leased a total of 160.000 acres in Butler, Edmonson. y Aarian has cited competition for steel related equipment Gra son, Hart, Logan and Warren counties. and for professionally qualified engineers and construction personnel, as potential risks for the project. The The Rio Verde Energy Corporation is sponsoring a Corporation's estimated cost for the plant and all off- project to produce 10.000 barrels per day of synthetic sites is $28.3 million. Joint venture lease and purchase crude oil from tar sands using in situ combustion agreements. both currently underway, could amount to methods. Initial development is planned on leases $20 million. Both loan guarantees and price guarantees located about five miles west of Brownsville. Kentucky. have been requested from the Synthetic Fuels Corpora- Initial production would follow securing financial assist- tion. but the project is intended to survive on its own if ance by two years with full production reached four passed over by the SFC. Construction is scheduled to years later. A portion of the oil recovered will be begin in 1982 and initial production would begin later upgraded by surface processing and blended with virgin that year with full production reached in 1986. oil to produce a low sulfur, pumpable syncrude. Rio Verde plans to assign Gruy Federal, a Houston-based consulting group specializing in unconventional recovery techniques, the task of overall project management. WESTKEN PLANS IN SITU PROJECT IN KENTUCKY A combination of loan guarantees and price guarantees Westken Petroleum Corporation of Bowling Green, Ken- has been requested from the U.S. Synthetic Fuels tucky has announced its plan to develop a large tar sands Corporation. Rio Verde asked for $54 million in loan deposit on a 19,000 acre tract of land in Edmonson guarantees. A price guarantee of $34 per barrel on the Count y, northwest of Brownsville. Kentuck y. Thermal in tar sands oil recovered during either the first five years situ combustion technology will be used to recover the of production or until a heavy-oil upgrading facility is heavy oil. Initial production is scheduled to begin in completed, whichever comes first, is also requested. 1982 with full scale production of 12,000 barrels per day to be achieved in 1987. The plant would be built in The project's environmental and socioeconomic impacts stages, (500 BPD modules), and, at full capacity, the have not been fully studied. However, because most of project will employ approximately 250 people. The the processing associated with in situ tar sands recovery proposed project would cost $200 million and a loan occurs underground, minimal impacts are anticipated. guarantee has been requested from the Synthetic Fuels WAPORA, a consulting firm specializing in environ- Corporation. mental and energy studies, will conduct all environmental and socioeconomic analyses required. Because surface mining will not be required for the project, only minimal disruption to surface agricultural uses of the land is expected. The project contemplates re-use of water produced so that there will be negligible AARIAN SEEKS SFC AID FOR UTAH PROJECT water effluent and no water pollution problems. It is anticipated that the heavy oil product will be shipped by Aarian Development Corporation of Taylorsville, Utah tank truck and barge to refineries along the Ohio and proposes to build a 20,000 barrel per day tar sands Mississippi Rivers and the Gulf Coast. project near Vernal, Utah. The project has been under development for nine years and will be based on the ## 4 A.D.I. chemical extraction process developed by Aarian.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-5 COLORADO COMPANIES PROPOSE KANSAS HEAVY assistance to proceed with the project, and to the OIL PROJECT absence of any commitment for funding, EOR has not yet made any formal submissions for state or local EON Petroleum Company, Denver, Colorado, is spon- permits for the construction or operation of the Chetopa soring the Chetopa Project located in Labelle County, Project. An EIS has also not yet been submitted. Kansas. The project will use technology for heavy oil recovery, developed by Tetra Systems, Inc., a Colorado The Chetopa Project will not require large construction corporation. This process involves the excavation of a or operation workforces. The primary construction series of shafts, approximately 12 feet in diameter and requirements will relate to shaft excavation rather than 100 -200 feet deep, to expose the oil bearing formation. production facilties construction. The actual manning Steam pipes are then inserted into the formation beneath figures will depend on the rote of excavation and unit each unit. Application of the "Flip-Flop" technology is construction. The initial construction phase will require used to extract heavy oil from the reservoir. Figure I the employment of men and equipment associated with shows the underground mining process for Flip Flop typical shaft excavation operations. The production recover y. This petroleum mining technique is discussed facilities construction process will not require the hiring in an article on page 3-4 of the June 1979 issue of of a workforce with unusual skills. There will be a need Synthetic Fuels. for general energy industry trade skills in the construction of the facilities and in the fitting and laying of the Projected production for the first year of full scale steam and oil pipe systems, as well as for certain drilling operation is 480,000 barrels. Full scale production can operations. begin 18 months after construction starts. The reservoir is estimated to contain 5 million barrels of oil. Total It is not projected that either the construction or opera- water requirements under the proposal will-be no more tion workforce will require-any significant housing con- than 3.000 barrels per day. This water will be extracted struction. FOR anticipates that some construction phase from deeper producing zones not suitable for domestic hiring needs may be met locally, and mobile housing is use. It is not anticipated that the Chetopa Project will expected to satisfy any temporary housing shortage that require the off-site disposition of any significant waste may occur. Transportation requirements will be satis- materials. fied by workforce personnel. EOR has requested that the United States Synthetic As mentioned above, EOR anticipates that some of the Fuels Corporation enter into a loan guarantee commit- construction workforce would be drawn from the local ment for $21 million to assist in financing of the population. The construction and excavation phase is Chetopa Project. Due to the need for federal financial expected to require a workforce of approximately 150 individuals. Total permanent population increase attributable to the workforce required to operate the project during the full-scale commercial production phase (e.g., workforce (30) plus families (90)) is not likely to exceed 120.

CALSYN PROJECT WILL USE DYNACRACKING

California Synfuels Research Corporation, as a joint venture with several U.S. and Canadian Oil Companies. is planning a heavy oil conversion plant in West Pitts- burg. California. The plant will be the first commercial application of Dynacracking, a route for thermally processing heavy oils originated by Hydrocarbon Research Inc. In Dynacracking, feedstock is heated, then fed to a reactor, where it is cracked to lighter products at around 1,000°F and 400 psig in the presence of an inert carrier and hydrogen (from the process's of fgas). Coke and metals from the feedstock are deposited on the carrier, which descends through a stripping section to a gasification zone at the bottom of the reactor. Here, the coke is gasified with steam and ox ygen (product gas rises to the cracking zone). Metals are purged from the carrier. Sulfur goes overhead with the product and is subsequently removed. The gasifier makes the process self-sufficient in heating.

FIGURE 1 Hydrocarbon Research ran a 15-bbl/d pilot plant in the UNDERGROUND MINING PROCESS 1950s, but the route has become economical only FOR FLIP FLOP RECOVERY recently, because of higher oil prices. Feedstocks anti-

3-6 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 cipated for the plant are very heavy oils from various duction will rise to 500.000 barrels per day. Three points in California, very heavy and metals-rich residual pipelines currently move crude from the San Joaquin oils from refineries in the San Francisco Bay area, and Valley: Chevron to Morro Bay on the coast. Mobil Oil on a test basis, tar sands product and other difficult-to-- Corp. to Los Angeles, and Gett y Oil Co. to San process hydrocarbons from various sites in the North Francisco. American Continent. If production of heavy oil does approach 500,000 barrels The plant is designed to process 5,100 barrels of feed- per day, then a new major heated pipeline system will be stock per day. The product slate includes 1,645 barrel- required by the mid-1980's. In response to this need, per-day equivalent of fuel gas, 2,211 barrel-per-day of a Getty Oil Co. will increase the capacity of its California heavy petroleum distillate. The gas may be sold for use crude oil pipeline system between the southern San as boiler fuel while the balance of the output will be sold Joaquin Valley and the San Francisco Bay area by looping as refinery feedstocks. 70 miles of line and adding pump horsepower on another 175 miles. The project will boost the capacity of Getty's The project will require 360 thousand gallons of water system between MclCittrick and Coalin ga to 145,000 bId per day for cooling water makeup and steam generation. from 50,000 b/d and between Coalinga and San Francisco The plant will discharge about 80 gallons of waste water to 220,000 b/d from 145,000 b/d. Work on the project is per day, but produces no solid waste on a continuous scheduled to begin this spring and be completed in two basis. Small quantities of an inert material used in the years. The entire pipeline expansion program is process is expected to be trucked away from the job site expected to cost $40 million. The 16 in.. 70 mile periodically. segment from McKittrick to Coalinga will have a 95,000 b/d capacity and parallel an existing heated 12 in. line. Construction on the plant is expected to begin within 3 The loop also will be heated. The existing heated 20 in. to 6 months, and to continue for 18 months thereafter. line from Coalinga to San Francisco will be increased in Production start-up should be attainable by early 1983. capacity by 75,000 b/d with the addition of four pump stations. All environmental permits necessary for the construction of the facility have been issued. The project has been Union (110,000 b/d), Exxon (100,000 b/d), Tosco (135,000 annexed to the local Sanitation District. Authority for b/d), Shell (105,000 b/d) and Chevron (365,000 b/d) all construction has been issued by Contra Costa County. use the current Getty pipeline and therefore are likely The project site is a 21 acre lot that previously has been users of the expanded line. Getty also uses the line to used as an asphalt terminal. The surrounding area is move its production to those refiners, particularly Tosco. devoted to heavy industrial uses, including rail yards, Champlin has no San Francisco Bay area refinery, and is petrochemical plants, and petroleum tank farms. interested in moving its production south to Los Angeles. Union, Shell, Chevron, Champlin and other producers Peak construction workforce should be less than 100 have L.A. refineries. persons, at the job site. In operation, the project should provide about 40-50 new jobs, covering a normal range of Additional Pipeline Expansions Are Currently Under occupations. Activity of this magnitude will produce no Examination major strains on the facilities available in the Pittsburg area. Normal types of housing and transport are avail- Two industry sponsored pipeline studies are in progress, able. and should be completed by mid-1981. A study is underway by four companies to determine the feasibility California Synfuels Research Corporation seeks a loan of another crude oil line to move San Joaquin crude to guarantee for a private sector loaii in an amount up to outside refining markets. one half of estimated project costs, now estimated at approximately $18 million (1/2 of about $36 million). Bechtel Petroleum's pipeline and production facilities division will prepare the feasibility study to assess potential routes and pipeline systems for transportation of expected increases in San Joaquin Valley heav y crude GEnY/OTHERS TO EXPAND CALIFORNIA production to major refining areas in California. Parti- PIPELINE CAPACITY cipants in the study are Shell Oil Co., Chevron Pipeline Co., Calnev Pipeline Co., and Four Corners Pipeline Co.. Southern California heavy oil production has been owned by Atlantic Richfield Co. steadily increasing for many years, and industry has wrestled with planning for producing, moving and refin- Bechtel Petroleum Inc. is contractor for both studies, ing the oil. Total production in the San Joaquin Valley and the Callifornia Energy Commission is a participant has risen to 550,000 barrels per day from 400,000 barrels in the coastal study. The study groups are separate and per day, mainly because Elk Hills field went on produc- are separately financing the studies. Woodward-Clyde tion during that time. New pipeline facilities are needed Consultants, San Francisco, will handle the environ- in the San Joaquin area because of an anticipated mental-permitting considerations. increase in heavy oil production, possibly more than double the current output of 200,000 to 210,000 barrels Although well aware of Getty's capability to expand per day. Although actual production increase estimates their 20 inch pipeline, the consortium was somewhat must be measured against anticipated declining rates in surprised by the suddeness of Getty's expansion plans. older fields, the recoverable reserves may exceed 5 Three routes for new heavy oil pipelines were to be billion barrels. California estimates its heavy oil pro- studied. The options included north from the San

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-7 Joaquin Valley to the San Francisco area, south to the believes that the Synerude plant merits world price Los Angeles area, and west to a Pacific Coast location because of its larger size, its higher initial capital between the two cities (possibly directly to the central investment and its higher operating costs. Suncor points line from the Santa Barbara Channel and surrounding out that the total shutdown and cutoff of production production areas to the Los Angeles refineries). Initi- necessary to maintain their plant at safe and efficient ally, one choice was to place a pipeline alongside the operating standards is one example why, on comparative existing (,city line between McKittriek and Coalinga. scales, larger plant size does not translate into relatively Pumping stations could then be added to the linked 20- higher costs. The plant, which was designed on the basis inch Getty line that currently feeds the Ba y area, 175 of the best technology possible under the economic and miles to the north. Getty had built the line in anticipa- regulatory conditions prevalent in the early 160's, is in tion that on day it would be expanded. Shell Oil Co., one many respects more costly in operation than Syncrude's. of the four participants, said it will continue the study of a line capable of moving 100.000-250,000 b/d of crude. Because Suncor's production no longer receives the world Because of the Gett y project, however, the study won't price for its synthetic crude, the need to manage the include movement to the San Francisco area but will be turnaround efficiently is especiall y essential. A reduc- confined to the Los Angeles area and west to a Pacific tion to the wellhead price of domestic oil ($17.75 per Coast location. barrel) during the last two months of 1980 also caused cash flow problems related to the maintenance project. The estimated costs of this turnaround, excluding the value of the production lost, were accrued throughout SUNCOR SHUTS DOWN FOR BIENNIAL 1979 and 1980, and were based on continued reception of MAINTENANCE world price.

During Ma y and June of 1981, Suneor Inc., will shut down The- raw statistics for the oil sands plant turnaround the Fort McMurray oil sands plant for a turnaround and project are alone impressive. Table 1 contains a break- maintenance program. The project will cost Suneor $21 out of manhour requirements by department. Super- million for maintenance turnaround and $36 million in visory input from personnel within Suncor's Oil Sands lost production capability (1.8 million barrels at $17.75 Division and within Catalytic Enterprises Ltd. per barrel). Another $13 million is planned for capital (CATCO)--a contractor providing manpower in main- engineering works and tie-in equipment that comprise tenance engineering and labor— will total approximately the last phase of Suneor's $185 million plant expansion. 84,000 man hours. Labor (by Suncor Inc. and CATCO) Conducted every two years. the maintenance turnaround previous to, during, and after the maintenance phase will consists of a thorough inspection and overhaul of the amount to nearly 400,000 man hours. Assistance pro- equipment in the complex. vided by other contractors (primarily A.B.M.. a consortium consisting of Associated Engineering Services, The preventive maintenance program was designed to Canadian Bechtel Ltd., and Montreal Engineering Ltd.) enable the plant to operate for a two- year period with- will add up to approximately 79,000 man hours. out any shutdowns that would interrupt planned production schedules. Because of the plant's single train In total, the turnaround project proper will consume in structure, all production units must he simultaneously the order of 560,000 man hours of supervision and shut down to maintain them at their originally designed physical labor. When the approximately 117,000 man levels of proficiency. Once the maintenance work is hours required to complete expansion tie-ins and capital complete. the plant can be started up and returned to engineering works are added, the total amount of turn- full production. around, expansion, and engineering related work to be conducted during the term of the turnaround project Twenty years has past since the Suncor plant underwent amounts to just over 670,000 man hours. conceptual and detailed design. At that time, the technology was innovative, the economies were risky. and the capacity was only 45.000 barrels per day. As the first of its kind on a full commercial scale, corporate management concluded the design volume could be achieved most economically through construction of a plant that would operate along a single, integrated production train. Because this train is made tip of an interacting line of units, it would be impossible to shut down and maintain one of these units and leave the others in operation. The periodic maintenance is an all- at-once proposition that inflicts partial production loss while the plant is being shut down, full production loss while it is in outage and maintenance is being done, and partial production loss again during start up to full-scale operation. According to Suncor's present estimates, the 1981 plant turnaround will occupy a 44 day period. The Synerude plant incorporates two production trains, one of which can be shut down for maintenance while the other continues operation. The Federal government

3;8 CAMERON SYNTHETIC FUELS REPORT, JUNE 1991 TABLE I MANhOUR REQUIREMENTS FOR TURNAROUND PROJECT

Cataly tic Enterprises Ltd. DEPARTMENT Baehte] Ltd lire-Mains. Mains. Pl MaiM. Clean Stçer- Supervision Turnaround Turnaround Assoc.Eog.Svcs. TOTALS per Turnaround Up vision Mains. Operations & Monitoring Montreal Eng. flepsrtnien 3.400 114.0011 11,30D 6,100 21.200 31500 4,000 66,500 240.000 Utilities 1,200 27,000 4,000 1.900 4.000 2,000 9,200 4,000 53,000 F,,trection I, 900 22,500 100 2.000 6,400 4,800 '6,000 400 04.000 Mine 39,000 7.000 0,600 34,000 42,900 128.60n C et 't r a MaIntenance 6.400 1.600 1.600 7.200 20.400 4.600 33.900 Ad's, nistratice, 2,100 15.400 9.300 21.000 3.200 51 .000 TOTALS poe Proirct Pt,0,0 0,400 213,000 15.41 1 0,600 $2,600 54,400 00,300 31,400 79,200 561,200 The Dgures listed are routed to MAN'IOUR REQUIREMENTS nearest hundred. FOR EXPANSION AND ENGINEERING WORE TO BE CONDUCTED DURING MAINTENANCE TURNAROUND 'Fl,e figures listed ON lire-Mn ins. - Turnaround. linsI Maint. Turnaro,,nd Catalytic Succor Cat. Bechtel, TOTALS per & Clan'Up represent labor eondue' Enterprises lee. Ane.Eng.ssr,. Expansion or ted during I bose pI,nscs. I.Ini led Montreal Eng.etc. F.ngl neering The Figures lIsted for Maint, b Opec- Erl neerie 46,000 200 Mien represent loon' conducted by 5,700 003.200 bnrgaining-tnit employees. Expansion 13,000 13,500 TOTAL: Espansion 116 .700 561,200 & Engr. 116.700 TOTAL: Turnaround. Exoanoire & Engineering 677,900

MAJOR OIL SANDS PROJECTS REACT TO CANADIAN N EP development, engineering, and research at a minimum level, but two participants, Petrofina Canada Ltd. and Amoco Canada Ltd.. wanted a smaller financial commit- Although the controversial Canadian National Energy ment. The consortium, headed by Shell Canada Policy has affected an entire energy industry, oil sands Resources Ltd.. declined to approve any expenditures on development especially has been caught in the middle. the project for the second half of 1981. Because Alberta chose to dela y giving approval for two specific oil sands plants in order to gain political The Alberta government has refused to grant approval leverage, future development plans for the resource have for the project until an overall energy-pricing agreement been in the spotlight. These projects must be contin- is reached with the Federal government. Alsands firmly uously reevaluated in light of the changing economic threatened to abandon the project if an agreement is not climate. In response to an unfavorable market evolving reached by June 1981. However, it appears that as long out of proposed NEP provisions, four major oil sands as negotiations between Alberta and Ottawa show pro- projects have made arrangements to either alter or gress. Alsands will tr y dissolve their intended activities if an agreement is not to keep the project alive until achieved. fall. The delay has already increased the estimated costs by $5 billion to $13 billion and the plant cannot be completed until 1988. Most of the $200 million planned Alsands Delivers Ultimatum and Waits for this year would have been spent on development work, technology, and staff to get the project underway. In response to the continued deadlock between governments on taxation, ro The $35 million budget allowed for 200 members of the yalties and the price of synthetic research and development staff to be kept on, site fuel, Alsands directors worked to slash the 1981 develop- preparation work already begun to be completed, and ment budget for its $8-billion tar sands project. All of some technology to be acquired, although not as much as the companies agreed that activity should continue at planned. some level (through June 1981), and that it was not necessary to ask the Federal government for financial Suncor. Inc. Will Complete Expansion Despite Dubious assistance. They decided to spend $35 million over the Future six month period to keep the venture alive. The approved $35-million expenditure represented a drastic The impact of the Canadian National Energy program on cut from the $200 million which the nine-member consortium planned to spend in 1981. Suneor, Inc., operators of the world's first synthetic crude facility at Ft. McMurra y. has been considerable. Early in February, "The Calgary Herald" contained a Seven of the nine companies in the corsortium voted for two-part series analyzing the severity of Suneor's situa- the $35-million minimum expediture to maintain site tion. The situation has not improved since that time.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-9 The first commercial-size oil sands plant in the world. about $810 million, which works out at $18,000 per Suneor was faced with a number of technical problems barrel of daily production. The same calculations for during its early years. and reported considerable losses Syncrude leaves it with unrecouped investment to date from the start-up of operations in 1967 through to 1975. of $17,000 per daily barrel of production (a total of $2.3 Only in the late 1970s did it begin to turn a profit as the billion). Under the new pricing regime, Suncor's pro- technical problems were overcome. The situation jected revenues for this year are estimated at about improved enormously when the plant was awarded the $300 million, but operating costs will be $200 million. world price for its production in April 1979, in order to Royalties and taxes will take most of the balance. The finance a 15.000-barrel-a-day expansion. provincial government royalty averages 12 percent (eight percent on the first two-thirds of production, 20 percent That $185-million expansion is going ahead, as the incre- on the remainder). There is also a five percent royalty mental production has been promised parity with Syn- paid to Noreen Energy Resources Ltd., federal income crude. The neighboring plant received the world price tax and the new eight percent petroleum revenue tax to from the start of operations in 1978, and continues to be paid. The profit margin works out at less than $1 a receive the present world price of $43 a barrel, (although barrel. But while the net, after-tax income still amounts now to increase, not with world levels, but with the to $14 million, the need to invest more than $50 million (Consumer Price Index) from a base price of $38 per in modifying and buying new equipment will result in barrel). negative cash-flow of $40 million. For every barrel produced. the total expenditures this year will be just Since November 1. 1980, Suneor has again received the over $21. basic domestic conventional price, currently $17.75. Based on a projected negative cash flow of $40 million The capital expenditures are expanding Suneor's asset on total -output of about- 15 million barrels,-Suneor Inc., base, so it can be argued that these should be ignored. expects to lose about $2.60 for every barrel of synthetic Bowever.èvcnthe $14 million net-income represents a- crude produced in 1981. Despite 13 years of production return of only 1.7 percent on an accumulated present- from the 45.000-barrel-a-day plant, executives figure value investment of $810 million. On the depreciated that, in 1980 dollars, the company is still more than $800 value of the company's capital assets—estimated at million out of pocket. That is the total investmentyet about $580 million—it represents a return of 2.4 percent. to be recouped, and which cannot now be recouped for An unexpected shutdown, caused by an event such as the several years because of the National Energy Program. recent fire, could wipe out the profit margin completely. Even by the turn of the centur y, as the life of the Suncor plant comes to an end, present projections indicate it Ottawa views the situation differently. The Canadian will have generated an average annual rate of return of government continues to insist that it has more than met just 7.3 percent on a total $20-billion investment. If the terms of an agreement with Suncor Inc. Suneor has Suneor were to receive the $38 per barrel plus CPI price. said that it agreed to the $185-million expansion of its the rate of return is projected at 11.4 percent, which is oil sands plant on the understanding that Ottawa would still a low return on such a high risk venture. authorize world level prices for its synthetic oil effective April 1, 1979. The expansion was well along when Ottawa announcedin the Oct. 28 budget that domestic- The decision has already been made that, without a reversal of the pricing decision, it will be necessar y to level prices would be paid to Suncor oil produced from shelve two oil sands projects which could have added 120 existing facilities but $38 plus a special oil-sands incentive would be paid to Suneor oil produced from expanded million barrels of synthetic crude to Canada's reserves. facilities. The minister said the Federal government not One is the so-called Peninsula Project. A certain area of the Suneor lease contains a particularly thick seam of oil only permitted Suncor to recover the cost of the expan- sands, but it is under exceptionally deep overburden-40 sion, but also let Suncor get world-level prices longer. metres. This makes it highly expensive to get at. With Suncor received about $300 million which should cover any inflation costs. the $38 price, the economies would be "marginal", but at $17.75, it is not viable at all. The peninsula is logically Lalonde said Suneor may have an argument in terms of the next place to mine as the bucketwheel excavators progress across the Suneor lease. However. it will now equity, in view that the nearby Synerude Canada Ltd. be by-passed, and the 90 million barrels of oil it contains plant receives $38 a barrel. But the Syncrude plant was will be lost forever. To go back to that area later will built with the condition that its oil would receive world- cost up to six times as much as it would now. level prices, whereas Suncor oil had been receiving domestic-level prices.

In addition, a project to extract bitumen from the oil- Regardless of the outcome of pricing negotiations, sands tailings has been abandoned. Normally, using the Suneor will spend $57 million this year to complete the hot-water extraction process. about 92 percent of the three-year expansion which will increase production to bitumen in the oil sands is recovered. Suneor has 58,000 barrels of oil a day from the current 45,000. developed a technique, which, it estimates, could extract Suneor spent $98 million on the expansion last year and a further six percent from the tailings. That in turn $30 million in 1979. Parts of the expansion will be on would add a further 30 million barrels of reserves. At stream by July and the full increased production will be sub world prices, the economies are no longer favorable. flowing in 1982. The Suneor plant's revenues during the 1970s amounted Esso Cold Lake Plant Carries On to almost $2 billion. Even so, the amount of investment yet to be recouped is claimed by the company to be By late 1980, Imperial had announced that it was shelving the Cold Lake project because of delays and

3-10 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 energy disagreements between the federal and Alberta interest in the project, did not include its name on the governments. In response to this decision, the Canadian list of firms making the announcement. The new refer- government agreed to lend Imperial $40 million to keep ence price of $38 per barrel plus indexation (rather than work going on the stalled $8 billion oil sands project. the guaranteed world price for s ynthetic crude) and The estimated cost for the project has since escalated to other budget measures (such as the new tax on revenue) $12 billion, (rising $100 million for every month of made the expansion program uneconomic. Currently, the delay). Imperial believed the cost to be too high for a $2.3 billion Syncrude plant has two production trains and company to bear in view of the conditions included in an authorized daily production of 129,000 barrels a day federal budget and the lack of progress on agreement of synthetic crude oil. between governments. The company called on the two governments to pay for ongoing development costs and Petro-Canada officials have been asked by the other the cost of keeping a project team together until they partners to refrain from participation in meetings where resolved their dispute. Initiall y Ottawa proposed that energy-pricing and negotiations with the federal govern- half of the loan would be supplied by Alberta. However, ment were being discussed. Because the Federal govern- the Canadian government was prepared to advance $20 ment will continue to honor the 1975 pricing formula as million plus an additional $20 million if Alberta was not long as negotiations continue with Alberta, Synerude still willing to participate. Alberta would not put up the receives world price for its production, which has been money, because it considers the Federal government selling in recent weeks at $43 per barrel in Montreal. responsible for the situation. The $40 million loan was not a grant and would be repaid if the project goes ahead. If the project dies, then the money is lost to the government.

The financial aid was sufficient to sustain the project through mid-1981. Imperial does not plan to ask for any additional assistance, and the federal government sa ys no more financial help will be offered. At present, the project would take a minimum of two years to start up again, even if the provincial go ahead was given. If Ottawa can't come to terms with the provinces by June 30, the $40 million federal loan will have been spent and Imperial will cease to work on the project. Most of the "office work" on Cold Lake will have been completed, and the future of the project depends on its financial viability. The project will probably be shelved indefinitely if an agreement including a pricing, taxation and royalty regime is not reached by fall 1981. Judy Creek CO Flood Shelved

Esso Resources Canada also postponed indefinitely its proposed carbon dioxide flood of the Judy Creek field following a reassessment of the economics after the federal budget announcement. The $470 million project, the first CO flood for Canada, was approved by the Alberta Energy Resources Conservation Hoard in March 1980. Injection was scheduled to start in early 1982. It was expected to boast recovery by 15.000 to 20,000 barrels per day. In May 1980, Esso evaluated the project in light of engineering studies and new cost estimates in an effort to reduce costs. The Canadian energy policies made the project completely uneconomic. Syncrude Plant Suspends Expansion Plans

The preliminary engineering studies for a $2-billion expansion plan (to be completed in mid-1983) at Syn- crude's oil sands plant were suspended indefinitely. The Synerude expansion would have added a third production train and approximately 70,000 barrels per day of capacity to the present plant in Fort McMurray, Alberta. It was scheduled to begin in 1988. The decision came as a result of the combined negative impact of the federal budget and the government's National Energy Program. The announcement was made for eight of the nine partners in the project. Petro-Canada, the federally owned oil company which currently has a 17 percent

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-li TECHNOLOGY

PHYSICAL SEPARATION APPLIED TO UTAH OIL Moreover, the rejection of greater than 60 percent of SANDS the sand, the uniformity of the concentrate, and the ease with which water can be removed from the concentrate "Concentration of Utah Tar Sands By An Ambient make the ambient temperature process strategy attrac- Temperature Flotation Process" by J.D. Miller and M. tive and cost effective in comparison to the hot water Misra was presented at the Annual AIME meeting in process. The most significant factor of the ambient Chicago, Illinois on February 22-27. 1981. The paper temperature process is the energy efficiency. The presented results from a study which successfully energy required to achieve effective separation by this achieved physical separation of bitumen from low-grade ambient temperature process is significantly less than Utah tar sands containing n relativel y high viscosity the energy required for the recently developed hot water bitumen phase (Sunnyside and Tar Sand Triangle deposits) process. Calculations indicate that required energy by traditional size reduction and froth flotation tech- input for phase disengagement by digestion in the hot niques. water process is at least 45 kWh per ton for greater than 90 percent recovery; whereas, for the ambient tempera- Under certain conditions (grinding to a sand size distri- ture process, the energy input for phase disengagement bution of 60 percent less than 100 um. 5.0 lb/ton by size reduction is substantially less, requiring only 13 promoter and 5.0 lb/ton dispersant), more than 90 per- kWh per ton for greater than 90 percent recover y. The cent of the bitumen can be recovered ina concentrate findings of this investigation add to the current physical which itself is an excellent feed material for either the separation pro€ëss alternatives-for tar sand materials. A hot water or thermal process. As expected, in the summary of these physical separation processes is pre- absence of alkaline digestion, the flotation behavior and sented in Table I. contact angle measurements of the tar sand sample indicated that the bitumen had a naturally hydrophobic character. The best flotation response was obtained at moderatel y alkaline pH. which correlates with the apparent iso-electric point of the bitumen as determined from titration curves. TABLE 1

PHYSICAL SEPARATION PROCESSES FOR UTAH TAR SANDS

Processing Strategy Tar Sand Source Bitumen Coefficient Phase Phase and Viscosity at of Disengagement Separation Percent Bitumen -90°C, poises Separation Low shear. Gravity Athabasea, 2.5 0.9 hot water settler Canadian digestion High grade Utah Effectiveness Tar Sands, Asphalt limited due Ridge and P.R. Springs. to with diluent addition emulsification

High shear, Modified Asphalt Ridge and 10 0.9 hot water froth P.R. Springs Sunnyside. 0.7 with controlled diluent addition

Liberation Traditional Tar Sand Triangle >100 .5 by size froth and Sunnyside reduction flotation followed by HWP of concentrate

3-12 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981

SYNCRUDE DEVELOPS TWO-STAGE FLOTATION process, is that for some very lean (low bitumen content) PROCESS feeds, as much as 90 percent of the bitumen is recovered in the flotation cells. Canadian regulatory agencies have A new approach to conventional hot water separation determined that tar sands as low as 6 percent bitumen processes seems to hold promise for economically are to he processed, and that a smooth and efficient extracting more bitumen from poor grades of tar sands. operation may not be possible with conventional techni- Devised by L.M. C y mbalist y , senior research engineer ques. for Sy ncrude Canada Ltd. Research (Edmonton, Alberta). the two-stage process has been under development for In Sy ncrude's two-stage route, the tar sand is slurried more than a decade, and is now going through final and screened in the conventional manner. The mass then optimization in a 2.5-ton-per-hour (tar-sand feed) pilot goes to a sand settler, where it impinges on an inverted plant operated by Syncrude. cone that encourages separation of coarse sand. The sand slides down the cone's surface and meets a counter- The advantages of using the process are that it uses less current wash by an aqueous phase (middlings) from the energy and water than conventional methods. The key is froth separator. This wash removes any remaining gentler washing action, done at lower temperatures, that bitumen. doesn't break up the bitumen as much, but nevertheless attains a higher recovery efficiency (95 percent) than Water and separated bitumen are pumped from the top the traditional Clark process (85 percent), in use since of the sand separator to the froth separator. Here the the 1920s. mixture is evenly distributed by means of a submerged rotating distributor. As this unit passes any one point, Conventionally, tar sand, hot process water, steam and and the turbulence of feeding subsides, the bitumen rises small amounts of sodium hydroxide (n separation aid) are and any sand and fines (such as clay) settle. fed into a cylindrical rotating tumbler in which the tar sand is disintegrated by mechanical and thermal energy, A fresh-water wash (the only use of fresh water after and the bitumen, locked between the sand grains, is initial slurrying of tar sand) introduced above the rota- liberated. The resultant oil y slurry passes through a ting distrihutor further cleanses the bitumen as it rises, screen to remove any oversized material, and is flooded and the downward flow of water helps settle the fines. with more hot water to further break up the sand and Settled sand and fines move on to a secondary recovery bitumen. This material next goes to a primary separa- operation. Figure 1 shows a flow diagram of the tion vessel where aerated bitumen rises to the surface as Syncrude Bitumen Extraction technology. a froth and is collected for further treatment. Sand settles and is withdrawn as tailings. Energy input to the sand settler should be adequate to provide effective separation, but sufficiently low in A mixture consisting primarily of clay and water, and sheer to avoid emulsification of the bitumen phase. To depleted of sand and hitumen (referred to as "middlings") isolate the effect of turbulence within this zone on the is processed further in flotation cells where, by means of adjoining settling areas, the mixing chamber is enclosed air addition and agitation, a second yield of froth is by a shroud within which two sets of turbulence recovered. The primary froth typically consists of 65 dampeners are installed. The upper boundary of the Percent bitumen by weight. while the secondar y froth mixing zone takes the form of a cone with an orifice at anal yzes at around 25 percent. A drawback of the the apex. Aerated bitumen globules escape through this

Tar sand H2O + NSOH earn

Bitumen, water and unsettled fines — — — Tumbler Scree Turbulence n -' Oversize --,' dampers M ixing zone j Feed enclosure JSlurry Invenod Freshç 8 tusesen cone water I for further Processing) Middlings rec"I. Fired t.bk sand settler Froth separator Rotating diniribusor

Tailings nm Ito disposal I Ito secondary recovery)

a,.,.,. ..,.,. C-1 L.a as FIGURE 1 SVNCRUDE TWO STAGE BITUMEN EXTRACTION PROCESS

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 3-13 orifice while sand and the remainder of the bitumen As the distributor arm rotates, it creates local turbu- escape downwards into the settling zone through the lence in that region where the in-coming slurry is bottom of the mixing chamber, at a velocity preferably distributed. The speed of rotation and the number of no greater than 0.3 m/see. The exit velocity gives rise rotator arms are set to allow this turbulence to subside to radial currents causing flow of the diluted slurry sufficiently for the bitumen and solids to escape before across the upper portion of the settling zone. At low the next distributor pass. Swarms of bitumen globules mixing zone exit velocities (0.08 to 0.15 m/sec) these have been seen to arrange themselves in a tight forma- currents may be allowed to flow across the vessel tion on the underside of the froth layer and then to unhindered. However, at higher velocity, additional cone coalesce. The distributor outlets are at a shallow depth surfaces or other baffling means are needed. under the surface so that low hydrostatic pressure allows a large volume of gas bubbles to remain, serving as a As the slurry components pass down the vessel they are buoyancy agent for lifting the bitumen. Distribution of subjected to diminishing turbulence, and the sand settles the slurry is made uniform by using cone-shaped distri- more rapidly. It collects on the upper surface of the butor heads at the ends of the arms. settling cone and slides downwards. The sand has been observed to describe a rolling action, which is beneficial The quality of the product is very much dependent on to bitumen release. With increasing vessel diameter the this step, particularly in large separators. It prevents downward vector and turbulence are further reduced "crowding" by reducing local effects, such as density and allowing more bitumen escape into the liquid phase. thermal currents. It also reduces hindered settling by Passages connect the settling zone to the mixing zone's lowering interference between settling solids and rising by to allow unhindered ascent of the released bitu- bitumen. men. The currents required to impel this released bitumen are provided by recycled -middlings from the Fresh underwash water is introduced beneath the froth froth settler. This stream, introduced in the bottom part layer but above the distributor-arms. An this way a of the separator, yields a totally dynamic environment highly diluted zone is provided, through which the by causing upward flow of liquid currents within the ascending bitumen passes immediately before joining the entire vessel, thus fulfilling two requirements: froth. This helps to clean the bitumen of solids and thus contributes to high froth quality. It also maintains a elutriating the bitumen from falling sand mild downward current that depresses the fines to the (counter current wash) middlings withdrawal point. Underwash water was usually added at a rate of 8 to 12 kg/100 kg ratio of levitating of bitumen trapped in the bottom water to bitumen in the froth. Only the excess is of the sand separator, thus enhancing its involved in the downward flow. The dilute, underwash recovery. zone leads not only to clean froth, but also maintains stable operation even when high fines tar sands are being When the sand reaches the conical bottom of the vessel processed. Underwash, when installed in the primary it is forced to compact. and bitumen entrained in the separation vessel of the conventional process pilot plant, interstitial slurry is squeezed out. Any aerated bitumen did not give these advantages, probably due to a differ- so released is carried by the upward flow to the under- ent system of distribution of the slurry. side of the bottom cone and then via the bypasses to the upper exit of the vessel. Unaerated bitumen globules in Tests at Edmonton show 95 percent bitumen recovery combination with sand and clay particles, tend to form a from medium-quality tar sands (10-11 percent bitumen layer above the turbulent region caused by the sliding content), vs. the usual 85 percent. The pilot plant sand stream and follow it to the lower strata of the sand operates at 45°C, which is considerably below the 80°C settler. Here, without due care, a sludge y substance is needed to break up the bitumen in conventional pro- formed above the sand-liquid interface. The bitumen cessing—an energy-saving feature. And because of re- content of such sludge can be as high as 20 percent. To cycling, the unit uses only half the water required by counteract this occurrence, a relatively bitumen-free other methods. aqueous stream is introduced just above this sand-liquid interface. The source of this aqueous stream ma y be If the demonstrated recovery efficiency can be main- clarified tailings pond water or secondary oil recovery tained on a commercial level, the Syncrude route has tailings. The spent sand, diluted by the above liquid, is good potential for application in existing tar-sand plants. pumped to disposal from the bottom of the sand settler. Overhead from the sand settler is led to the second stage, the froth separator. Velocities during this trans- POTENTIAL FOR INDUCTION HEATING METHOD IS fer should be kept between 3-4 m/s to prevent formation DISCUSSED of bitumen-solids agglomerates. In his paper "Processing of Solid Fossil-Fuel Deposits by The purpose of the separator is to allow spontaneous Electrical Induction Heating," Sidney Fisher identifies flotation of the aerated bitumen under such conditions two significant improvements in the heating of solid that the maximum amount of clean froth, high in bitu- fossil fuel deposits by eddy currents induced by an men content, is recovered. The desired conditions are alternating magnetic field. One is the injection into the obtained by introducing the sand settler overhead into fuel layer by pressure, from the surface, of a hot, the separator by a rotating distributor located about 0.5 saturated, high-conductivity, saline aqueous solution. in - 0.75 below the froth-middlings interface and by a The second is the use of a composite casing conductor, froth underwash system using preferably fresh water. consisting of an inner steel tube welded to an outer copper tube.

3-14 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 For typical fuels, the electrical inputs now estimated as Composite Casing/Conductor Materials Must Withstand required to evolve 90 wt percent of the volatiles and the High Temperatures corresponding thermal/electrical net energy ratios, for ideal loss-free conditions, are: A review has been made of the various possible lining materials for the shafts and tunnels of the underground Fuel kWh/t Net Energy Ratio eddy-current heating installation. Previous proposals have suggested casings of alumina cement, since they Coal 395 12.3 must withstand high temperatures and pressures. An Oil sand 153 8.8 alternative suggestion is now thought to be preferable. Oil shale 139 7.9 This is to construct the tunnel and shaft casings and Heavy oil 154 8.8 electrical conductors of an outer tube of copper welded to an inner tube of steel. The outer tube provides a In practice, net thermal/thermal energy ratios of about high-temperature large-diameter thin-walled low-induc- half these values can probably be achieved. tance low-resistance corrosion-free conductor, and the inner tube provides the required strength against crush- Eddy-Current Heating Requirements Examined ing by formation pressure. The coolant can occupy its whole volume so that pumping energy is reduced, and can For fuel-plus-saline resistivities of I and 10 2cm, a be treated to inhibit corrosion of the steel. range of values that can probably be attained, the penetration depths in meters in eddy-current heating are Provisions do not have to be made to separate the computed to be: coolant and conductor paths. The overall diameter will be much less using the new casing/conductor, reducing the cost of construction. The casing can be jointed by Resistivity in Frequency in Hz brazing or welding, and the hazard of high-temperature 60 100 300 high-pressure gasketted nonmetallic joining is avoided. Development of a technique for laying the metallic 9.0 5.0 2.7 casing by jacking from the vertical shaft, and removing 10 30 16 metallic casing by jacking from the vertical shaft, and removing the spoil hydraulically, with no men in the horizontal tunnels is now under way. This may further For effective eddy-current heating, the seam thickness reduce the casing diameter. Since a zero field exists must be greater than about three times the penetration. inside the conductor, no field energy will be expended Thus in fuel seams of 30 m. a frequency of 60 Hz can be directly in either the casing or the coolant. In addition, used where a resistivity of If2-cm can be achieved, and the heat extracted by thermal conduction from the hot 300 Hz where the resisitivit y is 10 fl-cm. The wave- fuel mass by the conductor is reduced in proportion to length of 300 Hz is about 1000 km a very large multiple the reduction in its diameter. In order to facilitate the of any coil length proposed. so that no standing-wave corner jointing of the conductor/casing, two vertical problem is encountered. Where a seam thickness in shafts can be sunk through the overburden, at the ends of excess of 100 an is encountered, 60-liz current is effec- the traverse tunnel. This will permit access to the four tive even for a resistivity of 10 Qcm. corners of each conductor loop, so that the right-angle joints can be made. The fuel water content is not allowed to evaporate until after the onset of pyrolysis due to the rising tempera- Dielectric heating Requires Closely-Spaced Underground ture. Thus the high conductivity imparted to the cold Passages fuel by the electrolyte injection carries over the pyrol y -sis phase of I and 10 This is the same range of In the dielectric-heating, much closer spacing of under- values imparted to the cold fuel by the injection of ground passages is required than for eddy-current heat- electrolyte. ing. Horizontal tunnels are driven in parallel rows above and below the area to be worked. These are 2.5 m by 4 For some of the solid fossil fuels, pyrolysis begins as low m in cross section, and have a horizontal spacing of as 200°C, and at this point, the electrical conductivity is between 5 and 10 M. Verticle drillholes. 12.5 can in already increasing. In all the fuels, the pyrolytic reac- diameter, are driven between matching tunnels, with a tions reach a maximum at about 500°C. Above 600°C, in spacing of I to 3 m. The horizontal tunnels are all cases, less than 10 wt percent of the volatiles remain. connected by two transverse tunnels, also 2.5 by 4 an in cross section, which are reached bya 3- or 4-in diameter These temperatures are at atomospheric pressure. At shaft from the surface, or which emerge at a sidehill high pressures (10 MPa), additional carbon will be preci- location. pitated, and results in an estimated loss of 20 wt percent of the hydrocarbons. When the water and other volatiles A brief calculation of the requirements for drillholcs, are retained up to a pressure of 10 MPa, while the tunnels, and shafts for a typical area of fossil-fuel process of induction heating is continued to 600°C, it is deposit 1 km square, with a thickness of 100 m, and a estimated that the additional hydrogen and oxygen ions, depth of 1000 m, yields the following striking comparison probably formed from water by the induced currents, of the two methods: will approximately offset the increased carbon precipitation due to the dwell time of the hydrocarbon vapors in contact with processed hot carbon. It is likely that the sum of the two effects will be near zero. No firm conclusion is possible without carrying out experimental work closely resembling the actual conditions proposed.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-15 hire content, rain, and aquifers. It is voltage limited, so Eddy-Current Dielectric that close spacing of electrodes is required, and high Structure Heating Ratio Ratio voltages are required. It requires frequencies in the Drillholes 66 km 5000 km to 75 to 150 megahertz band rather than the 60 Hz of the eddy- 10,000 km current plan. The generation and distribution of such Tunnels 44 km 202 km to 404 4.6 to 9.2 frequencies is costly and complicated, and results in km (2.4 x 4m appreciably lower efficiency. cross section) Vertical 1.1 to 2.2 km 1.1 to 2.2 km 1.0 Shaft (3- 4-m din- BETC AWARDS CONTRACTS TO STUDY MICROBIAL OIL RECOVERY The Department of Energy's Bartlesville Energy Tech- In addition to the much greater length of underground nology Center (BETC) has awarded research contracts to passages in the dielectric scheme, the tunnels required the University of Georgia and the University of Southern are many times the cost per unit length of the tunnels in California for studies to determine if bacteria can he the eddy-current scheme. At an estimate, the total cost used to help produce oil. Both projects are scheduled to of drilling and tunneling is 100 times greater for the be completed in early 1982. dielectric scheme than for the eddy-current scheme. University of Georgia Studies Viscosity Reduction In dried fossil fuel, the voltage gradient permissible for the dielectric plan is about 2000 VIm, so that with place The Department of Microbiology at the University of spacings of 10 m. the maximum assumed, 20;000-V •must Georgia has i $75,000 contract to assess whether microbe employed. This appears to dictate use of a maximum organisms can be used to reduce the viscosity of heavy plane spacing of S m, with an applied voltage of 10.000 oil, making it easier to recover and process. According V. The system is definitely voltage limited, and the high to project director W.R. Finnerty, the research will voltage required appears to be the first factor rendering focus on selecting, training or even constructing micro- the scheme of questionable practicability. This is organisms that will oxidize or metabolically alter crude emphasized by the fact that moisture will inevitably he oils. encountered in the deposit initially or during the lifetime of the operation, and when it does, breakdown at much Organisms will be examined from heavily biodegraded oil lower voltages will occur. reservoirs and from reservoirs that haven't yet biodegraded. The effects of bacteria on such elements of The dielectric heating plan requires a very high fre- oil as resin acids and asphaltines will be noted. Sample quency, while the eddy-current heating plan requires micro-organisms will come from sources such as sludge only the usual power frequency of 60 Hz. The required petroleum storage tanks, ponds, or any place that has frequency appears to be in the range of 3 to 6 MHz. The been exposed to oil. The potential uses for these generation. transmission, and application of such fre- organisms will depend on their metabolic characteristics. quencies present grave electrical-engineering problems. But if the bacteria can be isolated, they could be Despite recent rapid advances in high-power high- dispatched underground, probably into older formations frequency solid-state technology, the efficient and eco- to recover oil left after more conventional production, nomic generation of gigawatts at around 3 MHz is or into reservoirs which are only marginally productive. distant. University of Southern California Studies Mobility Conclusions BETC has given USC's Environmental Engineering The author concludes that the figures for net energy Department $90,424 to study microbe reservoir mobility. return for the two systems are about the same, as they The study, directed by Teh Fu Yen, will look at the should be. The advantages of "heating from within" transport properties of bacteria through the porous rock apply equally to both, as do the advantages over other found in most oil reservoirs. Bacteria will be injected electrical in situ approaches proposed—inserted resis- into various rocks to see how they move through dif- tance heaters, resistance heating by conduction, micro- ferent kinds of rocks, and at what rate; whether they can wave irradiation by antennas in drillholes, and so on. survive and multiply or get absorbed; and which genera- The advantages projected for RF heating, apply equally tion of a given bacteria should be used. to eddy-current heating: true in situ processing, no dependence on thermal conduction or convection, no in Previous work has shown that microbes can move situ oxidizing atomosphere, and controlled in situ heating through some types of porous media found in oil reser- zones and temperatures. voirs, such as unconsolidated sand. But the University of California's work will go further, to see if microbes can Fisher concludes also that the eddy-current heating plan is better than the dielectric heating plan on all major actually move through porous reservoir rock saturated with brine and oil. If the microbes will move through the points of comparison, and is the only known option that rock, then they may be useful in recovering oil found in is really a candidate for a major long-term energy rock formations. source. The cost of the tunneling and drilling for the dielectric-heating plan is conservatively 100 times greater. It is unable to deal with appreciable amount of moisture in the fuel, and is hampered by original mois-

3;16 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 BIOTECHNOLOGY PROVIDES AN ALTERNATIVE can be used as a high quality fertilizer, containing about OIL RECOVERY ROUTE 50 percent protein. Water employed in the process can be continuously recycled. Trace remnants of hydro- Worne Biochemicals Inc., of Berlin, New Jersey, has carbons in the water simply become food for the next announced the development of a biochemical method of batch of bacteria. Studies have revealed that the removing oil from oil sands. The process involves a bacterial de-mutate, or return to normal, if spilled into combination of nine bacteria especially adapted for the the environment. job. These microorganisms have developed the ability to utilize hydrocarbons as a source of metabolic carbon. The biochemical method is presently applicable to sur- They produce between 150 and 200 enzymes which face mining operations, but will soon be ready for in situ enable them to "eat" oil. These enzymes cause a change uses. Preliminary work has been encouraging, and Worne in the electrical charge holding the oil onto the sand predicts an in situ application during 1981. The depth particles. Electron exchange releases the oil, rapidly limit is now 1000 feet, due to bacteriocidal temperatures separating it from the sand. Within eight hours after at the greater depths. The bacteria would be combined being set to work in a tank of oil sands and water, the oil with the use of steam for in situ oil sands applications. floats to the top of the reaction tank and can he removed by a separator. The clean sand can be dis- The bacteria have already been used to triple the pro- carded. duction of viscous oil from reservoirs in the Dyer Lease Wells, Oklahoma. The bacteria break up viscous oils. Dr. H.E. Worne began developing the specific bacteria allowing them to flow to the well. Future tests are mix to treat oil sands in 1973. It started with a culture planned in Pennsylvania. Texas, and possibly California. collection including bacteria and fungi from diverse Bacteria can now be used to clear wells clogged with surroundings worldwide. These "bugs" were then care- paraffin residue. fully screened and isolated according to their capabilities. He now holds about 1,600 specific strains in his At present, a 16,000-square-foot plant in Texas grows culture bank. Environments of long-term oil seepage cultures, and a 2.500-square-foot plant in Williamstown yielded bacteria already partiall y adapted to hydro- Junction, New Jersey, deals with agricultural inter- carbon consumption. All strains were then encouraged mediates. About 5,000 square feet of the 17,000-square- to eat oil, and exposed to cobalt 69, strontium 90 or foot Berlin, New Jersey plant are devoted to pure 500.000 volt X-ray radiation to produce slight genetic research. alterations. It took about one year to separate favorable mutants from their fellows. The rate of enzyme produc- In another effort. Worne Biochemicals and Omnibio- tion was constantly upgraded. Nine bacteria were com- techology worked together on the design of a 500 barrel bined to maximize the reaction efficienc y. These are per day pilot plant being built in the Fort McMurray. stored for ready access. Alberta area during this year. Omnibiotechnology of La Prairie, Quebec is working to solve the mechanical To grow an active batch of bugs, nutrient fluid is problems of commercial operation. The Research inoculated with the culture. Strict control of sterility is Council of Alberta. through Omnibiotechnologv, is important. First shaker flasks and then Warne flasks are supplying the oil sands required for experimentation and used to contain the fluid. The flasks must be agitated in research. It is possible that the sludge from other Fort Environ-shakers. Finally computer controlled fer- McMurray operations could be used in the new plant. menters are used to complete the bacteria growth. helping to solve a disposal problem. The bacteria would Every 22 to 45 minutes a new generation of bacteria is consume minerals and nitrogen in the sludge as nutrients. born. By the time a centrifuge is employed to collect the bacterial paste, there are approximately 10 to 12 Worne feels the move from pilot plant to commercial trillion bugs per gram. The bacteria can be stabilized operation would take another year. A favorable energy for storage or freeze dried. Sale prices range from $8 to balance of three to one for the entire mining and $10 per pound, and one pound treats a tremendous separation process could be achieved. The oil recovery amount of media. rate would be approximatel y 70 percent to 80 percent. Present methods of treating the oil sands involve adding Although the present bacteria process leaves the chemi- the bacteria to a tank of agitated water. Oil sands are cal structure of the petroleum essentially unaltered, mixed in and air is pumped into the tank. Because the bacteria may be used in the future to break down heavy process is aerobic, no odors are formed. Sulfur stays in oils into less viscous oils. Some oil fractions would be solution. Under commercial operation, water pressure is released, with an actual loss of no more than 15 percent. expected to replace the use of agitation. The rapid release of the oil from the sands would remain the same. Worne Biochemicals is now open to cooperative ventures. After oil separation, the bacteria are unable to consume A larger bug plant is planned for 1981. and Worne hopes much oil. to build a biochemical plant in Canada in the future. If the use of these plentiful non-pathogenic microorganisms Additional claims are that the entire procedure involves can be perfected, it may provide an efficient method to a loss of less than 10 percent of the petroleum. It takes utilize our presently untapped resources. place under ambient temperatures and ambient pressure above freezing. It is pollution free, producing no toxic or caustic substances. All the bacteria and fungi that are used are totally pathogen free, and cannot cause disease in humans, animals or plants. The spent bacteria

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 3-17 SYNCRUDE EXPLORES HEAVY METAL RECOVERY with a typical analysis of 57 percent Ti0 2 . 19 percent Fe 03' 4 percent AI 2O q and 5 percent Zr; and a zircon L.W. Trevoy and R. Schutte authored a paper, "A New concentrate which analyzed 39 percent Zr. 4 percent Source of Heavy Minerals from Canadian Oil Sands Ti02 , 3 percent Fee20 3 and 8 percent Al203. Mining Operation' which was presented at the AIME Annual Meeting on February 22-26, 1981 in Chicago, The zircon concentrate, from the pilot plant separation Illinois. The results of a research program conducted by work, was shown to contain 56 percent heavy minerals by Syncrude Canada, Ltd. were given. sink-float analysis with meth ylene iodine, and thus required further upgrading. Gravity, magnetic and high- Titanium and zirconium heavy minerals occur in the tension cleaning was used to produce a high quality 98 tailings stream from processing plants which use the hot percent zircon product. In general, the tests concluded water extraction process for recovery of bitumen from that the zircon in the Fort McMurray tar sand deposits is tar sand. The overall objective of the program on heavy of high quality and relatively free from inclusions. The minerals was to conduct a laboratory study on a scale titanium minerals concentrate was found to contain which would permit evaluation of each step in the small quantities of Mn, Cr. Mg, Ca, Na and 1< (0.1 to 0.5 processing sequence, so that recovery efficiencies would percent concentration range) and, by sink-float analysis he established. The evaluation progressed from cleanup with methylene iodine, was shown to consist of approxi- of crude tailings through to the upgrading stages using mately 99.2 percent heavy minerals. The Syncrude specific gravity, high-tension electrostatic and magnetic ilmenite was observed to be highly weathered (altered) separation techniques. and contained a relatively high ratio of titanium dioxide to iron oxide (Ti0 2/Fe203 = 2.8). Bitumen, after extraction, is diluted with naphtha and is fed to-centrifuges-to remove coarse entrained solids. The Syncrude titanium minerals should provide a desir- The combined first and second stage tailings from the - able fdedstock for thechloride process ofTiO --manufac- dilution centrifuging plant typically contained 7 percent ture, which (1) prefers a low ratio of Fe to 2Fi, (2) can titanium and 2 percent zirconium. accommodate higher levels of impurities such as Cr, (3) is a more acceptable process based on capital cost of In order to provide free flowing minerals as feed to facilities and also (4) is more desirable in view of the subsequent processing steps, it was necessary to remove environmental regulations related to the disposal of the hydrocarbons associated with the tailings. Three plant wastes (chlorine can be recycled). approaches were considered: (I) burnoff involving cracking and oxidation of the hydrocarbon residues, (2) appli- A further processing option is the upgrading of Synerude cation of surfactants to assist in washing the tailings titanium minerals to synthetic rutile via chemical free of hydrocarbon contaminants, and (3) solvent removal of iron oxide. Synthetic rutile is a preferred extraction. In tests conducted with 19 surfactant formu- feedstock for Ti0 2 pigment manufacture via the chloride lations, removal of bitumen was incomplete in all tests. process. With solvent extraction, solvent loss is a major consideration. The present work chiefly involved burnoff of Heavy minerals distribution in tar sand drilling core scroll tailings in a fluidized bed reactor, 6 inches in samples has been evaluated for various locations on diameter. Syncrude Lease 17, plant tailings streams have been analyzed in 1979 and 1980 for titanium and zirconium Maximum reaction temperatures ranged from 500 9C to content, and expected annual production levels of heavy 800°C. To meet safety requirements, burnoff was con- minerals have been estimated. Average analysis for a ducted in two stages: (I) thermal cracking under nitro- single drill core (14 samples) in terms of floated minerals gen, and (2) oxidation with an air/nitrogen mixture. The was 8.4 percent iron, 7.1 percent titanium and 2.5 majority of the valuable heavy minerals in scrollscroll tailings percent zirconium. Based upon a plant production rate are found in the +325 mesh screen fractions. In burning of 105,000 barrels per day of synthetic crude oil, tailings off scroll tailings, some fines (-325 mesh particles) were from the centrifuge plant would contain 26,000 tonnes carried overhead and were thus removed, reducing total per year of zircon and 114,000 tonnes per year of fines (-325 mesh) from 42 to 23 percent. Hydroclones titanium minerals. With an 85 percent recovery effi- further reduced fines to 6 percent. Using a Humphreys ciency for zircon and 75 percent recovery of titanium 3-spiral circuit reduced coarse, low gravity solids (+100 minerals, annual production rates would be: mesh) from 32 percent to 5 percent. Typically, the product from the three stage spiral circuit consisted of Zircon —22,000 tonnes per year solids of which 86 percent were in the -100 to #325 mesh Titanium Minerals - 85,000 tonnes per year. size range.Recovery of titanium was close to 80 percent and recovery of zirconium was better than 90 By debottlenecking the Syncrude plant to produce percent in the 3-spiral circuit. 129,000 barrels per day of synthetic crude oil and if tailings from Syncrude and Suncor plants were processed A Carpo "Research Model" high-tension separator was together in a single minerals plant, the production to used to investigate the separation of titanium and zir- yield 44,000 tonnes per year of zircon and 170,000 tonnes conium minerals. The feed was Humphre ys spiral fini- per year of titanium minerals. sher concentrate, which contained approximately 19 percent Ti, 8 percent Zr, 8 percent Fe and 4 percent Al. Some of the commercial products which could be pro-- Using two stages of high-tension and recycle of mid- duced from Syncrude heavy minerals are shown in Figure dlings and tailings from the second stage, two concen- 1. The production of two mineral products, zircon and a trates were obtained: a titanium minerals concentrate titanium minerals concentrate, could be considered ii-

3-18 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981

CRUDE CENTRIFUGE TAILINGS SOLIDS

640 K TONNES/YEAR

ZIRCON TITANIUM MINERALS K TON/YR IS K TONNES

I- * ______I ILMENITE LEUCOXENE RUTILE I I 40K TONHE/YR. 36 K TWiNE/YR. 10K TONHI

I SYNTHETIC I TITANIUM RUTILC L ._—aJ I 56KTDNNES1YRI METAL

ZIRCONIUM METAL TITANIUM DIOXIDE PIGMENT SI K TONNES/YR.

FIGURE I COMMERCIAL PRODUCTS FROM SYNCRUDE HEAVY MINERALS

tially. By the use of magnetic separators, the titanium minerals concentrate could be further subdivided into three products: ilmenite (60 percent Ti0 2 ), leucoxene (80 percent Ti02) and rutile (95 percent Ti02). A market study was conducted in 1980 to surve y potential markets for zircon and titanium minerals from the Athabasca oil sands which will become available after 1984. With the possibility that several additional open pit tar sand mining operations will be started up in Alberta to meet our energy needs in this decade, it follows that a very considerable source of heavy mineral raw materials will become available to meet a continuing world demand for zircon and titanium minerals.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-19 LAND

THE U.S. GETS ANOTHER CHANCE TO ADOPT to draw the distinction required by the Solicitor's opinion COMBINE!) HYDROCARBON LEASING in advance of well completion, the Bureau of Land Management imposed a moratorium on Section 21 tar Once again, efforts are underway to promote tar sand sands leasing late in 1965. The moratorium and the leasing through legislation. Two bills have been intro- controversy over the rights of oil and gas lessees have duced into the House, HR3114 by Rep. James Santini (D- continued to the present, although the Department Nev.)and 11R3092 by Rep. Dan Marriott (R-Utah), which announced in August 1980, its intention to resume tar are essentiall y the same in their provisions, advocating sand leasing on a limited basis. combined hydrocarbon leasing. The Department of Interior has not yet taken a position on the proposed Proposed Legislation Advocates Joint Hydrocarbon Lease bills, but is expected to lend support, as it has done with previous legislation attempts. The primary thrust of the proposed legislation is to eliminate the need for the Department of Interior to Background To Tar Sand Leasing Reviewed distinguish between oil and tar sands b y establishing a system for issuing combined hydr ocarbon leases. The Prior to 1960, tar sands was a locatable mineral under idea has been proposed before, but for various reasons the Mining Law of 1872. which meant that a person could has failed, (refer to an article on page 3-30 of the locate •a mineral deposit, perform annual assessment December 1980 Cameron Synthetic Fuels Report for work, and eventually receive a patent. The Mineral additional -information). - The State of Utah has adopted Leasing Act of Februar y 25, 1920, effected a complete the combined leasing concept for State Resources. Bills change of policy with regard to the disposition of lands H.lL31 14 and ll.R.3092. as introduced, provide for the containing deposits of coal, phosphate, sodium, oil, oil following significant changes: shale, and gas. Thereafter, deposits of these designated minerals were no tonger open to location and acquisition 1. Mandatory conversion of existing oil and gas of title, but only to leasing. The law exempted existing leases to combined hydrocarbon leases upon valid claims that were thereafter maintained in com- filing of acceptable plan of operations, etc., pliance with the lows under which they were initiated. 2. Five-year primary term for converted lease, By enacting the Mineral Leasing Act Revision of 1960. 30 U.S.C. §241, Congress added deposits of "natural 3. 124 percent royalty rate under converted asphalt, solid and semi-solid bitumen, and bituminous lease, rock (including oil-impregnated rock or sands from which oil is recoverable only by special treatment after the 4. Special lease provisions for combined hydro- deposit is mined or quarried)," to the list of leasable carbon leases issued in "designated tar sand minerals under Section 21 of the Act. Shortly after the areas": enactment of the amendment and the issuance of a limited number of competitive tar sand leases, a contro- 124 percent royalty rate that may be versy arose concerning how to differentiate between reviewed for possible reduction, suspen- substances covered by Section 21 of the Act and Section sion or waiver by Secretary prior to 17, which provides for the leasing of oil and gas deposits. commercial operations. In a memorandum dated February 25, 1965. the Five-year extension of primary term Associate Solicitor, Division of Public Lands, Depart- where lessee is diligently pursuing an ment of the Interior, reviewed the issue and took the approved plan of operations, etc., and view that the distinguishing feature is whether the oil occurs in a fluid or gaseous condition in the ground. in Maximum lease size of 5,120 acres. which case it is oil, or whether it occurs in a solid or semi-solid condition, in which ease it is a tar sand. 5. Competitive leasing of unleased lands within According to a 1975 U.S.G.S. study, the mobility issue designated tar sand areas, turns on whether the substance initially flows to the well bore of its own natural force without stimulation by a 6. Designation as tar sand areas of 11 areas secondary recovery technique. If the substance can be previously identified by Interior as such, plus produced in the first stage without stimulation by secon- Secretarial discretion to designate additional dary recovery, then the Section 17 oil and gas lease areas identified "as containing substantial de- entitles the holder to extract the resource, but if initial posits of tar sand". production cannot be stimulated through primary means of recovery, the resource is a tar sand recoverable only 7. Inclusion of tar sands definition for the pur- under a Section 21 lease. However, the Department has pose only of Secretarial review of tar sand issued no formal decision on the matter. royalty rates. As a result of the Associate Solicitor's recommendation, 8. Secretarial discretion to lower aggregate and because it is technically impossible for the U.S.G.S. acreage limitations per State (currently

3:20 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 246.080 acres for Section 17 leases and 7.680 do not really limit the type of lease that may be acres for Section 21 leases) for leases in converted. Under the proposed broad requirements, designated tar sand areas, and Section 8 is an open invitation to competitive oil and gas lessees to convert to combined hydrocarbon leases as a 9. Tax disclaimer. way to reduce the applicable royalty rate from 16-2/3 percent to the 12+ percent rate which the bill would set Industr y is expected to support the bill provided certain for the converted lease. points of clarification are established: The bill also lacks provisions for the leasing of tar sands I. The combined leasing of tar sands will not in the situation where a current oil and gas lessee hinder oil and gas development, chooses not to convert to a combined hydrocarbon lease and is within a designated tar sand area. If the bill is 2. The redefining of oil to encompass tar sands adopted, all future leases and claims under Section 17 for the purpose of leasing will not alter would be issued as combined hydrocarbon leases, not just whatever distinction may have existed be- those issued in designated tar sand areas. Tar sand sites tween the two for federal tax purposes. caught in the interim would be unobtainable. 3. Companies/Individuals who currently hold Since all future leases would be issued as combined neither oil and gas leases or mining claims in hydrocarbon leases, and current oil and gas leases have a tar sand areas will not be unreasonabl y pre- primary term of ten years, it would be desirable for all cluded from obtaining tar sand leases, new combined hydrocarbon leases to have a ten-year primary term. 4. The special provisions for a designated tar sand area (DTSA) do not automatically apply There has been concern that a party having the maxi- to any DTSA other than those existing 11 mum allowable oil and gas lease acreage would have to areas in Utah, relinquish some of his leases if he either converted them or acquired additional acreage for the purpose of tar 5. Lease acreage within a designated tar sand sand development. It has been suggested that the leased area is not chargeable against the 246,080- acreage in a designated tar sand area should not be acre acreage limitation per state currently included in the 246,080-acre per state oil and gas acre- applicable to federal oil and gas leases, age limitation for federal oil and gas leases. Concerning secretarial discretion to lower acreage limitation, it has 6. The requirement to file for conversion within been suggested that the section be redrafted to impose a two years of enactment of the legislation is ceiling on the acreage any one company may hold under clarified to deal with the situation where a a combined hydrocarbon lease within the aggregate of all lease expires before the two year period has the designated tar sand areas. However, this could force run, a party having all oil and gas lease acreage in tar sand areas to relinquish holdings if they were converted. 8. An environmental impact statement is not Several parties object to an arbitrary acreage ceiling on required under NEPA for either the conver- the grounds that the acreage needed for a viable project sion program or field testing under a com- will depend on the qualit y of the resource, location, bined hydrocarbon lease, and technology , etc., and should not be determined except on a ease by case basis. 9. The definition contained in the bill relating to royalty adjustments should be workable Although similar legislation to the proposed bills had no and compatible with a taxing/IRS definition. trouble passing through the House last year, it seems doubtful that any bill could be passed by both houses this Several additional provisions under the proposed bill will year without unanimous industry support, and that will require clarification. The bill allows for the conversion only happen if the aforementioned areas of concern are of valid mining claims, but does not define the criteria settled. for determining validity. In addition, it does not specifically require holders of mining claims desiring conversion to file a plan of operations within two years, as is required by an oil and gas lessee. GEOLOGY OF MANVILLE HYDROCARBON RESERVOIRS PUBLISHED The bill provides that for leases in designated tar sand areas, the royalt y shall be "124 per centum in amount or The Saskatchewan Geological Society hosted a Con- value of production removed or sold from the lease." It ference and Core Seminar in Regina on October 15-17, is unclear in cases where production is upgraded on site, 1980 and the proceedings are contained in Special Publi- whether the royalt y applies to the product before or cation No. 5. The publication, "Llo ydminister and Be- after is is upgraded. yond: Hydrocarbon Reservoirs." provides o good reference for determining the current state of geological It was the intent of the drafters to limit leases eligible knowledge about the Llo ydminister area and its heavy oil for conversion to those which contemplate the develop- deposits. The title and authors for each paper included ment of those resources which must be developed pur- in the special publication are given below: suant to enhanced recovery techniques or mining. How- ever. the prescribed contents of the plan of operations

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-21 EARLY CRETACEOUS PALEOGEOGRAPHY IN THE ALBERTA FOOTHILLS AND ADJA- CENT PLAINS J.R. McLean and J.H. Hall

THE LOWER CRETACEOUS MANNVILLE GROUP OF SASKATCHEWAN - A TEC- TONIC OVER-VIEW J.W. Christopher

. MANN VILLE CHANNELS IN EAST- CENTRAL ALBERTA Antoine A. Gross

. HEAVY OIL OCCURRENCES OF THE CAC- TUS LAKE AREA SASKATCHEWAN Daniel Dueharme and David L. Murray

S LOWER CRETACEOUS (MANNVILLE GROUP) GRAND RAPIDS FORMATION, WABASCA A OIL SAND DEPOSIT AREA, NORTHEAST ALBERTA - - - - R.G. Keeler

• THE FREEMONT FIELD: AN EXPLORA- TION MODEL FOR THE LLOYDMINSTER AREA N.E. Dunning, H.J. Henley and A.G. Lange

• GEOLOGY OF THE FORTY ACRE ABER- FELDY STEAM PILOT H.J. Maceagno and M.D. Watson

S THE SPARKY SAND TREND AND IT'S PER- FORMANCE IN THE DULWICH - SILVER- DALE AREA OF WEST-CENTRAL SASKAT- CHEWAN Robert D. Robson

• FLUVIAL DEPOSITION WITHIN THE UPPER MANNVILLE OF WEST-CENTRAL SASKAT- CHEWAN: STRATIGRAPHIC IMPLICATIONS P.E. Putnam

• UPPER MANNVILLF. FLUVIAL CHANNELS IN EAST-CENTRAL ALBERTA Barbara J. Tilley and William M. Last

• CORRELATION OF LITHOFACIES AND LITHOSTRATIGRAPUIC UNITS IN THE MANNVILLE GROUP. LLOYDMINISTER AREA, SASKATCHEWAN Francis Haidi

• GEOLOGY OF AN IN SITU PILOT PROJECT. WABASCA OIL SANDS DEPOSIT, ALBERTA T.R. Lennox and M.M. Lerand

• GEOMETRY OF NEARSHORE SAND BODIES IN THE UPPER MANNVILLE GROUP, CEL- TIC FIELD, SASKATCHEWAN J.A. Lorsong

3-22 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 ECONOMICS

INDUCTION HEATING SHOWS ECONOMIC POTENTIAL The bitumen upgrading process requires 1,000 cf of hydrogen per barrel of synthetic crude. This is obtained In the paper "Solid Fossil Fuel Recovery Processes from natural gas. The upgrading aim is to produce crude Compared," Sidney Fisher develops a basis for economic which can be processed in existing refineries. This aim evaluation of the induction heating method. The pro- has yet to be realized, however, and the synthetic crude posed induction method involves drilling shafts and oils are eventually expected to require special refineries. tunnels through the solid fuel. Electrical conductors are When these refineries are established, it seems likely threaded through these openings to form a coil which that the bitumen upgrading process will aim at producing may be a kilometer or more in extent. A large low- only a pumpable liquid. A yield of 0.63 barrel of frequency alternating current is passed through the coil synthetic crude per barrel of bitumen was used. to set up a magnetic field within the fuel. This field induces eddy currents in the electrically dissipating Based on the factors given in Table 1, a total cost of materials which form the fuel beds. The bed's conduc- $25.90 per barrel was determined for the mining and tivity is raised several orders of magnitude by injecting a surface processing option. A total cost of $8.88 was saline aqueous solution from the surface. The fuel is calculated for induction heating of oil sand in situ. heated by the eddy currents. Some portion of its energy content can then be brought to the surface in the form Parameters for Heavy Oil Costs are Discussed of gaseous hydrocarbons, steam and hot gases to be utilized in conventional ways. About 75 billion barrels of heavy oil were considered recoverable by the in situ process based on underground The advantages of in situ induction heating include the injection of steam to raise the temperatures and reduce possibility of utilizing greater portions of solid fossil fuel the viscosity of the oil. This steam is partly raised by deposits, whether layered, low-grade, diffused, deep, burning one ton of coal/SO bbl of synthetic crude. Coal wet, fractured, under valuable land or towns, or other- is shipped to the heavy oil site from a separate surface wise unsuited for conventional exploitation. It also mine. This option results in considerable environmental offers the possibility of reducing surface disturbance, impact, since the open coal mines would be large. atmospheric pollution, and interference with surface and sub-surface aquifers. Heavy oil upgrading was assumed to be similar to bitumen upgrading. A hydrogen requirement of 1,000 scf/bbl In order to compare induction heating to other in situ of synthetic crude was used. Since the product is also and aboveground techniques, certain assumptions were likely to require special refineries, the upgrading aim made. At the present time, experimental work has been could be changed to produce only a punipable liquid. done at room temperature and atmospheric pressure to measure the electrical dissipation factors of oil sand. Water use was assumed to be 4.2 barrels per barrel of Further work is now proposed. It includes the series of product, although it could be much higher. A yield of surface and in situ heating trials necessary to establish 0.26 barrel of synthetic crude per barrel of heavy oil in the validity of the technical assumptions which have place was also applied. The cost of the product was been made concerning properties at formation pressures calculated to be $22.60 per barrel, without taxes, royal- and process temperatures. ties, leases, profits, cost of heavy oil, or contingencics.

Much of the information for the proposed processes is The use of the induction-heating technique is likely to still speculative. However, the information available has bring several advantages. At least twice the resource been organized in such a way that direct comparison of a base is available. Also, the yield will be much greater. number of parameters of each of the processes can be due to the higher temperature used, about 85 percent in made. These projected costs form the basis for a place of 26 percent. The capital cost of the installation comparison that indicates strong economic potential for is also much less. Induction heating of heavy oil in situ an eddy current, induction-heating approach to recovery could use purchased coal. and use of solid fossil fuels, Table I gives the parameters and results of the economic comparison for Oil As a result, the cost/bbl of synthetic crude is estimated Sands and Heavy Oil, at $12.30. This includes the purchase of mined coal but not the cost of the heavy oil. Oil Sands Cost Parameters are Given The results of this study indicate a strong economic The mining of the oil sand, and its transportation before potential for an eddy current, induction heating approach and after separation, represent a large, energy-intensive to oil sand and heavy oil recovery. However, much of operation, which must continue through Canada's ex- the available cost data is tentative and has been based tremes of temperature. About 2.3 tons of oil sand are for the most part on small test programs. mined to produce 1 bbl of synthetic crude. In addition, about 1.4 tons of overburden must be moved and restored. Initially, the projects require 10.4 bbl of water/barrel of oil produced. This figure is estimated to drop to 4.6 bbl in the fourth full year of operation.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-23 TABLE I INDUCTION HEATING PROCESS COMPARISON

Surface mining. Induction heating Steam injection Induction heating Process: separation of oil of oil sand recovery of of heavy oil insitu sand*** in situ"" heavy oil using purchased in situ using coal purchased coal

Total recoverable resource 100 billion bbl I trillion bbl 75 billion bbl 150 billion bbl bitumen bitumen heavy oil heavy oil Product Synthetic crude Synthetic crude Synthetic crude Synthetic crude Yield/unit. bbl/bbl 0.63 0.5 0.26 0.85 Daily yie ld. bbl/bbl 140.000 140,000 140.000 140,000 Operating days/yr 250 360 350 350 Annual yield, 10 6 bbl 35 50.4 49 49 Lifetime of total resource, yr. 2.860 16.000 397 2,600 Capital cost, $ billion 4.16 2462 5.95 2.02 Operating cost, $ billion/yr 0.28 0.22 0.297 0.30 Interest cost. $ billion/yr 0.626_ - - 0.40 - - 0.81 0.303 Total cost. $ hillion/vr 0.906 0.62 1.107 04601 - Cost/bbl. $ 25.90 8.88 22.60 12.30 Water use. bbl/bbl of product 4.6-10.4 Low 4.2 Low b/d 0.65-1.4 million Low 590.000 Low bbl/yr 162.5-352.5 million Low 206 million Low Sulfur dioxide emission High Low High High Other pollution High Low High High Environmental damage High Low High High In situ operation No Yes Partly Partly *In the case of most systems, all the capital cost is incurred over a period of 3 to 5 years, before production begins. For induction heating, only about half the capital cost is incurred in this 3 to 5 year period. The other half extends over the 40- year life of the project. This is not reflected in the estimates.

"Does not include taxes, leases, royalties, profits, cost of in situ fuel, or contingencies. Efficiency of conversion of thermal content of coke to electricity assumed 50 percent. If relatively low capital cost of induction heating is amortized in 10 years product cost drops to about $3. 65/bbl. ***Based on published figures for surface mining and separation of oil sand. Figures for steam injection and induction heating are estimated ****Coal consumption is about 1.000 ton/hr, which allows about 20 percent coal waste. Of the electricity generated at the coal site. 25 percent is used for induction heating of the coal and 75 percent for induction heating of the oil sand.

3-24 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 U.S. BUREAU OF MINES COMPARES COSTS OF UNCONVENTIONAL MINING METHODS Underground drainage systems are more environmentally compatible than surface mining, but they present poten- During fiscal year 1980, U.S Bureau of Mines research tial health and safety problems. A sectional view of a included unconventional mining methods. An "Assess- hypothetical underground drainage system for oil mining ment of Oil Mining' was included in the report, Bureau is given in Figure 1. Miners will be working in a of Mines Research 1980. This section contained cost potentially flammable, explosive atmosphere with toxic estimates for producing petroleum through underground gases. The rock strata in which oil is found are typically extractive systems, underground drainage systems, and weak, presenting ground controlproblems. Solutions to surface mining systems for appropriate oilfields in this these problems will be needed before underground oil country. Projected costs for underground extractive drainage operations can proceed safely. systems ranged from $40 to $75 per barrel in 1979 dollars, making these sytems infeasible even with today's inflated oil prices. Underground drainage systems were Projected to cost from $12 to $30 per barrel, making them very promising in light of toda y's world oil prices. Surface mining techniques were projected to cost from $18 to $27 per barrel.

Although the technical and economic prospects of both the underground drainage and surface oil mining systems appear excellent, more information is necessary on the environmental and health and safety hazards associated with these systems. With surface mining, the main problems are environmental. A Bureau contractor is currentl y designing mining and beneficiation s ystems for surface mining a tar sands deposit in Utah and for a specific heavy oil deposit in California. The environmental problems associated with these operations will be identified and quantified. Solutions to these problems and the cost of their implementation will be determined to see if surface oil mining can be done in an environmentally acceptable manner.

FIGURE I SECTIONAL VIEW OF A HYPOTHETICAL UNDERGROUND DRAINAGE SYSTEM FOR OIL MINING

CAMERON SYNTHETIC FUELS REPORT, JUNE 3981 3-25 FOREIGN

MANCYSHLAK OIL DEVELOPMENT IS DISCUSSED The question of water supply for the oblast has recently been raised with new acuteness. In the beginning of the Narodnoye Khozyaystvo Kazakhstana in Russian No. B. five-year plan, the fresh water needs of industry and August 1980, contained an article on Mangyshlak Fuel other branches of the economy were satisfied. Today, entitled "Stages in Formation and Growth." In the the situation has become significantly more complicated. article. V. Savehenko, secretary of the Mangyshlak A schedule for restricting the water supply has been Obkom of the Kazakhstan Communist Part y, discussed introduced in the settlements in the summer. the difficulties which have been encountered in developing newly discovered oil fields on the Buzaehi penninsula. The solutions to all of these problems must be worked Although the deposits are at a shallow depth (300-900 out in detail by the appropriate union ministries and will meters), the oil is highly viscous with a large content of require considerable material resources. The develop- resinous substances. Only a small portion of the avail- ment of the complex will be impaired considerably able reserve can be extracted by primary methods, and without their timely resolution. plans for enhanced recovery are underway. Current extraction plans include in situ steam stimulation and There are many unsolved problems in the development of deep-well wet combustion. Only experimental test the fishing and fish processing branch. On the one hand, sections are under construction and work is proceeding the main funds of the "Mangyshlakrybkholodflot" admini- slowly. - Much additional- technological experience is stration long ago became obsolete and worn out, while on required before operations can be expanded to the entire the other hand, -there are free labor resources in the city I'(arazhanbas field. of Fort-Shevchenko. The time has come for complete reconstruction of this enterprise, and for the construc- In the Kalamkns field, it was decided to pump poly- tion of a new fish processing complex. However the fish aerylamide - thickened water into the reservoir bed. industry association "Kaspryba" of the USSR Ministry of However, the drilling of injection wells and their prepar- the Fish Industry is slow to solve these problems. ation for operations is still progressing slowly. These technological problems require a comprehensive solution Further development of the territorial-production com- on the part of the USSR Ministry of the Petroleum plex will cause an increase in the freight traffic that Industry. surpasses the potential capacity of the main Makat- Uzen' railroad. A large complex to reconstruct the One of the complicated problems in developing the repair base, plant and tracks has yet to be implemented territorial production complex is the inadequate energy and may involve the establishment of a Mangyshalk supply. All phases of resource development require department of the West Kazakhstan railroad. power, and in recent years development of power engineering has lagged behind the growth in industry and in The future of Mangyshlak's oil is linked extensively to the population of the oblast. the efforts to intensify geological exploration for oil, gas and other minerals. For this purpose, deep exploration The part y. Soviet, and economic agencies extensively should be done in the Pernotrias deposits. Although studied the situation concerning electricity supply for confident that part of the discovered fields are under the the developing complex. They have since taken steps to sea, the extent of oil content of the Caspian Sea shelf is assure efficient electricit y use and to begin construction not clearly known. The author also states that the time and introduction of new power engineering facilities. has come to refine part of the oil locally. This will serve Construction has begun on the Shevchenkovskiy GRES. as feedstock for plastic production and will stimulate The start-up of the first unit is planned for 1982. It is further development of the petrochemical industry. the responsibility of the Ministry of Power and Electrifi- cation to guarantee the timely delivery of equipment to this important facility according to the construction schedule. In order to keep up with the power demand, it USSR BALAKHANY OIL MINE DRILLING UNDERWAY will be necessary to accelerate construction of the next plant units. Plans are again underway for Azerbaijan's first underground mine for heavy oil recovery in the 100-year old The guaranteed, reliable operation of the electrical Balakhan y field near Baku. Late last year, the Soviet circuits and substations becomes especially important Union began drilling the initial vertical shaft, The and difficult in the sharp continental climate of Balakhany oil mine is designed to recover heavy oil from Mangyshlak, with its frequent dust storms. The an area of about 200 hectares (494 acres). Diameter of Mangyshiak enterprise of electrical circuits of the the bore is 6 m (19.7 ft). "Gur'evenergo" administration has been unable to meet this need. Oil losses in 1979, attributable to emergency Two vertical shafts will be put down, with large hori- cut-offs alone, were about 30,000 T. The Kazakh SSR zontal tunnels similar to drifts in coal mines connecting Ministr y of Power and Electrification apparently needs the shafts. Small diameter holes will be drilled upward to create a separate administration for the at various angles from these corridors into the pay Mangvshlakskaya oblast, or at least, to guarantee the zones. Viscous crude will flow downward by gravity into normal operation of the extant enterprise, and supple- storage tanks and then be pumped to the surface. ment it with equipment and personnel.

3-26 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Opening of the first underground oil mine in the Baku The Venezuelan government does intend to allow foreign area originally was slated for 1978. Plans called for entities to help the country solve its internal growth cumulative crude production by the end of 1980 to total related problems. In contrast, foreign firms will he used 70,000-75,000 metric tonnes (511,000-547,500 bbl). No in the exploitation of the Orinoco Belt and other areas new target date has been announced for activating the only when the needed technology does not exist in Balakhany oil mine. However, start-up appears unlikely Venezuela. Even then, the government will look more before 1982 or 1983. favorably to those companies who are willing to train and incorporate local workers. The Soviets are hoping for a slice of Venezuela's Orinoco Belt development. Their energy officials suggest a widening of an earlier PETROVEN POURS MONEY INTO OIL DEVELOPMENT cooperation agreement which would include involvement in heavy oil exploration and production at Orinoco and Venezuela intends to increase oil reserves and refining other areas. Several U.S. engineering and construction capacity through a multibillion dollar program which firms have already secured sizable contracts from Petro- includes large scale development of the Orinoco heavy yen to aid in the oil development program. Several oil belt. Investments in all aspects of the Venezuelan articles contained in this section summarize these con- industry amounted to $2 billion last year and will tracts. increase sharply throughout this decade. The program will be conducted by Petrobras de Venezuela S.A. (Petro- In another agreement, believed to be the first oil pur- y en), the government owned oil company, through Logo- chase agreement between a U.S. state and foreign oil en S.A., Maravcn S.A., Corpoven S.A. and Menoven producer. Massachusetts has agreed in principle to buy S.A., the four operating companies of Petroven. residual fuel oil from Petroleos de Venezuela S.A. The deal calls for a Petroleos subsidiary to supply Massachu- Petroven's spending program will require a total of about setts utilities and other industrial users with up to 8 $25 billion during the next six years. About $5 billion million barrels of oil a year. or about 8.5 percent of their per year in 1980 dollars will be needed during 1986-2000. total fuel needs. Buyers would pay about 5 percent Oil accounts for 90 percent of Venezuela's foreign ex- below the going rate for residual fuel because of the change, 25 percent of its gross national product, and Venezuelan oil high sulfur content. more than 75 percent of government revenue. Vene- zuela's oil revenues amounted to $19 million during 1980. Nationalized since the start of 1976, the Venezuelan oil industry estimated reserves at 18.33 billion barrels at CORPOVEN IMPROVES PROCESSING CAPABILITY the start of 1980 and produced nearly 790 million barrels during the year. By the end of 1980. the country's Corpoven, S.A., subsidiary of Petroleos de Venezuela. estimated o ilreserves had risen to 19.524 billion barrels. S.A., has been actively working to increase output of refined products from Venezuela's heavy oil. The gaso- The oil industry growth has not taken place without line project at Corpoven's El Palito refiner y on the coast causing a mixed impact on the Venezuelan economy. of the state of Carabobo is scheduled for completion in The industry has brought higher wages, more jobs, and September 1981. Capacity of the 105,000 bid refinery the highest gross national product per capita on the won't change as a result, but the product pattern cer- continent, especially since the 1973 oil-price increase by tainly will. Gasoline output will go up from 17,000 bid OPEC. To some neighboring countries. Venezuela took now to 77.000 b/d after completion. Natural gasoline, to on an image as the rich, open-doors neighbor to the be brought into the refinery at the rate of 17.000 b/d. north. Venezuela now must contend with the domestic will help boost the yield. But the major effect will come servants, the unskilled laborers, the lower-paid farm and from a new 42.000 b/d fluid catalytic cracker and a factory workers from other South American countries, 72.000 b/d HF alkylation unit. UOP licensed and especially Colombia, who came in through the "green designed these two units. They will produce enough highways" of the long Venezuelan border to take advant- octane so that lead usage can be cut from 3 to about I age of Venezuela's oil-swollen economy. Venezuela cc/gal. Demand will dictate the ratio of gasoline grades initiated a campaign to count and register the immi- produced. It appears that will he 65 percent of 83 RON. grants living inside its borders, but without success. 30 percent of 95 RON. and 5 percent of 74 RON. Estimates as high as 3 million illegal immigrants had been voiced, but perhaps only .5 million can be A 66,500 b/d vacuum unit is also going in. Residual accounted for by officials. output. as a result of the program, will droo from 60,000 bid to 29,000 bid. However, the future resid will have n Either estimate represents a significant portion of the viscosity 71 times higher than the current material (200 total population of approximately 16 million people. 5SF at 122' F). This product will be piped to a nearby Despite the wealth pouring into the country, it is not electricity generating station. well distributed and 30 percent of the people still live below the poverty level. The cities are comprised of Further facilities in the refinery project are a 40 mega- extreme affluence side-by-side with extreme poverty. watt electricity generating unit and steam generating Transportation has presented one of the biggest prob- plant to make 900,000 lb/hr. The complex will he lems. Gasoline costs about 30 cents a gallon and this, controlled with a Honeywell TDC 2000 s ystem. Plans coupled with a massive increase in ear ownership. has don't, at present, call for closing the loop. Foster rendered the roadway system vastly inadequate. The Wheeler is doing the engineering, procurement, and cons- people have used their wealth to purchase possessions truction for most of the project at an estimated cost of and travel, but little has been applied to improving their $430 million. own public related services.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-27 UOP Aurabon Process is Under Consideration roughly about 25.000 bid each. The asphalt fraction will be split and burned as plant fuel and fed to a partial Corpoven may also add a 2.500 barrel per day demon- oxidation unit for hydrogen production. Hydrogen re- stration unit of UOP's Aurabon process to its Bajo quirement will be quite high at the refinery in 1985. Grande refinery. Feedstock to the unit would he vacuum resid from 10° API l3osean Crude. Cardon Refiner y to Add Demetalizing Capabilities UOP says that a fully integrated pilot operation reduced In another effort Maraven plans to add a hydrodc- the 1484 ppm vanadium in Boscan topped (not vacuum metalizing facility to the Carden refinery. That unit distilled) crude to 54 ppm in the 568° +C portion of the will also take Tiajuana-heavy vacuum resid and asphalt. product. Total C 6+ yield amounted to 99.8 volume It will be designed for vacuum resids of the maximum percent. The yield of 343° i-C product was 89.2 volume viscosity possible using Shell Internationale Petroleum. percent. M.13.V. technology. Petrolcos Venezuela S.A. needs a resid upgrading route Basicall y, the process is for metal removal, which then for Roscan crude because there is no outlet for such permits the product to be processed conventionally. The material. In contrast to the Orinoco oil belt, Boscan objective is to get the 800 ppm metals in Tiajuana heavy producing formations are too deep for steam stimulation. resid down to 150 ppm. The process will also perform Therefore, the resid could not find an economic outlet in some dcsulfurization and conversion. The residue will steam generation as it could in the Orinoco oil belt. have a sulfur content of 1.2 to 1.3 wt percent. The unit will employ Shell's "bunker" reactor concept, with inter- ## ## mittent catalyst withdrawal and addition. However, it employs new concepts, which were researched in cooper- MARAVEN MODERNIZES CARDON REFINERY - atioii with Maraven. - - - - Venezuela's Maraven S.A., a Petroven Operating Com- The unit will utilize a new regeneration catalyst pany. plans to utilize innovative technology at its Carden developed by Shell. The catalyst for the test was made refinery at Funto Fijo. With the completion of its cat in Germany. cracker and previously existing visbreaking capacity. Carden now has the highest conversion level of any A series of reactors will be employed by the commercial refinery in the Venezuelan circuit. Heavy fuel oil yield version with the first serving as demetalization cham- is only about 37 percent. bers: the following ones for desulfurization and limited conversion. Details on the demonstration unit have not The refinery processes normall y 210,000 to 220.000 bid been released. The semi-commercial plant will handle of light crude with a gravity of 30° API and onl y some 400-metric tonnes per day of short residue. 30.000 hid of 12° API. The majorityf o the crude processed is Lagotreco t ype crude (31.8° API. 1.2 wt Two Fluor Corp. subsidiaries have won contracts totaling percent sulfur). Lagocinco (34.4° API and 1.19 wt $10 million for work on the Venezuelan project. Fluor percent sulfur) is run for Tube oil. The remaining and Nederland BV is performing engineering and design work, smallest (about 30.000 bid) fraction is Tiajuana Pesado while construction coordination services in Venezuela (heavy) with a gravity of 12.0 and sulfur content of 2.66 will be undertaken by Fluorven Ltd. wt percent. It is used to make reconstituted crude by the addition of naphtha for export. This troublesome crude will become the total charge to a IJAGOVEN UNDERTAKES MAJOR PROJECTS TO facility to convert it into diesel and other products. A INCREASE ORINOCO BELT PRODUCTION 100.000 barrel per day train to refine this crude will he added to the 330,000 barrel per day refinery. The Combustion Engineering Inc.'s C-E Lummus unit was facility will include atmospheric distillation, high awarded a contract with an estimated value of $700 vacuum distillation, deasphalting. hydrotreatment (for million to assist Lagoven with a major crude oil upgrad- metals removal), hydrocracking. and partial oxidation. ing project. Lagoven is the largest operating unit of The first units could be on line in [985. A 19,400 barrel Petroleos de Venezuela. S.A.. the Republic of per day alkylation unit and a 12.000 barrel per day Venezuela's Government-owned oil company. The $8 butane isomerization unit are underway. UOP design billion oil development project is located in Eastern will be used and Davy McKee is the contractor. The Venezuela. and is in support of the Development of the estimated cost is $126 million. Southern Managas and Anzoatequi regions. The project involves upgrading low gravity crude (8° API) available The scheme calls for the deasphaited Tiajuana-heavy from the Orinoco Heavy Oil Belt, to an export grade vacuum resid to be hvdrotreated with a catalyst with a upgraded crude. Work on the project is expected to high metals uptake capacity because the deasphalted oil begin in 1983. By 1988, the project is scheduled to be (DAO) will have a high metals content. But the hydro- able to produce 125,000 barrels of oil daily. treatment will not be as severe as that required for resid desulfurization. At 43 wt percent deasphalted oil yield Lummus will act on Lagoven's behalf as project coordi- on the vacuum resid. the DAO will contain from 70 to 75 nator for the engineering, procurement, and construction ppm metals. The treated DAO and vacuum gas oil will of the facilities. The project will involve several major then, be sent to a hydroeracker to make maximum diesel. areas: crude oil production, crude oil upgrading, pipe- The hydrocraeker will probably consist of two trains of line. terminal, construction support facilities, and the

3-28 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 necessary infrastructure. The process facilities will Another unusual as pect of the Flexicoker is its produc- consist of two crude units, two delayed eokers, gas tion of low calorie gas (110 Rtu/sef). The gas produced plants, hydrotreaters, hydrogen plants, a sulfur plant. has a heating value equivalent of 7,400 b/d of fuel oil. acid gas removal, and full environmental control units. This necessitates the construction of new boiler furnaces to burn the gas. New furnaces required, such as those The project has been assigned to Lummus' Bloomfield, for the eat cracker, will also fire this fuel. Another New Jersey Operating Division. Lummus will be associ- change in operations will be dictated by the fluid cataly- ated with Vepica, a Venezuelan engineering company, tic cracker. which will actively participate in the project. A considerable amount of engineering and all the construction Currently, the Gofiners desulfurize a 50/50 blend of light on this job will be done in Venezuela by Venezuelan and heavy vacuum gas oil. These units will lose all the engineering and construction companies. Lummus plans light vacuum gas oil to the cat cracker when it goes on to try not only to maximize Venezuelan participation line. This means the feed to the hydrodesulfurizer will (about 60 percent of total work), but will also take all be heavy vacuum gas oil, heavy coker gas oil, and the steps to insure training of a substantial number of intermediate catalytic cycle oil—a much heavier blend. Venezuelan engineers. Hydrogen demand for some of these streams will be almost three times higher. Lagoven Continues Work on Amua y Refinery Lagoven's refining department has overall responsibility In the late 1960's Creole Petroleum Corp. enlarged the for the Amuay upgrading. Fluor is the prime contractor Amuny refinery to make it the world's largest at that and is working under a $986 million fixed-fee. reimburs- time and added an advanced fuel oil desulfurization ible contract covering detailed engineering, procure- com plex. After that, impending nationalization, ment. and construction. The completed project will followed in the mid-1979's by a slumping demand, put a require 16 million construction man hours and 6,000 damper on activity for most of the decade. Since then, workers will be needed when the project peaks. About the new owner. Lagoven S.A.. has undertaken a complete 2.2 million hours of engineering will be required. A overhaul of the refineries capabilities. fixed-fee reimbursable contract was signed to accelerate project execution. Project completion has top priority. After completion, during a typical operation when runn- It's estimated that the Flexicracker. alkylation unit and ing 450,000 bid of crude, the refinery can increase its the isomerization unit will be on line the last quarter of throughput of heavy and extra heavy crude from only 1981; the Flexieoker during the first quarter of 1982. 98,000 bid now to 200.000 bid. or from 22 percent of charge to 44 percent. Yet the yield of gasoline and Venezuelan participation in all aspects of the project is distillate from this operation will climb from a current being stressed. About 40 percent of the procurement is 67,000 bid to 130,000 bi(, But high-sulfur fuel oil make of Venezuelan content. Venezuelan subcontractors have will decline from 200.000 bid to 111,000 bid. The also been involved, to the maximum extent possible, in primary units going in to accomplish this are a 46.800 engineering and construction. b/d Flexicoker, a 70,500 bid Flexicrackcr (FCC), a 13,400 bid alkylation unit, and a 4.700 bid butane UOP and Exxon Research & Engineering had early design isomerization unit. The project also includes extensive functions. The butane isomerization and alkylation units application of closed loop digital control and facilities to are licensed by UOP. while ER&E licensed the fluid burn the low heating value Flexicoker gas as plant fuel. catalytic cracker and Flexicoker. Lagoven engineers, who will start up and operate the units, have also In addition, a complete upgrading and modernization of participated in the design. the refinery's oil movements system is proceeding. Oil movements at Amuay includethe distribution of crude An extensive Fluor training and retraining program of brought in for processing and export, and the blending craftsmen and laborers is going ahead. Over 2.000 and shipping of products. The project includes construc- workers have learned basic skills such as carpentry, tion of a new control-center building, installation of a heav y machinery operation, and instrumentation. As the computer system, remote terminals, and new storage. need for a certain skill diminishes, the workers are The new units, will change operations considerably. retrained. The operators and engineers to start up and Vacuum resid now goes to fuel oil and asphalt. Much of run the new units are also involved in rigorous training it in the future will go to the Flexieokcr. The feed to programs in Venezuela and abroad. the Flexicoker will have the following basic characteristics:

Specific gravity - 1.042 Conradson carbon No. - 20.5 Sulfur - 3.5 wt percent It will also contain an astonishing 708 ppm vanadium and 163 ppm nickel. The some 100 ton/day of coke the Flexicoker makes will contain vanadium in the order of 7 wt percent. When separated, this amount of vanadium on a daily basis would make up 10 percent of world dem and.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-29 STATUS OF OIL SANDS PROJECTS INDEX OF COMPANY INTERESTS

Company or Organization Project Name Page

Aarian Development, Inc. A.D.I. Chemical Extraction 3-34 Alberta Energy Company Ipiatik Lake Project 3-39 Suffield Heavy Oil Pilot 3-43 S y nerude Canada, Ltd...... 3-34 Alberta, Province of Syncrude Canada, Ltd...... 3-34 Alminex, Ltd. Sandalta ...... 3-43 Amoco Canada Ltd. Alsands Project Group ...... 3-33 Block One Project ...... 3-36 Peace River In Situ Pilot Project. 3-42 A OST R A Block One Project ...... 3-36 North Kinsella Heavy Oil Project. 3-41 Peace River In Situ Pilot Project. 3-42 Suffield Heavy Oil Pilot 3-43 Surmont Project ...... 3-43 Taciuk Process Pilot 3-4-4 Aquitaine Company of Canada Ltd. Huff-and-Puff Cold Lake Project. 3-39 BarberHeavy Oil Process, Inc. Heavy Oil Process (HOP) Technology. 3-38 BP Exploration Canada Ltd. Cold Lake Pilot Project 3-37 Marguerite Lake Phase A Pilot Plant 3-40 C&A Companies MRL Solvent Process ...... 3-41 Canada Cities Service, Ltd. Eyehill In Situ Steam Project 3-38 Manatokan Project ...... 3-40 Mine Assisted In Situ Project 3-40 PCEJ Project 3-41 Synerude Canada, Ltd...... 3-34 CDC Oil and Gas. Ltd. Athabasca In Situ Pilot Project 3-35 Chanslor Western Oil & Development Co. Vaea Tar Sand Project. 3-45 Chevron Standard Ltd. Alsands Project Group ...... 3-33 Huff-and-Puff Cold Lake Project. 3-39 Conoco, Inc. Conoco Uvalde Project 3-37 Dome Petroleum Canada Ltd. Alsands Project Group ...... 3-33 Dome Combination Thermal Drive Project 3-37 Elk Point Heavy Oil Project 3-37 Enereor Asphalt Ridge Pilot Plant ..... 3-35 FOR Petroleum Company Chetopa Project 3-36 Esso Resources Canada Ltd. Mine Assisted In Situ Project 3-40 PCEJ Project 3-41 Gett y Oil Company Cat Canyon Steamflood Project. 3-36 Diatomaceous Earth Project 3-33 Great National Corporation Sunnyside Project...... 3-43 Guardian Chemical Corporation Aqueous Recover y—Polycomplex. 3-35 Gulf Oil Canada Ltd. Alsands Project Group ...... 3-33 Mine Assisted In Situ ..... 3-40 Pelican ...... 3-42 Resdeln Project ...... 3-42 Sandalta ...... 3-43 Surmont Project 3-43 Syncrude Canada, Ltd...... 3-34 Wabasca Project 3-42

3-30 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 Company or Organization Project Name Page Haliburton Services R.F. Heating Project ...... 3-42 Home Oil Company Sandalta ...... 3-43 Hudson's Bay Oil and Gas Alsands Project Group ...... 3-33 Cold Lake Pilot Project 3-37 Marguerite Lake Phase A Pilot 3-40 Syncrude Canada, Ltd...... 3-34 Husky Oil Operations, Ltd. Aberfeldy Project ...... 3-34 Mine Assisted In Situ Project 3-40 Scotford Synthetic Crude Refinery 3-34 Hydrocarbon Research, Inc. Dynacracking Upgrading Plant. 3-37 HT Research Institute R.F. Heating Project 3-42 Imperial Oil Ltd. Commercial Extraction Plant. Cold Lake 3-33 Leming Project ...... 3-38 Japan Canada Oil Sands, Ltd. PCEJ Project 3-41 Japan Oil Sands Co. (JOSCO) Primrose Project 3-42 Kaiser Oil, Ltd. Suffield Heavy Oil Pilot 3-43 Kirkwood Oil and Gas Tar Sand Triangle ...... 3-44 Laramie Energy Technology Center LETC-TS-1S Reverse Combustion 3-39 (U.S. Department of Energy) Minerals Research Ltd. MRL Solvent Process ...... 3-41 Mobil Canada Ltd. Celtic Heavy Oil Wet Combustion 3-36 Cold Lake Stratigraphic Test Program 3-37 Murphy Oil Canada Ltd Eyehill In Situ Steam Project 3-38 Lindbergh Steam Project ..... 3-39 Lloydminster Fireflood 3-39 Natomas Energy Company Natomas Solvent Extraction Process. 3-41 Noreen Energy Resources Ltd. Primrose Project 3-42 Nova Oil Sands Surface Mine Project 3-33 PanCanadian Petroleum Cold Lake Pilot Project 3-37 Marguerite Lake Phase A Pilot Plant 3-40 Synerude Canada. Ltd...... 3-34 Petrocanada Alsands Project Group ...... 3-33 Block One Project ...... 3-36 Ipiatik Lake Project 3-39 Mine Assisted In Situ Project 3-40 North Kinsella Heavy Oil ..... 3-11 Oil Sands Surface Mine Project 3-33 PCEJ Project 3-4! Syncrude Canada, Ltd...... 3-34 Petrofina Canada Ltd. Alsands Project Group ...... 3-33 Syncrude Canada, Ltd...... 3-34 Pittston Compan y Westken In Situ Wet Combustion Project 3-45 Rio Verde Energy Co. Rio Verde Energy Co. Project. 3-42 RTR Oil Sands Alberta, Ltd. RTR Pilot Project ...... 3-45 Sandia Laboratories Deepsteam Project...... 3-37 Santa Fe Energy, Inc. "200" Sand Steamflood Project 3-44 Vaea Tar Sand Project ...... 3-45 Saskatchewan Oil and Gas Corporation Meota Steam Drive Project 3-40 Shell Canada Resources, Ltd. Alsands Project Group ...... 3-33 Block One Project ...... 3-36 Peace River In Situ Pilot Project. 3-42 Seotford Synthetic Crude Refinery 3-34

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-31 Company or Organization Project Name Page

Shell Explorer. Ltd. Alsands Project Group 3-33 Peace River In Situ Pilot Project 3-42 Sohio Natural Resources Company Asphalt Ridge Pilot 3-35 Standard Oil of Indiana (Amoco) Sunnyside Project 3-43 Sun Oil Company Block One Project 3-36 Fort Kent Thermal Project 3-38 Suncor. Inc...... 3-34 Synerude Canada, Ltd. Syncrudc Canada. Ltd.. 3-34 Turco, Inc. Tarco Tar Sands Project 3-44 Tenneco Oil of Canada, Ltd. Athabasca In Situ Pilot Project 3-35 Tetra Systems, Inc. Chetopa Project 3-36 Texaco Canada, Ltd Texaco Athabasca Pilot 3-44 Texas CuIf, Inc. Meets Steam Drive Project 3-40 Total Petroleum Meets Steam Drive Project 3-40 Underwood McLeUan& Associates Taciuk Processor Pilot. 3-44 (UMA Group) Union Oil of Canada. Ltd. Chipew yan-Buffalo Creek Carbonate 3-36 Union Texas of Canada, Ltd. Ardmore Thermal Pilot Plant 3-35 U.S. Department of Energy Cat Canyon Steamflood Project. 3-36 Deepsteam Project...... 3-37 R.F. Heating Project ...... 3-42 University of Utah Asphalt Ridge Pilot Plant .... 3-35 Sunnysi de Project...... Westcoast Petroleum, Ltd Manatokan Project ...... ,3-40 Suffield Heavy Oil Pilot 3-43 Western Tar Sands, Inc. Ultra Sonic Wave Extraction 3-45 Wcstkcn Petroleum Co. Westken In Situ Wet Combustion Project 3-45 World Wide Energy Fort Kent Thermal Project 3-38

3-32 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUEI.S PROJECTS (Underline denotes changes since March 1981)

OIL SANDS

COMMERCIAL PROJECTS

ALSANDS ENERGY LTD. (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 130,000 BPD. Located on Lease 13 (Shell) and Leases 12 and 34 (Fine- Daphne) at Athabasca. Alberta. Mining—electric dragline, bucket wheel excavators; extraction-hot water process; upgrading—fluid coking. Alsands intends to manufacture h y drogen initially by natural gas 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 Ba y 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 ERCB in June 1979 and substantiall y approved in December. A preliminar y field program, including site clearing and drainage, was begun, January9 1 80. An acceptable tax package will still have to be negotiated with the federal and provincial governments.

Project Cost: Estimated at $12 billion

ESSO RESOURCES CANADA LIMITED - Cold Lake Project Esso Resources Canada Limited has completed the design of a 141,000 BPD commercial oil sands extraction project near Cold Lake, Alberta. Esso Resources is a wholly owned subsidiary of Imperial Oil Limited, encompassing the latter's upstream assets and operations. The Cold Lake Project will recover heavy oil from the reservoirs by in situ steam stimulation with subsequent fluid pumping. About half of the Project investment involves bitumen upgrading facilities. The primar y conversion step in the upgrading is the Exxon Research and Engineering Flcxicoking process, followed by hydrotreating to reduce sulphur and aromatics content, and to adjust yield patterns. The resulting upgraded crude will be suitable for most Canadian refineries to satisfy product demand slates with existing processing equipment. Esso Resources will act as the plant operator and is inviting financial participation by other interests. The Alberta Energy Resources Conservation Board held extensive public hearings on the Cold Lake Project and submitted a favorable recommendation to the Alberta Provincial Government on October 29, 1979. The final step in the public aoproval process for the Project is the decision of the Alberta Government. This decision is deferred, pending an agreement between the Federal and Province of Alberta Governments on future Canadian crude price increases and the sharing of the resulting revenues between the two levels of government. While these agreements are being negotiated, the Federal Government has advanced $40.000.000 to Esso Resources to maintain its Cold Lake Project team intact, through July 1. 1981.permitting implementation to proceed promptly on receipt of Alberta approval of the Project.

Project Cost: Estimated cost $12 billion

GETTY OIL COMPANY - Diatomaceous Earth Project Getty Oil Company is studying the feasibility of commercial oil production from oil-saturated deposits of diatomaceous earth located in the 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 Gett y , 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 1981. The Dravopilot has been completed; and the Lurgi pilot should he completed in September 1981. 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 average crude oil production of 20.000 barrels per day throughout the life of the project. Getty estimates crude oil produced from the project will average 13 to 18-degrees API gravity. Commercial plant start-up is tentatively scheduled for no earlier than 1986.

Project Cost; Undetermined at this time.

OIL SANDS SURFACE MINE PROJECT - Petro-Canada, Alberta Gas Trunklinc, 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 da y at an undisclosed cost. Both Husky Oil Ltd., and the Alberta Indian Tribes have been offered a 10 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.

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 333 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) COMMERCIAL PROJECTS (Cont.)

SCOTFORD 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 b y the proposed Alsands project in the late 1980's. The refiner y's petroleum products will be gasoline, diesel and jet fuel and stove oil. The refinery will also produce 4,800 barrels per day of benzene which will be used as feedstock for a planned world scale sty rene plant in the refinery vicinity. 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) of Calgary, Alberta. 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) - Cmmercial plant at 838072-10-W4M has been, nproductionsince 1967 with authorized annual p5oduction of 1,334 m per day from the Athabasca bituminous sands deposit. Annual production for 1979 was 6,800 m I5erday. 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 underwa y 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 bucketwhcel 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. Previous to the Federal Energy Policy announced in November 1980. Suneor received world price for its synthetic crude production from the Oil Sands Division operation at Tar Island. The company now receives Canadian Domestic price for the first 45,000 barrels produced daily, and world price for any daily production exceeding that figure. Suncor, Inc., is currently negotiating with the Federal Government for a new pricing agreement.

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 Energ y Company (10 percent); Province of Alberta (8 percent); PanCanadian Petroleum Limited (4 percent); Petrofina Canada, Inc. (5 percent); Hudson's Bay Oil and Gas Co., Ltd. (5 percent) Plant at 93+92-10 W4M with an allowable production of 129,000 BPCD has been in earl y 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 s ynthetic crude were delivered. Production in 1980 was over 28 million barrels. All major equipment in place and operational; four draglines and four bucketwheels working. S yncrude's staff is now 3.800. Project Cost: Total cost $2.3 billion R & D PROJECTSss...s..*.....,.s..*.*.n,...... *, .... .,...... ABERFELDY PROJECT - Husk y Oil Operations. Ltd. An in situ steam drive with steam stimulation project is being developed at Aberfeldy Section 20-49-23 W3M in Saskatchewan. Installation of equipment and flow lines is underway with initial production expected to commence by June 1980, and steam injection by early 1981. A.D.I. CHEMICAL EXTRACTION - Aarian Development, Inc Aarian Development Incorporated will use A.D.I. Chemical Extraction technology to produce 20,000 barrels of bitumen per day from Eastern Utah oil sands. The plant would be built in three phases, with construction beginning in 1982 and initial production starting later that year at 5,000 to 8,000 barrels per day. Phase two will increase to 14,000 barrels per day in the third year. Phase three would reach 20,000 barrels per day in 1986. Loan guarantees and price guarantees have been requested from the Synthetic Fuels Corporation. Project Cost: $28.3 million. *New or Revised Projects.

3-34 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

R&D PROJECTS (Cont.) AQUEOUS RECOVERY - Dikor Process, Guardian Chemical Corporation The aqueous recovery process investigates the feasibility of using a low concentrate solution of a Pol yeomplex to extract bitumen from oil sands. The chemical was originall y 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 commerciall y in the Athabasca deposit with support of major companies. Results of testing encouraging, and 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 in an in situ recovery pilot in the Cold Lake tar sand deposit of northeastern Alberta. The purpose of the project, consisting of 15 wells drilled on S acre spacing, was to evaluate both steam stimulation (huff and puff) and steam drive. The reservoir crude is immobile at original conditions, but by using steam stimulation, the reservoir temperature around the well bore was increased enough to allow the heavy crude (10-12 0 API) to be produced. After several steam stimulation cycles, interwell communication was established between 4 of the IS experimental wells. At that point, (approximately January 1. 1980), the project was converted to a steam drive with one injector and three producers (the other 11 wells were shut-in). Since then the production rate of the three producers has averaged in the order of 50 BOPD/welI. To date a total of more than 250,000 bbls of heavy crude have been recovered since the pilot was initiated.

Project Cost: Capital Costs estimated at $3.0 million ASPHALT RIDGE PILOT PLANT - Enercor. University of Utah Proposed plan to construct and operate a pilot plant on Asphalt Ridge utilizing University of Utah hot water oil extraction process and bitumen upgrading technology. Engineering for the initial 50 barrel per day pilot plant is underway, and plans are to have it operational in mid-1981. Enercor received 50,000 grant from the Utah State Advisor y Council on Science and TechnoloEv. who will. accordinr to Drovisionst" of the anorooriation leisIation.

Project Cost: Estimated at $1.1 to $1.5 million ASPHALT RIDGE PILOT - Sohio Shale Oil Company A surface mining project using solvent/water extraction, located on 8,200 acres in Uintah County, Utah. The extraction process is a process called "continuous counter current solvent extraction process" developed b y 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 1981.

Project Cost: Undisclosed *ATHABASCA IN SITU PILOT PROJECT - CDC Oil and Gas. Ltd., Tenneco Oil of Canada, Ltd. The CDC/TECAN steam flood pilot, scheduled for startup in late 1981. will begin with steam stimulation of production wells followed by continuous steam injection into the injection wells. Two separate patterns will be tested to compare the effect of different well spacing. Anticipated peak oil production rate is about 2.000 BOPD. All pertinent data concerning the volumes and pressures of steam injected, steamfront movement through the formation, and the volumes and analysis of the produced fluids will be recorded and stored on a micro-computer for future analysis. A total of 50 wells will have been drilled and completed during the 1980-8I winter drilling season including 10 producers, 16 injectors, 15 temperature observation wells inside the patterns, three observation wells outside the patterns, three water source wells, and three water disposal wells. If the pilot is successful during the first few years of operation, it would be expanded in 1984. Also, other supplemental techniques (nitrogen or carbon dioxide injection) might be tested. An intensive corehole program and geological analysis would be conducted on the in situ lands of Lease 87 to determine the best location for a commercial project. Project Cost: Unknown *New or Revised Projects.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-35 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) R&D PROJECTS (Cont.)

BLOCK ONE PROJECT - Amoco Canada Petroleum Company Ltd., AOSTRA, Petro-Canada, Ltd, Suncor, Inc., Shell Canada Resources This Experimental in situ recovery pilot is located in section 27-85-8 W4M, Gregoire Lake, Athabasca deposit, Alberta. Canada. The project, called Block One, consists of nine 2-1/2 acre patterns, expected to produce nearly 1.000 BPD. This in situ project is utilizing a 3-step process including COFCAW. Amoco holds patent rights to this process. A total of nine injection, 16 production and seven observation welts 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 STEAMFLOOD PROJECT - Gett y Oil Compan y, U.S. Department of Energy. The objective of this pilot program is to evaluate the feasibility and economies of the steam displacement process for future full-scale development of the Cat Canyon SI-B oil sand reservoir and in similar deep heav y 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 Februar y ,-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 dc-watering operation is complete. Ultimate Project Cost: $8,700,000

CELTIC HEAVY OIL WET COMBUSTION - Mobil Oil Canada, Ltd. Mobil's wet combustion heav y oil project is located in T52 and R23, W3M in the Celtic Field, northeast of Llo ydminster. 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 productivit y. Wells have been drilled; construction of injection and production facilities is expected to he completed b y March 1981. Air injection started in late October 1980. Total cost for facilities and wells is $20.5 million. Operating cost is $1.2 million. Project Cost: $30 million (Cdn.) CHETOPA PROJECT - EOR Petroleum Co.. Tetra Systems The Chetopa Project, located in Labette County, Kansas. will use technology for heavy oil recovery developed by Tetra Systems. First year production will reach 480.000 barrels. This process involves the excavation of a series of shafts, approximately 12 feet in diameter and 100-200 feet deep, and the insertion of steam pipes into the formation beneath each unit. "Flop-Flop" technology is used to extract heavy oil from the reservoir. The project is currently sponsored by EOR Petroleum Co., however, discussion with Tetra Systems. Inc. are ongoing with respect to the formation of a joint venture partnership. It is anticipated that shaft excavation and collection unit construction would be contracted out, but no proposal for bids has yet been released. An EIS has not yet been submitted, and formal application for state and local permits awaits firm financial commitment. EOR has requested that the U.S. Synthetic Fuels Corporation enter into a loan guarantee commitment for $21 million. CHIPEWYAN - BUFFALO CREEK CARBONATE - Union Oil Company of Canada Testing of an in situ recovery project has taken place under Approval No. 2062 in 2189-21 W4 in the Chipew yan area west of the Athabasca deposit, Alberta. Canada. A single huff-and-puff test was run to determine steam injection capacit y 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. *New or Revised Projects.

3-36 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

R&D PROJECTS (Cont.)

COLD LAKE PILOT PROJECT - HP Canada, Pancanadian Petroleum Ltd., Hudson's Bay Oil and Gas Company A second pilot plant is being planned by BP Canada, located near the Alberta-Saskatchewan 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 day. 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 was carried out in 1980, in addition to 94 holes previously drilled. A decision on location of a possible pilot project will depend on the results.

*CONOCO UVALDE PROJECT - In Situ Steam Drive This Uvalde, Texas project involves the use of in situ steam drive to recover oil from a -2 0 API deposit (viscosity over 1.000.000 cp) at a depth of 1,500 feet. One five spot pattern pilot test has been completed, with an estimated oil recovery of 53 percent. Work is currently in progress to conduct a second similar pilot test several miles away. Because of the high energy inputs required in the first test, steam for the second test will be provided using a coal fired, fluidized bed steam generator.

DEEPSTEAM PROJECT - U.S. Department of Energy, Sandia Laboratories This project includes use of a downhole steam generator developed to operate at the base of the oil-bearing formation. Field testing started in February 1980 on the Chevron lease near Bakersfield, California. During the first phase of the test, steam will be injected from above ground. In the second phase of the test, foam will also be used to control movement of steam through the reservoir. The generator will be lowered into the hole in the following phases. Trials of three downhole steam generators began in the summer of 1980. During a 5-month test, 25,000 bbl of heavy crude were recovered from the Kern River Field in California by using the downhole generator on the surface. Longer term tests are scheduled by the end of 1981. The program is intended to produce commercially designed units by 1982-1983.

'DOME COMBINATION THERMAL DRIVE PROJECT - Dome Petroleum Company Dome completed a 17 well drilling program at Morgan (northeast of Llo ydminister) during 1980, and will drill an additional 18 holes in 1981. A total of 50 wells could be drilled prior to June 1983. A combination thermal drive technique is being tested, where steam stimulation through several wells preceeds a fireflood initiated through one central well. Initial production is expected this year with the evaluation phase to follow. It is expected that an extension of the experimental permit will be sought.

Project Cost: Unknown

DYNACRACKING UPGRADING PLANT - Hydrocarbon Research, Inc. HRI is working with California Synfuels Research Corporation, operators for an industrial joint venture to build a commercial-scale heavy oil upgrading plant in California, capable of handling heavy oil, tar sand bitumen and shale oil. The facility is designed to initially handle 5.100 barrels per day of vacuum residue from west coast refinery crudes. The plant will use an URI-patented process known as "Dynacracking."

Project Cost: $1.5 million for design phase only.

*ELK POINT HEAVY OIL PROJECT - Dome Petroleum Company Enhanced oil recovery project to produce about 1,500 BPD heavy oil. Dome holds interests in about 95,000 acres in the Elk Point field, northwest of Lloydminister. Steam stimulation followed by a fireflood is currently planned. The project will get underway in 1981.

Project Cost: $25-30 million capital cost

'New or Revised Projects.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-37 STATUS OF SYNPUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) 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 Esso's Lease No. 40. Current project approval is 1,500 HOPI) with productivity around 700 BPD from 30 wells on a five spot pattern. Esso has sold these data to several companies. Esso's Leming piloili located in Section 5 through 8-65-3W4 and currently produces 7,000 BOPD. The Leming pilot uses a seven spot as well as an oblong line drive pattern. A horizontal well was drilfWTh 1978. Esso expanded its Leming field and plant facilities in 1980 to increase the capacity to 14,000 BOPO at a cost $60 million. Operating wells at Leming by year-end 1981 will total 206. j Lake Pro ect will be tested in the esDanded Len

umcn on Project Cost: $200 million

EYEI-IILL 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. Consfruction 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 obtain a 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 Suneor, 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. Under an agreement between Worldwide and Suncor, Suneor became the operator of the project on January 1, 1980. Engineering evaluation of Phases I and II will proceed throughout most of 1981. Current plans project the start of a commercial development in 1982. Preliminary engineering designs for the expansionW_ have been completed, involving the drilling of 112 wells and construction of additional steam facilities t an aooroximate cost of more than $50 million. A greement in nrineinle has been

Project Cost: Estimated Total Cost $448.6 million (Cdn.)

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 formout 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. Approximately $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 Recovery Program of the Department of Energy such that tertiary incentive revenue is available for partial funding of the project. Major construction was initiated during the first week of April 1980, with the sinking of a seven-foot diameter shaft to the base of the oil sand to be produced. Construction of the cavern in the oil sand is in progress. Completion is projected for the third quarter of 1981. Project Cost: $6-7 million total

3-38 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

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 eight temperature observation wells. A huff-and-puff procedure is followed utilizing a 25 MM BTU/hr steam generator. Aquitaine Company of Canada Ltd. ma y 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

IPIATIK 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 10 be 12 billion barrels.

Project Cost: Undetermined

LETC-TS-lS. Steam Drive - U.S. Department of Energy U.S. Department of Energy Tar Sand Program conducted by the Laramie (Wyoming) Energy Technolog y 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. Evaluation of experimental results are continuing. 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. The fourth field experiment, LETC-TS-25. is scheduled for start-up in the second quarter of CY82. Planning, design, and permit acquisition are currently underway.

Project Cost: FY 81 funding at this time is $6 million

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 FIREFLOOD - Murphy Oil Compan y, Ltd. An experimental wet in situ fireflood project located in the Llo ydminister area. .Silverdale (Sparky Pool Formation). Saskatchewan, Canada, has been operated from August of 1973 until May of 1980. The pilot consisted of a nine spot pattern enclosing 40 acres. The drive system appeared technically successful. However, severe operating problems associated with the production wells resulted in unfavorable economics. The pilot is now suspended.

Project Cost: Initial capital investment approximately $1 million

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-39 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) R&D PROJECTS (Cont.)

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 has drilled 12 test wells. A cyclic steam test is being carried out on one of the wells. By October 1, 1983, the company must commence installation of a 25 well pilot project to conduct steamflooding by November 1, 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.

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 PanCanadian Petroleum Limited have entered into arrangements whereby Hudson's Bay and PanCanadian will join HP 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-R5- 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: HP -Exploration Canada- Ltd. (20percènt), 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 HBOG and PCP will have the right to purchase from BP their respective percentage interest in the 75.000 acre block of leases now wholly owned by BR 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. Recently the partners agreed to extend the sco pe of the project by drilling infill wells and by including additional

Project Cost; $44 million

MEOTA STEAM DRIVE PROJECT - Texas Gulf, Inc., Total Petroleum, Saskatchewan Oil and Gas Corporation The project is located approximatel y 20 miles northwest of North Battleford and started in 1974 with one well. Nine oil production/steam injection wells on 2.5 acre spacing have been drilled and subjected to cyclic steam stimulation between 1974 and present. The existing nine-spot was converted to steamdrive in late 1980 with expected recovery at steamdrive completion of 40 percent of the oil-in-place. Feedwater for the existing 20 MMBtu generator is obtained from the North Saskatchewan River via a 3.9 mile pipeline. Fuel gas for the generator is provided from gas wells in the project area. The second phase of the project scheduled for start-up in the fall of 1981 will involve the addition of a 25 MMBtu Thermosludge steam generator which will service an additional nine wells located on 5 and 10 acre spacing.

Project Cost: The Saskatchewan and Canada Federal Governments contributed $1.5 million in funding assistance during 1977 and 1978.

MINE ASSISTED IN-SITU PROJECT - Husky Oil Operations. Ltd., Esso Resources Canada, Ltd., Gulf Canada Resources, Inc., Canada-Cities Service, Ltd., and Petro-Canada 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, S on 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.)

New or Revised Projects.

3-40 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNPUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) R&D PROJECTS (Cont.)

9.IRL SOLVENT PROCESS - C & A Companies, Minerals Research Ltd. C & A Companies has proposed a 20,000 BPD tar sands facility on private land in the PR Springs Deposit, Brand County, Utah. The project will employ surface mining and the Mineral Research Limited solvent extraction process. Minerals Research Ltd. has concluded the laboratory development and Pilot Plant testing phase for their Solvent Process for recovering Bitumen from Tar Sands. The design for construction and operation of a 200 BPD module to evaluate the process under field conditions and actual production has been completed. The 200 BPD commercial demonstration plant. Phase I. will be constructed as early as 1981. The 20.000 BPD production facility, Phase II, will begin construction byd-1982 mi with completion by mid-1986. The 20,000 BPD plant will be constructed in five steps of 4,000 BPD each, allowing production of the first step to begin by early 1983. C & A is requesting loan guarantees from the SFC for the commercial project. Project Cost: Unknown

NATOMAS SOLVENT EXTRACTION PROCESS - Natomas Energy Company Natomas Energy Company has received a grant from the Department of 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 KIN5ELLA HEAVY OIL - Petro-Canada & AOSTRA Heavy oil teritar y recovery experiment conducted in the North Kinsella field, in Alberta Canada. The experiment is underwa y and features the contrasting of two recovery methods; (I) 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

PCEJ PROJECT - Petro-Canada, Canada-Cities Service Ltd. and Esso Resources Canada. Ltd., Japan Canada Oil Sands. Ltd. Project is designed to investigate the extraction of bitumen from Athabasca Oil Sands using an in situ recovery technique consisting of electric preheat process followed by more conventional steam flood recovery mode. Site is located at Stoney Mountain, some 35 km south of Fort McMurray. The plant is presently 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 corning obligation for Phase I by contributing $30.8 million.

Project Cost: Undetermined. *New or Revised Projects.

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 3-41 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

R&D PROJECTS (Cont.) PEACE RIVER IN SITU PILOT PROJECT - Shell Canada Resources. Ltd./AOSTRA, Amoco Canada, Petroleum Co., Ltd, Shell Explorer, Ltd. Experimental in situ recovery project located about 20 miles northeast of Peace River, Alberta. Project consists of 7 seven-acre 7-spot patterns producing a peak of 3,500 BPD bitumen. Field site preparation commenced October 1977. Phase A covering engineering design, procurement and construction was a fixed $58 million. Phases B and C provide for five and four years of operation respectively, which could bring total cost to $170 million. Cost of the project being shared 50 percent by Alberta Oil Sands Technology and Research Authority (AOSTRA) and 18.75 percent each by Shell Canada Resources, Ltd. and Shell Explorer Ltd. and 12.5 percent by Amoco Canada Ltd. Construction and drilling completed October 1979 with Phase B operations now in progress.

Project Cost: Phase A cost $58 million (complete) Phase B cost currently estimated at $65.7 million.

PELICAN-WAIJASCA PROJECT - Gulf Canada Resources, Inc. Construction of fireflood and stcamflood pilot facilities is underway in the Pelican area of the Wabasca oil sands with the project to be operative by 1981. The pilot will consist of a 31 well centrally enclosed? spot pattern. Both steam stimulation and fireflood processes will be tested.

PRIMROSE PROJECT - Noreen Energy Resources Ltd. & Japan Oil Sands Co. Noreen is the operator of an experimental in situ project located 25 miles north of Cold Lake, Alberta, Canada. Delineation drilling was completed in the spring of 1975 on lease No. 60. Drilling of production-injection wells for the pilot project was completed in the fall of 1975, with construction of facilities essentially completed in September of 1976. Steam injection operations have proceeded continuously since that date. Project Cost: The agreement with JOSCO stipulates that they must expend 75 percent of $15 million in order to obtain a 50 percent working interest in the lease. To date, expenditures have reached the committed amount. 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: $4.5 million (Cdn.) *R.F. HEATING PROJECT - lIT Research Institute, U.S. Department of Energy, Elaliburton Services The Illinois Institute of Technology Research Institute is preparing a series of experiments with the radio frequency process in Utah Oil Sands. The development is being funded by the U.S. Department of Energy ($3.6 million) and by Halliburton Services ($1.4 million). The 27 month program will include field tests and additional laboratory studies of the radio frequency process, which has been under development since 1976. -RIO VERDE ENERGY CO. PROJECT - In Situ Combustion Rio Verde Energy Co. entered into a joint venture agreement with Reading and Bates Petroleum Co., where the latter is to conduct core drilling on a 1000 acre test property within three months ending July 1981. They were also to test the commercial feasibility of applying enhanced oil recovery techniques. Reading and Bates has the option to acquire 5,000 additional acres. Rio Verde Energy holds 160,000 acres of Kentucky oil sands leases and has asked the U.S. Synthetic Fuels Corporation for financial assistance in developing those leases. A loan guarantee of $54 million and a price guarantee of $34 per barrel of oil recovered (until an upgrading facility was available or five years of production had expired) was requested. The project will use in situ combustion methods to produce 10,000 barrels per day of synthetic crude oil from tar sands. Tar sand leases near Brownsville, Kentucky will be developed first.

New or Revised Projects.

3-42 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

R&D PROJECTS (Cont.) 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 SANDALTA-Home Oil Company, Ltd., Alminex, Ltd., Gulf Canada Resources, Inc. Home Oil Company Limited, in October 1979, announced the farmout of its Athabasca oil sands property to Gulf Canada Resources, Inc. The property, Oil Sands Lease #0980090001 (formerly BSL #30) consists of 15,086 hectares (37,715 acres), situated 43 kilometers (26 miles) north of Fort McMurray on the east side of the Athabasca River. Under terms of the farmout agreement, Gulf, through expenditures totalling some $42 million, can earn up to an 83.75 percent interest in the lease with Home retaining 10 percent and Alimex Ltd. 6.25 percent. An exploratory drilling program began in December 1979 and was completed in February 1980. Results of this program were encouraging and Gulf has elected to proceed with further exploration in 1981. A decision to proceed with commercial development will not be made until 1986. Project Cost: Gulf Canada only $42 million.

SUFFIELD HEAVY OIL PILOT - (SHOP) - Alberta Energy Company Ltd.. AOSTRA, Westcoast Petroleum Ltd., Musketeer Energy Ltd. An in situ combustion project located in southeastern Alberta within the Suffield Military Range and operated by Alberta Energy Compan y. Phase A of the project consists of one isolated five-spot pattern. The reservoir is a Glauconitic sand in the Upper Mannville formation which is underlain by water. The wells, including three temperature observation wells, were drilled during the summer of 1980. Completion of facilities construction and start of injection is forecast for early 1981. Phase A is expected to continue for four years. AOSTRA holds a 50 percent interest in the project, Alberta Energy Company holds a 25 percent interest and Musketeer Energ y and Westeoast 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

SUNNYSIDE PROJECT - Standard Oil Company of Indiana (Amoco) Standard is conducting a feasibility study for a commercial project in the Sunnyside deposit in Carbon County, Utah. Various extraction technologies are being studied tinder 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. Data for environmental purposes is also being collected. The feasibility study is slated for completion in 1981. The study is totally funded by Standard. 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)

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-43 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981)

R&D PROJECTS (Cont.) 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 n cost of $1 million, and has been in operation since. The process was invented by William Taciuk of The IJMA Group. Development is being done by IJMATAC Industrial Processes Ltd., a subsidiary of The UMA Group. The processor consists or a rotating kiln which houses heat exchange, cracking and combustion processes. The processor yields cracked bitumen vapors and dr y 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) FAR 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 or bitumen.

Project Cost: Unknown TARCO TAR SANDS PROJECT —Tarco. Inc.. Green Coal Co., Texas Gas Transmission Corporation A 200 BPD synthetic crude from tar sand plant located near Homer in Logan County. Kentucky. A permit to mine tar sands on the 28-acre site has been issued to Turco by the Kentucky Department for Natural Resources and Environmental Protection. A PSD permit was issued in October 1980. The mobile plant facility will be coal fired. Ilexane extraction technology will he applied.

Project Cost: Undisclosed TEXACO A'FIIABASCA PILOT - Texaco Canada Resources 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 thirt y-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. First pattern caustic flood has been completed the results are being assessed. Second pattern wet combustion test preparations are continuing with start-up expected Ma y 1981. Casing and slotted liners have been run in three horizontal wells forming Pattern Ill. The wells were drilled to program with about 330 meters of horizontal seeiT3ifln each well. The first well is now in soak phase and the two remaining wells fire being steamed. Preparations are being made for a similar three horizontal-well pilot at the Company's Steephank lease (Bituminous Sand Lease No. 49 in the Athabasca Oil Sand Deposit). The Alberta Energy Resources Conservation Board has approvedth e project. Drilling has enbe postponed until the winter of 1981-82 because of loner than expected drilling times at the Athabasea pilot by the specialized but preparations and construction of the Pilot Project at this lease will continue to gain data and experience. Project Cost: Approximately $33 million to end of 1980. "200" SAND STEAMFLOOD DEMO1STRATION PROJECT - Santa Fe Energ y Company, U.S. Department Energy. This is a jointly-funded steamflood project in the Midway-Sunset Field of Kern County, California. The reservoir contains approximately 50 million barrels of oil-in-place between 400 and 700 feet deep: The project consists of five phases: Pilot site monitoring and evaluation; Pilot area expansion; Site selection for full-scale project; Expansion to full-scale stcamflood, and a Production monitoring phase. The project is currently in its fourth year. The pilot evaluation report was prepared during 1979 and a decision was made to go to an expanded program of fourteen patterns with drilling anticipated to start in April 1980. Current expenditures on the project total 54.927.696. Injection rates for the pilot project averaged 450 B/D/well with production from the ten pilot producers averaging 136 B/D/oil and 276 B/D/ water for 1979. The project has indicated that it is rate sensitive. Expansion to a full scale steamflood was started in April 1980. Currently, 21 wells have been drilled. Steam injection and production facilities are being constructed. It is anticipated that the expansion will be completed in June 1981. Project Cost: Total cost $8.25 million

*New or Revised Projects.

3-44 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/OIL SANDS (Underline denotes changes since March 1981) R&D PROJECTS (Cont.)

ULTRA SONIC WAVE EXTRACTION - Western Tar Sands Inc. A 100 BPD pilot plant located on a 640-acre site at Asphalt Ridge in Uintah Count y. Utah. Open pit mining, crushing and surface extraction will be employed. The facility will use solvent, condensed natural gas, or a paraffinic fluid, enhanced by ultrasonic vibration for extraction. Tracor, Inc. will build and operate the pilot plant which is due on stream in 1981. Corkhill Drilling, Inc. was engaged by Western to drill 14 holes to an average depth of 100 feet to determine the extent of tar sand resources on the site location. Project Cost: $1.5 million

VACA TAR SAND PROJECT - Chanslor Western Oil and Development Company (Santa Fe Energ y Company) Proposed commercial stcamflood 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.

*WESTKEN IN SITU WET COMBUSTION PROJECT - Pittston Compan y, Westken Petroleum Corporation A joint venture tar sand project to be located on a 19.000 acre tract of land in Edmonton Count y, Kentucky. The project will use thermal in situ combustion technology. Pittston is the lead compan y sponsor and will invest up to $8 million for construction and operation of the pilot and demonstration facilities. Westken will serve as lease operator and financial agent. The plant will be built in 500 BPD modules with initial production scheduled to begin in 1982 and full production of 12,000 BPD to be achieved in 1987. A loan guarantee has been requested from the Synthetic Fuels Corporation.

Project Cost: $200 million

*New or Revised Projects.

CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 3-45 RECENT OIL SANDS PUBLICATIONS

Aquino, L., et al.,' Demetalization and Desulfurization of Deasphalted Oils of heavy Venezuelan Crudes," Revista Tecnica Intevep, V. 1, N. 1, January 1981, pp. 3-8. Arnold, M.D. and A. Herbert Harve y . "A Radial Model for Estimating heat Distribution In Selective Electric Reservoir Heating," in The Journal of Canadian Petroleum Technology, Montreal, Quebec. October-December 1980, pp. 37-41. Bearden. R. and C.L. Aldridge, "Novel Catalyst and Process for Upgrading Residual and Heavy Crudes," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Bower, R.B., "Intcgraded Heav y Oil Production and Upgrading." presented at the Second Venezuelan Petroleum Seminar in Caracas. Maracaibo. Puerto La Cruz, February 14-24. 1981. Chrones. J.. "Flow Much Upgrading? Where? How?." presented at the conference on Advances in Petroleum Recovery and Upgrading. snonsored by the Alberta Oil Sands Technology and Research Authority, held in Calgar y, Alberta, on May 24- 26. 1981. Dugdale. Dr. P.J.. "Equipment and Its Corrosion in In Situ Pilots." presented at the conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgary. Alberta. on May 24-26. 1981. - - -- - Earnshaw. D. and U. Moore, "Instrumentation and Data Acquisition for an In Situ Tar Sand Steam Injection Experiment." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. *Energy Resources Conservation Hoard. "Make-up Fuel Esso Cold Lake Project." Alberta, Canada, February 1981. Fanaritis. John. "Fluid Bed Retrofit to an Enhanced Recovery, Oil Patch Steam Generator," presented at the IGT sym posium on Advances in Coal Utilization Technology IV. held in Denver. April 22-24, 1981. Fisher. ST.. "Processing of Solid-Fuel Deposits by Electrical Induction Heating." Institute of Electrical and Electronic Engineers. Transactions on Industrial Electronics and Control Instrumentation. Volume IECI-28, N. 1, February 1981. pp. 65-67. *Fisher, Sidney T., "Solid Fossil Fuel Recovery Processes Compared." in Oil & Gas journal. February 23. 1981, pp. 82-90 Funk. E.W.. "Phase Equilibria in Mixtures of Athabasca Bitumen with Alcohol and Paraffin Solvents," presented at the A.I.Ch.E. 1981 Spring Meeting. Houston, Texas. April 1981. Gary Energy Corp.. "Selection of Reservoirs Amenable to Micellar Flooding." First Annual Report, Oct 1978-Dee. 1979, DOE Contract No. BC-00048-20/BC-00051-20, December 1980.

Greene. M.I. and J. Mann, "A New Wa y to Upgrade Tars and Heavy Residua." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Jacobs. F.A.. "Viscosity of Gas-Saturated Bitumen." in The Journal of Canadian Petroleum Technology. Montreal, Quebec. October-December 1980, pp. 37-41. g Lennox. T. Ross. "The Effect of Geolo y on Design and Performance of In Situ Field Pilots." presented at the conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgar y. Alberta. on May 24-26. 1981. Linville. Joe, ed.,"Contracts for Field Projects" and supporting research on "Enhanced Oil Recovery and Improved Drilling Technology," Progress Review No. 24 U.S. Department of Energy/BETC. February 1981.

Maraven. S.A.. "An Update of the (Venezuelan) M-6 Project." presented at ythe conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technolog and Research Authority, held in Calgary, Alberta. on May 24-26. 1981. MacCallum. G.T.. "The Geology Needed for Heavy Oil." presented at the conference on Advances in Petroleum Recovery and Upgrading. sponsored by the Alberta Oil Sands Technolo gy and Research Authority, held in Calgary, Alberta, on May 24-26, 1981.

Reviewed in this issue.

3-46 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS - OIL SANDS

McIntyre. Bruce G • ?'The Geologic Setting of the Grosmont Thermal Recovery Project. Northeastern Alberta,' presented at the conference on Advances in Petroleum Recover y and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgary, Alberta, on May 24-26, 1981. Miller. J.D. and NI. Misra, "Hot Water Process Development for Utah Tar Sands," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Monroe, E.S.. Jr., "Effects of CO in Steam Systems," in Chemical Engineering, March 23. 1981, pp. 209-212. Montgomery, Dr. U.S., "Ritumen Chemistry Related to Upgrading," presented at the conference on Advances in Petroleum Recover y and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgary. Alberta, on May 24-26, 1981.

Mossop, Dr. G.D.,"The Role of Regional Geology in Oil Sands Develo pment," presented at the conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgary, Alberta, on May 24-26. 1981.

Muenger, J.R. and C.P. Marion, "Applications for S yngas Generated by Partial Oxidation of Heav y Feeds with Total Carbon Utilization," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston. Texas, April 1981.

Muth, Chester IV., "Synthesis of Polysulfonates for Enhanced Oil Recovery by Chemical Flooding." Final Report August 30, 1979-August 14, 1980. DOE Contract No. MC-1 1284-'l4. West Virginia University. October 1980.

Perry. Harr y. "Oil Shale and Tar Sands." presented at the Engineering News Record conference Making S ynfuels Plant Business Your Business, Washington, D.C.. March 1981

Rakach, AL, "Design of an In Situ Pilot," presented at the conference on Advances in Petroleum Recovery and Upgrading. sponsored by the Alberta Oil Sands Technology and Research Authorit y , held in Calgary, Alberta. on May 24-26, 1981. Redford, D.A., "The Use of Solvents and Gases With Steam in the Recovery of Bitumen from Oil Sands." presented at the Second Venezuelan Petroleum Seminar in Caracas, Maracaibo. Puerto La Cruz, February 14-24, 1981. Ritter, Dr. D.A., "Tailings Water Reclamation," presented at the conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authorit y , held in Calgary. Alberta. on Ma y 24- 26, 1981.

Rubin, B. and P.K.W. Virtsome, "The Simulation of the In Situ Combustion Process in One Dimension Usin g a Highly Implicit Finite-Difference Scheme," in The Journal of Canadian Petroleum Technology, Montreal, Quebec. October- December 1980, pp. 68-76.

Rush, J.B., "Twenty Years of Heavy Oil Cracking." presented at the A,I.Ch.E. 1981 Spring Meeting, Houston, Texas. April 1981.

Saunders. L.W. and H.L. Mcf{inzie, "Performance Review of Phenolic-Resin Gravel Packin y g," in Journal of Petroleum Technolog , February 1981, pp. 221-228. Savchcnko, B., "Stages in Formation and Growth." in Naradnoyc Khozvavstvo Razakhstana in Russian No. 8, August 1980. pp. 33-36. Science Applications. Inc., "Heavy Oil Reservoirs Recoverable by Thermal Technology." Annual Report. Vol. 1-3. DOE Contract No. ET-12380-1, February 1981.

Science Applications, Inc., "State-of-the-Art Review of Nitrogen and Flue Gas Flooding in Enhanced Oil Recovery." DOE Contract No. DE-AT2I-78MC08333, December 1980.

Society of Petroleum Engineers. "Enhanced Oil Recovery Field Reports." Vol. 6, No. 2. 198 t. Taciuk, Wm., "Taciuk Direct Thermal Processor for Oil Sands." presented at the conference on Advances in Petroleum Recovery and Upgrading, sponsored by the Alberta Oil Sands Technology and Research Authority, held in Calgary, Alberta, on May 24-26, 1981.

Trevoy, Lloyd W., "A New Source of heavy Minerals From Canadian Oil Sands Mining Operation.' presented at the AIME Annual Meeting, Chicago, Illinois, February 22-26, 1981. Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-47 RECENT PUBLICATIONS - OIL SANDS

University of Alabama, Microscopic Study of Oil Recovery by Carbon Dioxide," Final Report. Oct. 1, 1978-AuF, 31. 1980. DOE Contract No. MC-12095-7. December 1980.

University of California, 'Sealed Ph ysical Model Studies of the Steam Drive Process," First Annual Re port, September 1 977-September 1978, DOE Contract No. DE-ATO3-77ET1 2075, December 1980.

\'cnkatcsan. V.N. and F.V. Hansen. 'A Fluidized Bed-Thermal P yrolysis Process for the Recovery of a Bitumen Derived Li quid from the Bitumen Impregnated Sandstone Deposits of Utah," presented at the A.I.Ch. E. 1981 Spring Meeting, Houston, Texas, April 1981.

Vinsome. P.K.W. and J. Westerveld, "Comparison of a Three-Dimensional Numerical Simulation With a Hot Water Drive Physical Model Experiment," in The Journal of Canadian Petroleum Technology. Montreal, Quebec, October-December 1980, op. 42-45.

William March Rice University. "The Single-Well Chemical Tracer Method for Measuring Residual Oil Saturation," Final Report DOE Contract No. DE-ASI 9-79BC20006. October 1980.

Williams. J., "Equipment Required for the Operation of a Steam Injection System and for the Production and Processing of heavy Oil." presented at the Second Venezuelan Petroleum Seminar in Caracas, Maracaibo, Puerto La Cruz, February 14- 24. 1981. OIL SANDS - PATENTS

Barber Heavy Oil Process. Inc., Jose ph C. Allen - Inventor. U.S. Patent 4.257.650. March 24. 1981, "Method For Recovering Subsurface Earth Substances." This invention relates to methods and systems for recovering high viscosity oils, petroleum substances and other minerals from subsurface earth formations. In particular. one or more large diameter shaft holes are orovided which preferabl y terminate in an enlarged subterranean chamber. A pluralityo f drill holes are provided, with perforated piping which extend radially from the chamber into the formation, and from which oil and the like may he recovered. It is a particular feature of this invention to provide means and methods for injecting a mixture of steam nnd a noncondensable gas into the drillholes. whereby the driving mechanism of the formation may he selectivel y maintained or enhanced at the same time the viscosity of the oil in the formation is reduced.

Bodine, Albert G. - Inventor. U.S. Patent 4.257.648, March 24. 1981. "Non-Resonant Cyclic Drive System Employing Rectification of the Cycl ic Output." A vibratory drive s ystem for use in spalling a road surface, cutting rock. etc. Vibratory energy is generated by means of an orbiting mass oscillator, the output of which is rectified by means of a rectifier to provide unidirectional pulses to a cutting tooL To make the system compact and provide controlled operational parameters, non-resonant operation is emplo yed, optimum drive to the tool being achieved by biasing the oscillator against the tool and by providing a shoulder which fixes the uppermost position of the tool when it is being biased against a load. The tool position and the design of the oscillator are such that the oscillator housing contacts the tool near the mid-down stroke (90' ) of the oscillatory vibration cycle, this being the point of highest vibratory velocity and kinetic energy. In this manner, the highest possible delivery of energy to the tool is provided. Earnofsky. George B. - Inventor, U.S. Patent 4.239.617. December 16. 1980. "Process and Apparatus for Solvent Extraction of Oil From Oil-Containing Diatomite Ore." A process for solvent extraction of oil from oil bearing diatomite ore and an apparatus for use therewith. The ore is extracted by countercurrent decantation with a hydrocarbon solvent. solvent is recovered from the extract by multiple effect evaporation followed by stripping, spent diatomite is contacted with water to displace a major portion of the solvent therefrom, and solvent is recovered from the aqueous slurry of the spent diatomite by stripping with steam at superatmospherie pressure. Linde Aktiengesellschaft. Hans J. Wernicke - Inventor. U.S. Patent 4.257,871, March 24. 1981. "Use of Vacuum Residue in Thermal Cracking." Vacuum residue is used for production of olefins by first separating, preferably by solvent extraction, the asphalt therein, blending resultant asphalt depleted fraction with a lighter fraction, e.g., a vacuum gas oil, and then subjecting the blend to a conventional catalytic hydrogenation step prior to thermal cracking. The hydrogenate may be separated into fractions with the heavy fraction only being thermally cracked.

Mitsubishi Mining & Cement Co., Ltd., Masaaki Ruho, et al. - Inventors. U.S. Patent 4.256.342, March 17, 1981, "Dragline Equipped With Hopper Means and Loading Means." A novel dragline is pr ovided which is equipped with hopper means and loading means. More specifically, the dragline of the invention com prises a hopper means mounted on the front portion of a revolving frame rotatably mounted on a mobile base, the hopper means receiving rocks and stones, soil and sand. minerals and the like dug and carried by a bucket, a guide means for guiding the bucket to a position over the hopper means so that the excavated material is loaded into the hopper means, and a loading means disposed below the hopper means for receiving and transferring the material into another transport means, at least the downstream end portion of the loading means being pivotable. The dragline of the invention makes it possible to dig rocks and stones, soil and sand, minerals. etc., in an efficient manner on a large scale and to load them into a transport means.

3-48 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 OIL SANDS - PATENTS

Mobil Oil Corporation, Leslie R. Rudnick - Inventor, U.S. Patent 4,242,195, December 30, 1980, "Extraction of Tar Sands or Oil Shale With Organic Sulfoxides or Sulfones." Tar sands and oil shales are extracted with aliphatic or aromatic sulfoxides or sulf ones whereby both non-polar organic constituents, e.g., hydrocarbons, and more polar constituents, e.g., phenols, are solubilized and recovered for conventional processing.

Otis Engineering Corporation. Ronald K. Churchman - Inventor, U.S. Patent 4.248,302, February 3, 1981, "Method and Apparatus for Recovering Viscous Petroleum From Tar Sand" A method of recovering viscous petroleum from tar sand formations utilizing a deviated steam injection well with pump-down (through the flow line) completion. The steam injection well ma y use side pocket mandrels with constant flow or orifice regulators to control steam injection rates into the surrounding viscous petroleum formation. A pluralit y of pumping wells are situated along the drill path of the steam injection well and substantially above injection points for recovery of the fluidized petroleum. Phillips Petroleum Company, James H. Hedges and Gilbert H. Glinsmann - Inventors. U.S. Patent 4.258,789, March 31, 1981, "Cosurfaetant Blends For Oil Recovery Surfactant System." A first and second series of aqueous surfaetant- eosurfactant-eIeetrolyt s ystems are prepared at varying electrolyte concentrations using, respectively, a relatively water insoluble cosurfactant and a relatively water soluble eosurfaetant. The resulting systems are mixed with oil to be displaced or its equivalent and allowed to equilibrate so as to determine the salinity at which the microemulsion phases forms on said equilibration have approximately equal volumes of oil and water, thus giving the optimal salinity concentration for each surfactant-eosurfactant combination. Similar equilibrations are made using at least one surfactant system which employs a cosurfactant of intermediate water solubilit y. The resulting oil recovery percentage is plotted versus the salinity. Since increasing the more water soluble component of the cosurfactant increases the optimum salinity value and vice versn. a cosurfaetant blend is prepared so as to give a system which has an optimum salinity essentially corresponding to the unique salinity.

Reale, Lucio V. - Inventor, U.S. Patent 4.250,017. February 10. 1981. "Process and Apparatus for Separating Tar From a Tar Sand Mixture." A process and apparatus for separating tar from a tar sand mixture. The separating ste p is by a novel mechanical process avoiding the complication of heating, freezing and the use of solvents. In the process a suitable suspension liquid is added to a tar sand mixture which is then struck with a plurality of striker arms to separate tar from sand particles and agglomerate tar into droplets. After the striking step. the sand particles are allowed to settle to the bottom and tar droplets rise and float, the tar droplets are skimmed off the mixture, and the tar droplets are also scraped off the striker arms. The resulting tar droplets are washed at least once to remove remaining sand particles.

Rockwell International Corporation, Joseph Friedman. et at. - Inventors, U.S. Patent 4.256.565. March 17, 1981, "Method of Producing Olefins From Hydrocarbons." A method of producing high yields of olefins from h ydrocarbon feedstocks which is particularly applicable to heavy hydrocarbons. A current flow of hydrogen is introduced about the periphery of the gaseous oxygen stream at a temperature at which it will spontaneously react with the ox ygen to provide a gas stream of reaction products having an average temperature within the range of about 1,000' to 2.000' C. It contains a major amount of hydrogen and a minor amount of water vapor. The gas stream is introduced at high velocity into a second reaction zone and impinged upon a stream of hydrocarbon which is heated to a temperature in excess of its melting point but below the temperature at which any substantial coke or tar forms. The flowing mixture is maintained at 800° to 1,800° C for a time of from about 1 to 10 milliseconds to form olefins. Thereafter, the flowing mixture is rapidly quenched to arrest the reaction and the olefin products are recovered.

Swanson, Rollan - Inventor, U.S. Patent 4,248,693, February 3, 1981, "Process for Recovering H ydrocarbons and Other Values From Tar Sands." Disclosed is a process for recovering hydrocarbons from tar sands by contacting the tar sands with alkali metal sulfides or alkanol solutions of alkali metal h ydrosulfides, at temperatures between 40°C and 450°C, in the presence of steam or hydrogen or mixtures thereof, thereby producing at least partially, hydrogenated hydrocarbons lower in sulfur and nitrogen content than the initial untreated hydrocarbons of the tar sands and which readily distill from the sands.

Texaco, Inc., John El. Estes and Ernest P. Buinicky - Inventors, U.S Patent 4.250.016, Februar y 10. 1981. "Recovery of Bitumen from Tar Sand." A process for recovering bitumen, or heavy petroleum, from a mixture with sand and similar inorganic materials. Said bitumen-sand mixture is mixed with an aqueous solution of an ammonium salt selected from ammonium sulfite, ammonium bisulfite and mixtures thereof to form a second mixture comprising said aqueous ammonium salt solution, bitumen and sand The second mixture is heated to a temperature in the range of about 120° F (45° C) to about 260° F (127° C) and is separated into a bitumen phase free of sand, an aqueous phase and a sand phase. Texaco. Inc., George Kalfoglou - Inventor, U.S. Patent 4.236.579. December 2, 1980. "Modified Lignosulfonates As Additives In Oil Recovery Processes Involving Chemical Recovery Agents." A process for producing petroleum from subterranean formations 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 lignosulfonate salt modified by alkoxylation 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 lignosulfonates modified by alkoxylation 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.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3-49 OEM PROJECT ACTIVITIES

GREAT PLAINS FILES PROPOSED RATE SETTLEMENT Impacts on the project of the December 8, AND RECEIVES FERC APPROVAL 1980, Federal Appeals Court Decision declar- ing illegal certain financial terms approved Great Plains Gasification Associates filed an Offer of by the Federal Energy Regulatory Commis- Settlement with the Federal Energy Regulatory Commis- sion (FERC) which were critical of the DOE sion (FERC) on April 10, in an effort to obtain final conditional commitment to guarantee the government approvals necessary for full scale construc- loan; tion. Course of action presently preferred by DOE The FERC gave approval to the agreement on April 30, and Great Plains, and other options they have altering it to emphasize that it does not set a precedent. considered to revitalize the project since the court decision; and In the Offer of Settlement, Great Plains proposed to sell the synthetic gas output of its coal gasification plant at Status of DOE compliance with loan guaran- the tailgate of the plant on an unregulated, non-jurisdic- tee requirements contained in the Depart- tional basis. With approval by the Commission, Great ment of Energy Act of 1978—Civilian Appli- Plains can withdraw its certificate application and sell cations (P.L. 95-238). the synthetic gas output of its coal gasification plant on an unregulated, non-jurisdictional basis to Michigan Wis- After the court decision in December, ANR considered a consin Pipe Line Co., National Gas Pipeline Company of variety of actions (See page 4-1, of the March 1981 America, Tennessee Gas Pipeline Company, and Trans- Cameron Synthetic Fuels Report for an analysis of the continental Gas Pipeline Co. Columbia Gas Transmission Supreme Court decision). These options included: Co. will not be contracting with Great Plains. • Appealing the court decision, The Gas Purchase Agreement provides for the sale of • Seeking a Federal legislative solution synthetic gas by Great Plains to each pipeline at a price • Changing the project to produce synthetic of $6.75 per MMBTU, adjusted quarterly commencing liquids instead of gas, and April 1, 1981, in accordance with a factor which reflects • Restructuring the project financing plan. an equal weighting of changes in both (a) the Producer Price Index for all commodities and (b) the Producer Because ANR was striving for a Spring 1981 construction Price Index for No. 2 fuel oil. In addition, ceiling prices start up, restructuring the project financing was picked for the synthetic gas would be established for various as the option to pursue. periods during the term of the Gas Purchase Agreement. During the first five years after deliveries of synthetic Shortly after ANR announced the reclassification pro- gas commence, the price of the gas may not exceed the posal, Columbia Gas System, Inc pulled out of the equivalent price of No 2 fuel oil, but that ceiling would project. not apply in the event that the price of oil were regulated. During the suceeding five years, the ceiling The GAO report is a concise description of Great Plains price would be the higher of (1) the arithmetical average history. The analysis of DOE actions concerning the of the prices paid during the preceding three-month guaranteed financing, however, is the most significant period by each pipeline of the highest-priced 10 percent feature of the GAO findings. According to the report, of its purchases of natural gas in the lower 48 states PL 95-238 set out basic terms and conditions for guaran- from non-affiliated producers (the "domestic price cap") teed financing and DOE either performed the required or (2) the arithmetical average of the prices paid h y the action or insured that Great Plains would take the pipelines for gas imported from Canada and Mexico (the necessary action to comply with the terms of the law. "imported price cap"), but under either cap the price could not exceed the equivalent price of No. 2 fuel oil if While DOE believed that the required actions were the price of oil were unregulated. Thereafter, the satisfactorily completed, GAO questioned the adequacy "domestic price cap" would establish the ceiling price for of its compliance in areas involving implementing regu- the synthetic gas unless natural gas producer prices were lations, congressional report requirements, and establish- regulated, in which event the "imported price cap" would ment of a synthetic fuels advisory panel. be applicable.

GAO REPORT DESCRIBES GREAT PLAINS STATUS In March, the General Accounting Office issued report EMD-81-64 entitled, "Status of Great Plains Coal Gasifi- cation Plant." The proposed $1.5 billion loan guarantee to Great Plains and its ramifications are discussed in the report, as well as the following items:

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-1 W.R. GRACE PROJECT ACTIVITIES DESCRIBED NEW ENGLAND ENERGY PARK DESCRIBED The W.R. Grace coal-to-methanol project, proposed for EG&G Synfuels. a subsidiary of EG&G Inc., is studying location in Moffat County, Colorado, is the first coal the feasibility of developing an energy park based on conversion project to enter the state of Colorado's Joint coal gasification. A 4.300 acre site near Fall River. MA Review Process. (For a description of the Joint Review is under contract with approximately 1,900 acres allo- Process see page 1-68 of the June 1980 Cameron Synthe- cated for the park. tic Fuels Report and the related article in the_ GeiiiF1 Section of this issue concerning the JRP manual). The project, called the New England Energy Project, was selected by DOE in the first round of P.L. 96-126 awards The Joint Agreement for the project has.been signed by for a study using either Koppers-Totzek or Slagging Moffat County, the Colorado Department of Natural Lurgi technology. In their application to the Synthetic Resources, the U.S. Environmental Protection Agency, Fuels Corporation, however, EG&G proposed using the and W.R. Grace. By signing the Joint Agreement, each Texas gasifier. A loan guarantee of approximately $2.8 of the governmental entities has agreed to serve as the billion was requested from the SFC. lead agency for their level of government for this application of the Joint Review Process. The facility would convert approximately 10.500 tons/day of Applachiaji coal to medium-Btu gas that In March of 1981, Grace applied to the Synthetic Fuels would be further converted to 758,000 gal/day of metha- Corporation for a price guarantee of 75 cents/gallon nol and 13.000 megawatt hours/day of electric power. (Jan. 1981 dollars) escalated quarterly at the inflation rate plus 4-percent. According to their application, the Byproducts irwlude 382 long tons/day of elemental sulfur final feasibility study began. in December of 1980 and and 110 x 10 Btu/day of usable low, temperature waste will be completed in August 1981. Preconstruction (e.g. heat: The energy output of the facility, including waste design, permit application) activities will begin in Sep- heat, is equivalent to 55,000 barrels of oil equiva- tember 1981, and construction will start in mid-1982. lent/day. Operations will begin in mid-1984. Vitreous, nonleaehable slag (a maximum of 1.500 The Koppers (KBW) gasifier will be used to process 1.175 tons/day) and other b yproducts will be retained on the TPD of coal from Grace's reserves in the Axial Basin. site and sold for other commerical uses. Little environmental impact is expected from this gasification Approximately 500 tons (or 156,000 gallons) of methanol process. product would then be transported to markets either by railroad tank can (at 30,000 gallons each) or by truck (at Bechtel is the architect/engineer performing pre-con- 8,000 gallons each, 20-25 per day would be needed). struction engineering. Kidder Peabody & Co. Inc. is financial advisor to the project. The plant would require about 1.632,000 gallons of water per da y. W. R. Grace anticipates obtaining this supply from water stored by the Yellow Jacket Water Conser- vancy District. However, because Yellow Jacket's water CONGRESSIONAL OPTIONS REGARDING rights will be junior to those used in the proposed SOLVENT REFINED COAL PLANTS DISCUSSED Juniper-Cross Mountain Project, the latter may be a preferred water source should it be built. On March 6, the Congressional Research Service released Report No. 81-54 SPR designed to provide infor- The construction work force for the project will increase mation useful in deciding the future of the Solvent to 200 during the first six months, then will further Refined Coal Demonstration projects. The following increase to 600 during the first quarter of the second items are presented: year of construction. It would remain at that level for 6-8 months and then return to 200. Operations employ- • Selected benefits that might result from ment would be at a level of approximately 80 as con- operating these plants, as well as possible struction declines. disadvantages of halting construction efforts. According to their application, Grace believes that the • Selected arguments for discontinuing funding po pulation increase generated by 80 permanent jobs of the SRC demonstration plants. should be accommodated without difficulty in the five communities within 30 miles of the project. Their • Several choices and decision criteria facing present population totals over 15,000. Congress regarding funding of the SRC projects. - Table 1 is reprinted from Graces Synthetic Fuels Corpo- ration application and presents the environmental chara- • The option of having the United States Syn- cteristics of a 5000 TPD methanol fuel plant and related thetic Fuels Corporation (SFC) instead of the facilities. DOE partially fund these projects.

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CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-3

Benefits Resulting From SRC Demonstration Described It points out also that large sums of money have been committed by both the government and private industry Successful demonstration of the SRC plants would to these projects. Table I presents the Federal Expendi- tures since 1979. • Provide an accurate basis for determining investment and operational costs for com- The report notes that participation in the projects in- mercial plants; clude non-petroleum industry groups, as well as foreign governments, and, if funding were to stop, there might • Prove the environmental acceptability of the be some adverse reactions regarding this nation's com- SRC fuel products for direct use in electric mitment to internal efforts to develop coal as an energy power generation and allow assessment of the source. marketability of the other products; Arguments Given For Discontinuing Funding of the SRC • Demonstrate the technical feasibility of the Projects process steps, as well as increasing industry's confidence in the improved metals, design The need for a subsidy to the private sector to construct and fabrication technologies that are needed these plants was questioned. In addition, it was stated for commercial scale applications; that the need for such a large commitment of Federal funds is inconsistent with the current effort to cut • Provide technical and economic data that Federal spending and with the Administration's inclina- might be transferred to other coal liquefaction to lessen Federal involvement in energy matters. tion processes; and It also argued that U-Coal and the EDS processes, as • Provide experience in-obtaining the necessary well as SRC. can use -Eastern con]. Another argument regulatory approvals to operate this type of against funding the plants was that the cost of the plant. projects continues to escalate and, with a variety of technical, economic, and managerial problems, will pro- In addition, the processes would be able to utilize bably not meet their intended production schedules. The Eastern coal, resulting in a more comprehensive synthe- original completion date of late 1983 could be 1985 or tic fuels production program. The SRC processes offer later. major opportunities to increase domestic energy supply and to reduce foreign policy and economic vulnerability to foreign initiatives. The report does note, however, that successful demonstration of the processes does not necessarily ensure that they will be commercialized.

TABLE I

FEDERAL EXPENDITURES ON THE SRC PROCESSES SINCE FY 1979 (in thousands of dollars)

Carter Admin- istration's FY 1979 FY 1980 FY 1981 FY 1982 FY 1982 Appropriation Appropriation Appropriation Base Request Solid solvent refined coal (SRC-l) demonstration plant Operating Expenses 7,000 7.000 5,000 5,000 10,900 Construction 40,000 40.000 157.500 157.500 496,500 Liquid solvent refined coal (SRC-U) demonstration plant Operating Expenses 7 9 000 14,000 5,000 5,000 20,000 Construction 50,000 40.000 170.000 170.000 132.000 Solvent refined coal (SRC) pilot plant Operating Expenses 13.500 15.000 47,000 47,000 44.000 Design and technical support Operating Expenses 1,600 ------SUBTOTAL 119,100 116,000 384.500 384,500 703,400

4-4 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 The following options were given with regard to possible Congressional action concerning the SRC plants: • fund neither of the SRC plants; • fund both of the plants; • fund only one of the plants; • fund the scale-up of the plants but at a smaller size than originally planned; • require additional industrial participation but still fund the projects at a reduced Federal level; or • fund the SRC plants using SFC funds instead of DOE funds. Regarding SFC's possible funding of the SRC demonstration plants, three major options were discussed. These included: (1) The SRC demonstration projects could compete for SFC funding along with our other synfuels projects under the joint venture authority of SFC; (2) P.L. 96-294 could be amended to require the SFC to fund the SRC demonstration plants; or, (3) P.L. 294 could be amended to allow SFC's joint-venture authority to be a priority mechanism of financial assistance.

Comment: The report raises more questions than it answers and provides the project sponsors with yet another quandry. Perhaps the most significant short- coming of the report is the weak treatment accorded the financial participation of the Japanese and German governments in the SRC-11 project. (See page 4-2 of the September 1980 Cameron Synthetic Fuels Report for a review of the agreements). Surely our responsibility to keep our commitment deserves more than the weak statement that, "If we stopped the funding, there might be adverse reactions." Further, the fact that the SRC projects have posed a variety of problems and that these would no longer be of concern if the projects were halted, is a rather simplistic approach to the cost dilemma of major energy projects.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-5 ENVIRONMENT

SRC-I DRAFT ENVIRONMENTAL provides supplementary National Environmental Policy IMPACT STATEMENT RELEASED Act (NEPA) reviews as necessar y , and a continual re- evaluation as detailed design progress. The U.S. Department of Energy (DOE) issued the Draft Environmental Impact Statement for the solvent refined Sit.' ic TlrqorihM coal (SRC-0 demonstration plant in January. DOE is proposing to build and operate the 6000 TPD plant at Figure 1 shows the location of the proposed SRC-I site in Newman, Kentucky on a cost-shared basis with the Northwestern Daviess County, Kentucky, 9 km (5.6 International Coal Refining Company (ICRC). A 30.000 miles) south of the Ohio River, which is also the Indiana TPD plant would be constructed at the site upon success- border. The site encompasses 600 ha (1,484 acres) on the ful demonstration of the process. Green River floodplain. The major portion of the site is used for agriculture, with the second most important The tiering approach which will be used by DOE for the land use being the riparian hardwood forest. The Indiana environmental analysis of the project is similar to that bat, a species listed as endangered by the U.S. Fish and used for the SRC-11 project. (See Page 4-19 of the Wildlife Service, occurs on the site in the riparian forest December, 1980 Cameron Synthetic Fuels Report for an along Martin Creek. The project facilities occupy an analysis of the governmental actions caused by the insignificant portion of the species range, however, and controversy over the draft SRC-11 EIS. and Page 5-i of will have no cumulative effect on the winter habitat that report for the memorandum of agreement between considered critical to the species' survival. DOE and EPA describing the tiering approach). Essen- tially this approach, to be used for future statements,

FOREST AND WOODLAND AGRICULTURAL RESIDENTIAL Li] COMMERCIAL L] WILDLIFE MGT. AREA INSTITUTIONAL MARSH PERENNIAL STREAMS AND LAKES OIL WELL 0A5 WELL

- PRIMARY ROAD SECONDARY ROAD PROPERTY BOUNDARY O 05 1 KILOMETER O 0.5 I MILE

- SITE AREA RESERVED FOR DEMONSTRATION EtANI ADDITIONAL SITE RESERVED FOR COMMERCIAL EXPANSION

FIGURE 1 THE PROPOSED SRC-I SITE

4-6 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Because the water quality in the Green River adjacent to with a number of other factors to arrive at the choice of the proposed site is classified as "effluent limited" the Newman as the proposed site. best practicable technology must be applied to wastes which will be discharged into the river. In 1976 Rust Engineering Company, under the sponsor- ship of the Kentucky Center for Energy Research Other Energy Projects Proposed for the Area (KCER), undertook an alternate site analysis for selection of a site for a 2000 TPD SRC-1 plant. The Rust The report discusses in detail the cumulative effects of study evaluated sites from a list of potential Kentucky the projects under construction, proposed, or planned for sites supplied by KCER. The siting criteria used in the construction and operation within a 4-air-mile radius Rust study were primarily physical, engineering, and from the proposed site. Four synfuels projects funded economic factors that were judged to be important for partially by the DOE are currently planned in Western construction and operation of the SRC-1 plant. The Rust Kentucky. Table I lists all the energy projects within study consisted of four phases that, by eliminating the area, including the power plants. The Tri-State potential sites from a large list, sequentially narrowed project is in the feasibility study stage, while the U-Coal the number of potential SRC-1 sites. Phase I of the and W. R. Grace projects are in the preliminary design analysis concentrated on potential siting "areas" and stage. According to the draft, the most significant evaluated these areas on general, physical, and environ- cumulative effects resulting from the energy projects mental requirements and constraints. Phase II of the would be the potential adverse economic, social, and analysis consisted of a more detailed evaluation of the cultural impacts. Figure 2 shows the location of the 24 potential siting areas identified in Phase I. This phase energy projects near the SRC-1 site. reduced the number of potential sites to ten. Phase Ill of the analysis eliminated five of these ten sites because Other Sites Were Also Evaluated of site-specific physical constraints and land availability. The final phase included a more stringent evaluation of The contract awarded for the SRC-1 Phase Zero design the physical, cultural, and economic constraints of the study required that the industrial participant submit a five remaining sites. In the final phase, seven site site-specific proposal. Although environmental factors requirements were assigned weighted values and the were considered by the industrial participant in the site- sites compared. Newman, Kentucky was selected as the selection work, they were considered in combination preferred site in Rust's study, and Equality and Lewis- port were rated as prime alternative sites.

INDIANA 4 LOUISVILLE •,fr SRCl SITE EVANSVILLE - 9 V 07 ILLINOIS '2 is 80 3* HENDERSON I '. OWENSBORO ILL OHIO 6 f KY MOV '—SAC-I SITE

S SYNFUEL FACILITIES PADUCAH 1' 1. SAC-I KENTUCKY 2. W. A. GRACE 3. FRI-STATE 4. H-COAL O 10 20 30 miles I 1 • ELECTRICAL GENERATING PLANTS O 55.5 km 5. ROCKPORT 6. D. B. WILSON 7. GIBSON 8. HANCOCK 9. A. B. BROWN FIGURE 2 ENERGY PROJECT LOCATIONS IN THE VICINITY OF THE SRC-I SITE

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-7 TABLE 1 SYNFUEL FACILITIES AND ELECTRICAL GENERATING PLANTS PROPOSED, PLANNED, OR UNDER CONSTRUCTION IN THE NEWMAN, KENTUCKY AREA Synfuel Facilities Principal Products Approx. Approx. coal input amount Tentative schedule Name/Location - (tons/d) Type (bbl/d equivalent) Construction Operation

1. SRC-1 (demonstration), 6,000 Solid, liquid 20,000 1981 1984 Newman, Kentucky and gaseous SRC-1 (commercial) 30,000 Hydrocarbons 100.000 1986 1994

. W P fl....na flacI,ntt 30 nnn T.inijid 50.000 1982 1987 Kentucky hydrocarbons

3. Tri-State Synthetic Fuels 20,000 Liquid 50,000 1982 1987 Project, Henderson. - hydrocarbons Kentucky "SASOL Project" - - - -

4. H-Coal Project ,a 23,000 Liquid 50.000 1984 1988 Breckenridge County, hydrocarbons Kentucky Electric Generating Plants Capacity Schedule Name/Operator Location (MW) Construction Service

5. Rockport I and 11 Spencer County, Indiana 1,300 Under construction 1986 Indiana Michigan Electric 1,300 Under construction 1986 Company 6. D. B. Wilson Plant Ohio County, Kentucky 395 Start in mid-1981 1983 Big River Electrical 395 Start in mid-1981 1985 Cooperative

7. Gibson Plant Gibson County, Indiana 650 Under construction 1982 Public Service of Indiana 8. Hancock Plant Hancock County, Kentucky 650 Not yet begun 1987 Kentucky Utilities 650 Not yet begun 1988

9. A.B. Brown Plant Posey County. Indiana 250 Under construction 1985 Southern Indiana Gas 500 Start in 1985 1988 and Electric

a Currently limited to process design

4-8 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 After Rust Engineering completed its site-selection acti- the environment. The draft further describes the moni- vity for the SRC-1 project, DOE became a participant in toring program that will include point and fugitive the project. The proposed plant capacit y was increased emission sources, ambient monitoring, and area person- to 6,000 TPD, with the goal of commercial expansion to nel monitoring. The latter is part of an industrial 30,000 TPD in the future. Executive Orders 11988 and hygiene program discussed at length in the draft. Ac- 11990 pertaining to floodplain/wetland encroachment cording to the EIS, the sources of hazardous substances were issued May 24, 1977 after the site selection process to which the public could be exposed include fugitive had been completed. hydrocarbon air emissions (leaks), emissions from the plant flare system, waste-water discharge to the Green To evaluate the impacts of construction and operation at River, and SRC liquid spills during product transport. possible alternative sites, an independent analysis of Point source air emissions, onsite spills, and solid waste available sites was conducted Based on this analysis, disposal are not significant sources. Fugitive hydro- which is described in detail in Appendix B of the draft carbon emissions will be reduced through the use of EIS, two sites were identified as reasonable alternatives special mechanical-design and equipment selection for to the proposed site: one on the Green River near potential leak points and a "directed maintenance" pro- Equality, Kentucky, and one on the Ohio River near gram. Emisson of these hazardous substances from the Ravenswood, West Virginia. Figure 3 shows the location flare system will be reduced through the use of a of the alternative sites. controlled combustor. Discharge of these substances to the Green River will be reduced through the use of a Impacts and Benefits During Demonstration Summarized tertiary wastewater treatment system with zero-discharge capability. Impacts from SRC liquid product The proposed plant design, as well as the environmental spills will be reduced by careful selection of markets, impacts resulting from construction and operation of the routes, transportation equipment, a developed plan for plant, are described in detail in the draft EIS. In spill cleanup and countermeasures, and collaboration addition, the complex organic compounds resulting from with the EPA and the Coast Guard in the event of a spill. the hydrogenation reaction are discussed in detail. The SRC process will produce a broad range of material that contains carcinogenic and mutagenic organic compounds, including aromatic amines, aromatic and heterocyclic compounds, highly substituted phenols, and other compounds. The study describes the engineering controls that are being incorporated in the design to reduce the risk minimizing the exposure of workers, the public, and

PENNSYLVANIA \

vE OHI O - _0NONGA'4 INDIANA : U: MORGAN OH ILLINOIS •PAR,ERSOURGPIT CIWCINNAT, SRAVENSW000 WEST VIRGINIA • L.OULSVLL_ • ST. LOUIS CHARLESTON LEXINGTON OWENSSOR0 RE VIRGINIA EQUALITYAN KENTUCKY MISSOURI N GREE pjIuEP NORTH - . •KNOXVILLE NASHVILLE CAROLINA TENNESSEE K MEM PH I X SOUTH ALABAMA GEORGIA CAROLINA MISSISSIPPI

£ PROPOSED SITE, NEWMAN, KENTUCKY O COMPARATIVE SITE, EQUALITY. KENTUCKY • COMPARATIVE SITE, RAVENSW000, WEST VIRGINIA • MAJOR CITIES

FIGURE 3 REGIONAL SETTING OF ALTERNATIVE SITES FOR SRC-I DEMONSTRATION PLANT

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-9 GOVERNMENT

GENERAL ACCOUNTING OFFICE ADVISES COST functions such as a construction schedule, CONTROL METHODS FOR COAL LIQUEFACTION materials handling, inventory systems, and a PLANTS quality control program were nonexistent for most of the construction period. The General Accounting Office (GAO) recently published a report "Controlling Federal Costs for Coat Liquefac- "DOE staffing was inadequate at both pro- tion Program Hinges on Management and Contracting jects to effectively monitor progress and Improvements." contribute to timely decisions. This was especially so during the construction phase The report discusses the four major coal liquefaction and as a result, at the H-Coal project many processes being developed under DOE direction: H-coal, poor and questionable construction practices Exxon Donor Solvent (EDS), Solvent Refined Coal (SRC- occurred which contributed heavily to the 1), and SRC-11. Major emphasis was given to the H-Coal escalation in both cost and schedule. and EDS projects and the problems encountered during p construction of those recently completed ilot plants. In "DOE's H-Coal contracts were poorly written addition, the escalating projected costs for the SRC-1 because they did not define the scope of work and SRC-11 demonstration plants were analyzed. The other than in general terms and failed to costs for the plants have increased from the original full y protect the Government's investment. $685 million to approximately $1.9 billion for SRC-1 and $1.4 for SRC-11, without provision for contingencies, "DOE plans for the two large SRC demon- escalation or potential product revenues. The DOE stration plants need careful review and quoted cost of $1.4 billion for each of the plants, takes attention in light of escalating cost and the into account product revenues but omits the cost of risks involved in scaling up to the 6.000-ton- contingencies and escalation during the 5-year opera- a-day facilities. The projected costs to- tions phase. GAO believes that complete cost estimates gether with such others as economics, envi- are critical to future decisions on these plants. ronmental considerations, and chances of commercial success are key factors in decid- DOE should be concerned about the small percentage of ing if both processes warrant support in view private investment by U.S. sponsors in the SRC (proof competing technologies." jects), and the concurrency in the design and construction schedules, says GAO. The report questioned DOE's To improve the monitoring and control over future coal wisdom in scaling up the SRC-1 plant from 6 TPD and the liquefaction and other energy projects, GAO made the SRC-11 plant from 30 TPD. following recommendations: Despite the contrast in Government-industry partici- • Assure that projects are properly planned and pation in the li-Coal and EDS processes, the report designed sufficientlybefore they start to analyzes the two projects together rather than critiquing avoid disruptions and to hold design changes each separately. to a minimum. The problems of the difference in Government-industry • Provide adequate DOE support staff to moni- participation are noted in the conclusions, which are tor the various phases of its projects and to quoted directly from the report as follows: assure that management tasks such as property control, inventories, subcontracting. "The initial Government-industry H-Coal and so forth, assigned to private industry are agreements regarding the level of investment done within regulations and with adequate by private sponsors and the ceilings imposed management controls. on sharing in cost growth were imbalaneed. Larger investments by private sponsors and • Establish a format for existing monthl y pro- responsibility in sharing cost growth make all ject reports (prepared by contractors) to pro- parties more cost conscious. EDS with its vide data needed by DOE to effectively mon- 50/50 cost sharing was a prime example of itor the projects. ideal Government-industry financial responsibility and shared risk. As a result, the EDS • Encourage the use of fixed-price contracts project had more adequate controls over when it becomes practicable for the contrac- cost. tors to define their remaining efforts and quantities required. "DOE started the H-Coal project prematurely before sufficiently detailed designs were The GAO recommended that to enhance the prospects available. This action was taken as a reac- for successful future commercialization and to lessen tion to the "energy crisis" and despite warn- the Government's financial burden, the Secretary of DOE ings of the plant designer. The project was should obtain a more equitable percentage of investment not adequately planned and key management from private sponsors for all phases of the energy

4-10 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 projects to assure they share in the risks and fully apply MONTANA ENERGY ALMANAC UPDATED their expertise towards assuring sound management, in- eluding adequate controls over cost and schedule. The Montana's Department of Natural Resources and Conser- Secretary of DOE should also provide to the Congress an vation (DNRC) has updated its "Montana Energy Al- assessment of the effect that the escalating costs of the manac." The new (1980) Almanac replaces a 1978 SRC plants and the risks involved in scaling up to the version. It contains comprehensive summaries of legisla- 6.000-ton-a-da y facilities, along with other relevant faction and government programs relating to energy in tors, will have on the feasibility and affordability of both Montana. It also provides specific information on pro- rrojeets and the ability of DOE to reach its program posed energy development projects, an overview of Mon- objectives. tana's energy production and consumption patterns, and discussions of relevant federal, state, local and private- sector energy-related activities of concern to the state. Particular emphasis has been given to events that have FERC DENIES TRANSWESTERN RECOVERY OF occurred over the past two years as well as current COSTS OF ABANDONED WESCO PROJECT energy-related efforts. Copies may be obtained at the Department of Natural Resources and Conservation, Bruce Birchman, an Administrative Law Judge with the Energy Division, 32 South Ewing, Helena, Montana. Federal Energy Regulatory Commission, issued his Initial Decision in Transwcstern Pipeline Company's rate treat- Montana's Energy Legislation Reviewed ment request on March 13, 1981. In this Decision. Birchrnan denied the rate treatment requested by Trans- Most of Montana's energy-related laws have been passed western for $15.1 million in expenses incurred b y the since 1971, in response to the growing interest in deve- Western Coal Gasification Company (WESCO) project. loping the West's energy resources. The Energy Al- (See page 4-70 of the March 1976 Synthetic Fuels for a amanac describes the regulatory laws. These laws description of the project). relating to energy are administered primarily by DNRC, the Department of State Lands (DSL). and the Public The issue decided by Birchman was whether Western Service Commission. A common theme is the recogni- Coal Gasification Company's coal gasification project tion that environmental, social, economic and human expenses qualify for rate treatment under Commission health-related factors may be adversely affected by Order Numbers 483 or 566. and, if not, whether those energy extraction, conversion and distribution activities. expenses can be amortized in the cost of service. The Minimization and mitigation of impacts, equitable distri- conclusions were that WESCO project expenses qualify bution of energy production costs, reclamation of natural neither for rate base treatment, nor for alternative cost resources, and energy conservation are primary points of of service treatment urged by Transwestern. emphasis.

The FERC Staff contended that the WESCO project Of major impact to coal conversion projects is the Major expenditures should be appraised in terms of the Com- Facility Siting Act (MFSA) enacted in 1973. The Act mission Order Number 483 definition of H and D in provides for comprehensive review of proposals to con- effect at the time of the expenditures were made. This struct and operate certain kinds of facilities for genera- 483 definition restricts cost recovery to projects de- ting, converting or transmitting energy in Montana. The signed to test the technical feasibility of a process. Legislature found that additional facilities may be re- FERC contends that the Lurgi coal gasification project quired to meet an increasing demand for electricity and proposed for use by WESCO was alread y technically other forms of energy, but that such facilities have proven, hence did not entail new novel, or experimental major impacts on the environment, on population distri- technology. Hence, it did not qualify for Ft and D bution, and on the welfare of the citizenry. To minimize treatment under the Order 483 treatment. adverse impacts, the Board of Natural Resources and Conservation must certify public need for and environ- Also denied was Transwestern's point that the Order mental compatibility of such facilities before construc- Number 566 definition of R and 0 should govern rate tion begins. Air and water quality-related matters are treatment for these expenses. Order 566 includes expen- the responsibility of the Board of Health and Environ- ditures of new or existing concepts until technically mental Sciences. feasible and commercially feasible operations are verified. Birchman ruled that Order 566 does not have The Act applies to: (1) facilities that can generate SO retroactive application to alternate energy project which megawatts or more of electricity; (2) facilities that can antedates its issue. produce 25 million cubic feet or more of gas per day; (3) facilities that can produce 25,000 barrels of liquid hydro- In his decision, Birchman also ruled that Transwestern carbon products per day; (4) uranium enrichment facili- failed to establish that it actually incurred the expenses ties; (5) facilities that can use, refine or convert 500,000 at issue, lie said he could find no clear statement as to tons of coal or more per year; (6) electric transmission "which Transwestern affiliate made which payment." lines greater than 69 kilovolts capacity, with certain Also, he contended that the risk of committing funds to exceptions for lines covering short distances; (7) facili- study or initiate projects is a business risk which man- ties for developing and using geothermal resources agement and stockholders should bear. capable of producing 25 million Btu per hour or more; (8) facilities for in situ coal gasification; and (9) pipelines Following FERC's decision, Texas Eastern filed a peti- leading from or to a facility as defined above. Facilities tion with the U.S. Supreme Court for a writ of under exclusive federal jurisdiction are exempt. certiorari.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-11 Applications for facilities filed under the Act must of sites in other states. The Wibaux site was chosen as include a description of the proposed facility, with the proposed site prior to final application to DOE. discussion of alternative sites, an explanation of need for a utility facility, discussion of efforts to promote con- Intake Water Company, a subsidiary of Tenneco, Inc., has servation and reasonable alternative energy sources and signed a contract with DNRC's Water Resources Division a filing fee, based on the estimated construction cost of to gather baseline data for an environmental impact the facility, to finance the state's evaluation. statement on the impoundment of Beaver Creek, near the Montana-North Dakota border. Tenneco plans to The 1979 Legislature amended a number of substantive assess use of this reservoir for the gasification plant as and procedural sections of the Major Facility Siting Act well as water supplies from the Powder and the Yellow- (MFSA) in order to clarify the schedule the state must stone rivers in Montana and from Lake Sakakawea in follow in evaluating and reaching a decision on applica- North Dakota. According to Tenneco's long-range plan, tions. Particular attention was given to the jurisdictions Intake presently has water rights for 80,650 acre-feet of DNRC and the Department of Health and Environ- per year from the Yellowstone River, and has applied for mental Sciences (DHES). Applicants are now required to a Water Use Permit to appropriate water from Beaver file joint application with both departments for a certifi- Creek. The project development study will include an cate of environmental compatibility and public need and analysis of all potential pipelines from water supplies to for the permits required by state air and water quality plant sites. A pipeline to transport the synthetic natural laws. Both departments must accept an application as gas would be built to connect with existing or proposed complete before the evaluation process begins. natural gas pipelines. A connection with the Northern Border Pipeline in North Dakota is one of the options An application may not be filed unless the facility is Tenneco is considering. identified in_a long-range plan submitted to DNRC at least two years before DNRC accepts th&aplicatibn. Utah International, -Inc. -(UI) has -options -to lease and - Applicants are required to submit baseline data for the purchase agreements affecting approximately 60.000 preferred and reasonable alternate site locations identi- acres and at least 500 million tons of strippable coal fied in an application. known as the Moorhead deposit in Powder River County. In 1979 UI informed DNRC that the deposit could be The MFSA requires annual submission of long-range plans "sufficient for the requirements of several gasification by utilities and any person contemplating construction of plants." each of 250 million cubic feet per day capacity, a facility within the ensuing ten years. The plans must if UI is successful in acquiring water and federal and also be filed with the Public Service Commission, the state coal when leasing is resumed. An alternative use Environmental Quality Council, DUES, and the Depart- would be to build a mine-mouth electrical generating ments of State Lands. Highways. and Community Af- facility. fairs. The Crow Indian Tribe received a $2.7 million grant from Certificates may be revoked for failure to meet safety DOE in 1980 to study the feasibility of building a standards or failure to comply with any other conditions synthetic fuel plant on the Crow's reservation. A plant imposed by the Board. Penalties up to $10,000 per day capable of producing synthetic gas (125 million cubic may also be assessed. DNRC is responsible for monitor- feet per day) with the energy equivalent of 22,000 ing the operation of facilities. barrels of oil a day will be studied. The projected nine- month study will explore the financial, environmental, The 1979 Legislature amended the MFSA with respect to socioeconomic, and technical feasibility of building a applications and certificates. Applicants are required to synfuel plant. The grant application was prepared by the supplement an application as requested by DNRC. and Tribal Council, Pacific Coal Gasification, and Fluor DNRC may determine that the supplemental information Engineers. Pacific Coal Gasification would operate the requires an amendment to an application at any time $3-4 billion plant, but the Tribe would own a 51-80 before DNRC's final recommendation. Additional filing percent equity in the plant. Five sites on the Reserva- fees or a new application may be required as the tion are presently being studied. Peak construction is Department determines necessary to carry out its planned for 1984-85 with completion scheduled for 1987. responsibilities. A peak labor force of 3000 is anticipated for the plant. Power to the plant could be supplied by a new coal-fired Plans for Montana Energy Projects Reviewed electrical generator which is also currently being studied. Plans call for phasing construction of the two In April 1980, Tenneco Coal Gasification Company filed projects so that both are not at peak employment at the its first annual long-range plan under the Major Facility same time. Two coal mining companies involved in Siting Act. This plan, in the form of a DOE grant developing Crow coal—Shell Oil Company and Westmore- application for $20 million, described a project develop- land Resources—will provide information on coal ment study for a coal gasification plant that would use reserves for the plant. The Crows have requested loan 13.5 million tons per year of coal to produce 250 million guarantees from the Synthetic Fuels Corporation. cubic feet p& day of synthetic natural gas using the Lurgi process. Tenneco is seeking a loan guarantee for Northern Resources, Inc.. a joint venture of Burlington 75 percent of project capital costs from the Synthetic Northern and Resource Sciences Corporation, is pursuing Fuels Corporation. The plant would be scheduled for full the development of a strip mine on the Dreyer Brothers. production by 1990. Potential sites have been identified Inc. Ranch in McCone Count y. The company plans to in Wibaux and Dawson counties, Montana, and the area open a mine, scheduled for initial production by 1982, surrounding Beach, North Dakota, along with a number which could produce up to 16 million tons per year by

4-12 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 1990. Northern Resources intends to apply for a ten per day gasification plant, requiring up to 10.3 million million ton per year mine to supply a Northern Resources tons of coal per year, is under consideration. lignite-to-methanol conversion facility in McCone County, the output of which would be used to fuel Northern Resources received a $200,000 grant from DOE Burlington Northern locomotives. in 1979 to study the feasibility of siting a coal gasification plant in the Billings area. The facility would be In 1978 DNRC completed detailed baseline vegetation built in the Goggins Industrial Park just east of Billings and wildlife studies for an 11.5 square mile area includ- and would be capable of converting 400 tons of coal per ing the sites that were orginally proposed in 1974 for a day into about 19 million cubic feet of gas per day. fertilizer and methanol-diesel plant and associated mine. Because of its size, the facility would not be under the DNRC has continued to coordinate vegetation and wild- jurisdiction of the MFSA. life monitoring studies in this area. While the company estimates that a maximum of 2,000 acres would be Figure 1 shows the proposed energy developments in disturbed over the life of the currently planned mine, the Montana. mine permit application will cover approximately 31.5 sections to include all areas that might be affected over #### the life of the mine. U.S. REGULATORY COUNCIL REPORTS In 1979 Burlington Northern (BN) proposed that the ON COAL REGULATORY PROBLEMS Timber Creek lignite deposit, west of Glendive, be dedicated to synthetic fuel development. The approxi- The United States Regulatory Council has issued a report mately 1.3 billion ton deposit is in checkerboard owner- entitled, "Cooperation and Conflict: Regulating Coal ship, with the federal government owning 46 percent, Production." This report describes the first year of the Burlington Northern 43 percent, the state of Montana 7 U.S. Regulatory Council Coal Project's effort to percent, and other private parties 4 percent. In letters identify and resolve specific regulatory problems affect- to Montana Governor Thomas L. Judge and the Secretary ing the production of coal. of the Interior, BN proposed pooling the reserves to permit logical development of the coal. BN estimates The U.S. Regulatory Council established the Coal Pro- the deposit could support a facility capable of producing ject in response to complaints that overlap and inconsis- 100,000 barrels of synthetic crude oil per day for 50 tency between regulatory agencies were a source of years at a consumption rate of 25 million tons of lignite major problems for the coal industry. Coal operators per year. In response to SN's proposal, the U.S. Depart- raised this issue with the President's Commission on ment of the Interior (DOI) indicated that it plans to Coal, the National Coal Policy Project, in congressional make federal coal available to industr y through standard hearings, with the regulatory agencies, and directly with leasing procedures. DOI advised SN to maintain contact the U.S. Regulatory Council. In May, 1979 Senator with the local Bureau of Land Management office and to Walter D. Huddleston (fl-Ky) conducted a nationwide share its knowledge of the various coal deposits in the mail survey of coal operators in conjunction with the hope that a Known Recoverable Coal Resource Area three days of hearings on government regulation of the (KRCRA) might be designated. KRCRAs are a means of coal industry which he chaired before the Senate Select targeting prime coal resources for consideration during Committee on Small Business. the process of delineating and ranking potential tracts of coal that the federal government may offer for lease. In Sixty complaints were submitted to the Regulatory 1980 SN filed a general "expression of interest" in Council in response to Sen. Huddleston's survey. Of leasing its lignite deposits along with the federal depo- these, there were: sits. 18 problems of overlapping and inconsistent A number of other energy projects are in the planning regulations; stages. 28 complaints about specific regulatory poli- Mobil Oil Corporation is considering a 400 BPD coal cies or programs; and liquefaction plant in Dawson County, and has filed a 14 complaints about paperwork and permit- water application to take 400 cubic feet of water per ting. second from the Yellowstone River in Dawson County-- also near Glendive—to supply its proposed liquefaction In its attempts to resolve such problems, the council plant. The company wants to produce 40,000 barrels concluded that: daily of unleaded gasoline, using about 14 million tons of coal annually. Problems from overlapping and inconsistent regulations occur more frequently between Montana Power Company (MPC) is evaluating the econo- federal and state agencies than between mic and feasibility of coal gasification, including the federal agencies. possibility of a joint project with Montana-Dakota Utili- ties. A significant portion of the overlap and in- consistency in the regulatory process arises Wesco Resources, Inc., headquartered in Billings, is in the enforcement of the regulations. assessing the feasibility of synthetic fuels development Coal operators have been affected by dis- in the McCone County area on behalf of Washington agreements between the Office of Surface Energy Company of Seattle. One 250 million cubic feet Mining and state agencies on how to implement the new surface reclamation regulatory program.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-13

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4-14 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 • Overlapping reporting requirements and conduct a "Coal Competition and Market Performance redundant permitting requirements are signi- Study." Part of this study, which was conducted by the ficant problems to the coal operator. Energy Information Administration (EtA) has been completed and is available as Report No. DOE/EIA/TR-0253 • Coal operators face regulatory problems be- entitled, "The Substitution of Coal for Oil and Gas in the cause they are unaware of the substance of Industrial Sector." agency requirements. • Strict statutory time limitations placed by This report projects an increasingly important role for Congress on the development of the surface coal to play in meeting the future requirements of the reclamation program have raised uncertainty industrial sector. The total industrial demand for coal concerning how the Surface Mining Control (including metallurgical coal demand) is projected to and Reclamation Act will be implemented increase from 3.4 quadrillion Btu/year in 1978 to 7.3 and enforced. quadrillion Stu in 1990 and 7.9 quadrillion Btu in 1995. • The use of "performance standards' rather Industrial coal demand will represent about 27 percent of the total U.S coal demand by 1995, the remainder being than "design standards" can provide needed used mainly for electric power generation. In compari- flexibility in complying with equipment regu- son, in 1978 the industrial sector accounted for only 10 lations. percent of the domestic coal consumption.

Comment: The U.S. Regulatory Council was abolished in During the next decade, conventional coal technologies March, 1981 (See the General Section for a related (use in boilers, cement kilns and lime kilns) will dominate article). Hopefully, the new task force which replaces industrial coal use. In the longer term, synthetic liquid the Council will be successful in improving the regula- and gaseous coal-derived fuels will extend greatly the tory process which is particularly restrictive in the coal industrial sector's reliance on coal. industry. Coal is expected to retain a relative fuel price advantage ($/Btu) over oil and gas through 1995. Tables 1 and 2, reproduced from the EIA report, compare industrial THE SUBSTITUTION OF COAL FOR OIL AND GAS IN energy consumption and industrial energy prices for THE INDUSTRIAL SECTOR IS STUDIED BY THE various years from 1973 to 1995. ENERGY INFORMATION ADMINISTRATION Section 742 of the Power plant and Industrial Fuel Use Act of 1978 (Public Law 95-620) mandated that DOE

TABLE 1

INDUSTRIAL ENERGY CONSUMPTION

Projections1 1973 1978 1990 1995 Fuel A B A B A B A B Quads Quads Quads Quads

Electricity 2.3 10.0 2.7 12.3 4.6 17.2 5.5 18.6 Distillate Oil 0.9 3.9 1.2 5.5 0.4 1.5 0.4 0.4 Residual Oil 1.3 5.7 1.5 6.8 0.1 0.4 0.2 0.7 Liquid Oil 0.6 2.6 0.8 3.6 0.7 2.6 0.8 2.7 Coal 4.4 19.2 3.4 15.5 7.3 27.2 7.9 26.8 Natural Gas 9.6 41.9 7.9 35.9 7.8 29.1 8.1 27.5 Other 3.8 16.6 4.5 20.0 6.0 22.4 6.7 22.7 Total 22.9 100.0 22.0 100.0 26.8 100.0 29.5 100.0 1 Medium World Oil Prices projection series. Energy Information Administration, Annual Report to Congress, 1979, p. 93 2Coal consumption includes metallurgical coal consumption. NOTE: Column A list quadrillion Btu; Column B lists percentages.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-15 TABLE 2

INDUSTRIAL ENERGY PRICES (1979 dollars per million Btu) Projections FUEL 1973 1978 1990 1995 Electricity 5.96 8.34 12.18 11.96 Distillate Oil 2.33 3.60 7.18 7.85 Residual Oil 1.72 2.49 6.22 6.83 Liquid Oil 2.3? 3.42 8.83 9.56 Coal 0.98 1.34 2.26 2.36 Natural Gas 0.75 1.56 4.85 5.40

4-16 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TECHNOLOGY

"ALTERNATIVE FUELS MONITORS" ASSESS Table I gives the estimated production of coal gasifica- READINESS OF COAL GASIFICATION AND tion and indirect liquefaction facilities to the year 2000. LIQUEFACTION TECHNOLOGIES Table 2 gives the estimated production of high-Btu gas and liquids by technology. The Energy Processes Division (EPD) of the Environ- mental Protection Agency (EPA) is in the process of Direct Coal Liquefaction Monitor Described developing pollution control guidance documents (PCGD) and formal requirements for the production of alter- Specific topics covered in the direct coal liquefaction native fuels. (See page 1-11 of the December 1980 monitor include production capacities and projected out- Cameron Synthetic Fuels Report for a discussion of the puts through the end of this century; estimated factors PCGD). of production needed to achieve these levels; potential sites; supporting activities in the public and private In order to establish priorities, the EPD commissioned sectors; and international activities. the preparation of monitoring reports as means to determine the commercial readiness of various alternative Solvent Refined Coal (SRC)-I, SRC-11, H-Coal, Exxon fuel technologies. Hagler, Bailly & Company completed Donor Solvent (EnS), and the Dow Coal Liquefaction the "Alternative Fuels Monitor: Coal Gasification and Processes are described in the monitor. The report Indirect Liquefaction" last August, and the 'Alternative states that the major outputs of the direct coal lique- Fuels Monitor: Direct Coal Liquefaction," in January faction industry will be naphtha and fuel oil, and the co- 1981 for the EPD. products will be propane, butane, and low-Btu gas. While the SRC-I process also produces a clean-burning solid Coal Gasification and Indirect Liquefaction Monitor fuel, the monitor only considered the liquid products. Contains Project Description Table 3 gives the estimated production of direct liquids While the guidance document on indirect coal liquefac- by technology as predicted in the monitor. According to tion will cover only the Lurgi, Koppers-Totzek. Texaco, the report: Fischer-Tropsch methanol production and M-Gasoline processes, the coal gasification and indirect liquefaction "Commercial direct coal liquefaction (DCL) facili- monitor considers additional technologies in order to ties will not produce alternative fuels until 1990 provide a more comprehensive view of the emerging and not in significant quantities until at least 1995. industry. Through 1990, DCL facilities will be pilot or demonstration plants." Besides a discussion of the technologies, each Monitor includes a brief description of current projects in the The report projected 15,000 to 30,000 barrels per day of United States and abroad; production capacity and pro- oil equivalent (bpdoe) of fuel output from SRC demon- jected output to the end of the century; estimated inputs stration facilities by 1985. The lower level assumes that necessary to achieve these levels; potential plant sites; either the Newman, Kentucky or the Morgantown, West and supporting activities in the public and private sec- Virginia facility will be operating. The upper level tors. assumes that both will be operating.

TABLE 1 ESTIMATED PRODUCTION OF HIGH-BTU GAS AND LIQUIDS, BY TECHNOLOGY (thousand bpdoe)

1985 1990 1995 2000 High-Btu Gasi fication Lurgi 20- 33.5 60 - 100 100 - 150 140 - 235 Koppers-Totzek/Texaeo - 60 - 100 100 - 150 140 - 235 Other - 25 75 - 125 270 - 330 Indirect Liquefaction Fischer-Tropsch - 50 75 - 100 100 - 150 NI-gasoline - 25 - 35 100 - 150 150 - 300 Methanol processes - 50 - 65 200 - 250 275 - 350 Other - 0-25 100 150-200 SOURCE; Hagler, Bailly & Company based on announced projects and corporate intentions and telephone conversations with potential producers.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-17 TABLE 2 GASIFICATION PRODUCTION. 1985-2000 (thousand bpdoe)

Fuel Type 1985 1990 1995 2000 High-Btu Gas 20 - 33.5 145 - 225 275 - 425 550 - 800 Low- to Medium-Btu Gas -- 100 - 250 300 - 650 400 - 700 Liquids -- 125 - 175 475 - 600 675-1,000 Total 20 - 33.5 370 - 650 1,050 - 1,575 1.625 - 2.500 *Predominantly Medium-Btu SOURCE: Haglor. Bailly & Company, based on capacity projections by DOE; Bechtel National, Inc.; Amoco; Booz-Allen; Council on Environmental Quality; IERL - Research Triangle Park.

TABLE 3 ESTIMATED PRODUCTION. BY TECHNOLOGY, 1990-2000 - (thousand bpdoe)

Technology 1990 1995 2000 SRC-I, SRC-ll 0 - 25 50 - 100 100 - 200 H-Coal 25 - 50 50 - 100 100-200 Exxon Donor Solvent 0 - 25 50 - 100 100 - 200 Others 0 0-25 100-150 SOURCE: Hagler. Bailly & Company, based on company intentions. NOTE: Totals will not yield projected output levels because anticipated industry production in any year will be a combination of upper and lower levels for the various technologies.

The monitor predicts that no technique will dominate the expected to be completed until 1990. Table 4 shows the industry, but that the currently leading technologies, production capacity and facilities for coal liquids from SRC-I, SRC-11, H-Coal, and EDS will capture equal 1985-2000. segments of the market through 2000. Other experimental processes will begin entering the commercial Both coal gasification and indirect liquefaction as well market and account for between 0.1 and 0.15 rnbdoe by as the direct liquefaction monitors relied extensively on 2000. No technology is likely to account for more than previously published reports for the conclusions. These 0.2 mbdoc production by 2000. Further, no commercial include the following major reports reviewed on page 4- production facilitiesof half or lull world scale size are 8, September 1980 Cameron Synthetic Fuels Report:

TABLE 4 DIRECT COAL LIQUIDS PRODUCTION CAPACITY AND FACILITIES, 1985 - 2000

1985 1990 1995 2000 Capacity 20 - 40 33 - 66 185 - 315 470 - 705 (thousand bpdoe) Plants' l_22 1 - 2 5-6 II - 16

1A least 10,000 bpd. 20ne or both SRC demonstration plants. 3Assumes a half world scale SRC plant and a half world scale Fl-coal facility owned by Ashland and Airco Cryoplants, Inc. SOURCE: Hagler, Bailly & Company.

4-18 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 "Production of Synthetic Liquids from Coal: TABLE S 1980-2000, A Preliminary Study of Potential Impediments, Final Report," Bechtel Inter- OVERLAPPING COUNTRIES WITH national, Inc., San Francisco, California, POTENTIAL FOR DIRECT Contract No. ET-78-C-01-3137M001. COAL LIQUEFACTION DEVELOPMENT "Project C-Clear, An Assessment of Com- mercial Coal Liquefaction Process Equipment Colorado: Kentucky: Pennsylvania: Performance and Supply," Mechanical Tech- nologies, Inc., Latham, New York, Contract Garfield Henderson Armstrong No. DE-AT21-77MC0-2165, Task 11. La Plata Hopkins Butler Jackson McLean Cambria Routt "Feasibility Assessment - Production of Syn- Muhlenberg Clarion Ohio thetic Fuels from Direct and Indirect Lique- Illinois Clearfield faction Processes," UOP Inc./Systems Deve- Pike Fayette lopment Corporation, McLean, Virginia, Con- Bond Union Greene Bureau Webster tract No. ET-78-C-01-3117. Indiana Clinton Somerset The section on sites in each monitor was derived from Crawford Montana: Washington Douglas Westmoreland three prominent site studies by SRI International, BLM, Edgar and USGS. According to the monitors, 120 countries Bighorn Fayette Custer Utah: were identified in common by the three studies as Franklin Dawson potentially suitable for siting coal gasification and in- Carbon direct liquefaction facilities. These counties are listed Fulton Musselshell by state in Table S. All three studies were in almost Gallatin Richland West Virginia: complete agreement on potential sites in Kentucky, Greene Rosebud Ohio, Pennsylvania, West Virginia, and Wyoming. Over- Grundy Sheridan Barbour lapping sites are also scattered in Colorado, Montana, Hamilton Treasure Boone New Mexico, North Dakota, and Utah. Assuming that Henry Yellowstone Harrison each county can support only one 50,000-bpdoe coal Jackson Lewis conversion plant, a conservative assumption, all three Jefferson New Mexico: Logan studies would agree that potential sites could support 6 Knox Marion million barrels per day (mpd) of alternative fuels produc- La Salle McKinley Marshall tion. Lawrence San Juan Monongalia Livingston Ohio The most original data in the two monitors were the Logan North Dakota Preston tables listing international involvement. Table 6 lists McLean Taylor the Bilateral Coal Gasification Projects, Table 7 lists the Macon Hettinger Upshur Macoupin Coal Gasification and Indirect Liquefaction Projects by McLean Wester Madison Mercer Wetzel individual countries. Table 8, the Multilateral Direct Marion Coal Liquefaction projects, Table 9, the Bilateral Direct Oliver Coal Liquefaction projects, and Table 10, Direct Coal Menard Stark Wyoming: Liquefaction Projects by individual countries. Montgomery Ward Perry Williams Campbell The Direct Liquefaction Monitor described the develop- Putnam Carbon Randolph ments by nation of planned or ongoing international Ohio Converse projects as follows: St. Clair Johnson Saline Athens Lincoln Australia: Sangamon Belmont Sheridan Washington Carroll According to officials of Australia's Broken Hill Proprie- White Columbiana tary Company two or three coal liquefaction plants Harrison could be in operation in the country in the 1980s. Indiana: Jefferson Suitable sites have been identified in Newcastle, New Meigs South Wales, and in Victoria and Queensland. Gobson Monroe Knox Morgan Two projects - both advanced by Japan - are under Posey Muskingum consideration by officials in Victoria. One has been Sullivan Noble suggested by Nippon Brown Coal Liquefaction Company, Vanderburgh Perry and the other by Mitsui and Company, which seeks to Vermillion Stark produce solvent-refined coal for use in Japanese steel Vigo Tuscarawas furnaces. Warrick

In addition, Arco Australia Ltd. is financing a feasibility SOURCE: Bureau of Mines, U.S. Geological Survey, study of a liquefaction plant that would use brown coal SRI International. from the only privately owned deposit in Victoria.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-19

TABLE 6 BILATERAL COAL GASIFICATION PROJECTS

Companies Source of Countries Subtechnology Product Size Involved Status Funding U.S. Department of Energy (DOE/ West Germany Ludwigshafen, Methanol Ethylene, Will produce BASF, Mobil Completed Participants will West Germany synthesis propylene 396,000 ibId Oil Co., in Spring share in $1.6 of synthetic linde, 1980 million in cost liquids URBK DOE/ West Germany Wesseling, West M-gasoline Gasoline Will convert Mobil, Planned Participants will Germany 100 b/d of two West share equally in $33 methanol German firms million costs

Belgium/ West Germany Hensies, In situ Low- to -- -- Planned Part of a 1976 cost Belgium medium-Btu cost sharing agree- gas ment between Belgium and West Germany TABLE 7

COAL GASIFICATION AND INDIRECT LIQUEFACTION PROJECTS BY INDIVIDUAL COUNTRIES

Country Subtechnology Product Size Companies Involved Status South Africa Sasolburg Lurgi/Fischer- Oil, solid 20,000 Sasol I Started-up in Tropsch waxes, diesel, liquid 1955 gasoline fuels

Secunda LurgilFischer- Transportation 40,000 bbl Sasol II Full production Tropsch fuels, tar of liquid in 1982 products, fuels per ammonia, day sulfur

Sasolburg Lurgi/Fischer- Transportation More than Sasol III Full production Tropsch fuels 50,000 bbl in 1984 of liquid fuels

Modder Fontein Koppers-Totzek Medium-Btu 88 MMSCF/ African Explosive Analysis of gas, ammonia day, Chemicals Industry; technology near 1,000 tpd Krupp-Koppers, GmbH completion (Essen, West Germany); McLachlan & Lager, Ltd. (South Africa); TRW, Inc. West Germany

Oberhausen-Holten Texaco Synthesis gas Pilot Plant Ruhrgas AG Start-up in entrained-bed (819,670 tpd) Ruhrkohle AG/Steag AG 1976

4-20 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 TABLE 7 (Continued) Country Subtechnology Product Size Companies Involved Status West Germany (cont.) Fuerstenhausen/Saar Saarberg/Otto Synthesis and Pilot plant Saarbergwerke AG, 1978-1982 slag bath reduction gas (250 tpd) Cr. C. Otto & Co. gasification GmbH

Frechen (Cologne) Reinbaum HTW Synthesis gas Pilot plant Heochst-Uhde, Start-up in (Winkler) (132.3 tpd) Rheinisehe, Braun mid-1978 Kohlenwerke AG Dortmund yEW process Electric power Pilot plant Vereinigte Elektri- (24 tpd); zitatswerke, Westfalen demonstration AG plant (360 tpd) Netherlands Moerdijk Shell-Hoppers Synthesis gas 1,000 tpd Royal Dutch/Shell Start-up in late 1983 Rotterdam Texaco Electricity One gasifier City of Rotterdam, Design scheduled and one Rotterdam Energy for completion 25 MW gas Utility (GEB), by end of 1980; turbine fol- Arnheim Electrical first stage of lowed by a Testing Laboratory project to begin second gasi- Laboratory (KEMA) operating in fier and gas 1986, second turbine and stage in 1989 a steam turbine Belgium 1-lensies In situ Synthesis or Pilot plant Institut pour le Start-up in combustion gas Development de la late 1981 Gazeification Souter- raine; S.A. (Coppee- Rust: N.V. (Leige division) Brazil Sao Jeronimo Koppers-Totzek Gas for pro- Will even- Petrobras, Rrupp- Start-up in duction of tually become Hoppers 1982 ammonia and a large chemi- later for home cal complex use Japan Iwaki City Hitachi Japan Electric Power Construction Development Company began Dec. 1979 Poland Libiaz (outside Katowice) Koppers-Totzek Medium-Btu gas Three 4-head Kopex (Poland's state Construction gasifiers agency); Krupp Hoppers to begin in 1982; GrnbH. Separator (state start-up in owned engineering office) 1984

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-21 TABLE 7 (Continued)

Country Subtechnology Product Size Companies Involved Status Canada Manalta Coal, Ltd., In situ Alberta Research 5-year test is Vesta mine (90 mi. Council, 4 government planned, but southeast Edmonton, agencies, 11 industry details are still Alberta) participants being negotiated Great Britain Entrained flow Pilot plant British Gas Corporation To be designed gasifier coupled (100 tpd) (BGC), British Dept. constructed, with base of of Energy and operated fixed bed gasifier over a 6-year (composite gasifier) period

Yugoslavia Lurgi Medium-Btu 25 MMSCF/ Kosovo combine/ Phases II and (East Germany) gas (for com- day gasification plant, III (analytical bustion); Kosovo Institute; work) being hydrogen (for 21.5 MMSCF/ Mining Institute finalized; Phase ammonia syn- day of Belgrade; IV (study thesis Radium Corp. of of fugitive emis- Texas; Insitute of sions) on-going Applied Nuclear Energy of Belgrade

TABLE 8

MULTILATERAL DIRECT COAL LIQUEFACTION PROJECTS

Project/ Location Subtechnology Product Size Operator Status United States/Japan! To be Synthetic fuel 60,000 bpdoe Mitsui (Japan), Amax Feasibility study United Kingdom determined (United States), to be completed Australian firms, by June 1981; British Petroleum construction to start mid-1981. Milmerrean coal has been extensively tested, eliminating pilot plant stage.

United States/West SRC-fl - naphtha 20.000 bpdoe Gulf Oil Corp. (United Completion Germany/Japan - low-sulfur States), Ruhrkohle AG expected by Sept. oil (West Germany), Mitsui 1984; operation (Japan); Japan and in demonstration Germany to finance phase to be corn- $350 million; Gulf to pleted by March invest up to $100,000; 1987. At end of U.S.DOE will 24-year operation contribute about period, operator $700 million will have option to purchase plant.

United States/West Exxon - LPG 605 bpdoe Exxon, Phillips Petro- Construction Germany/Japan Donor - naphtha leum Company, Atlantic completed in Solvent - fuel oil Richfield. Funding pro- March 1980; Baytown, Texas - gas vided by Japan Coal initial coal- Liquefaction Develop- in operation ment Corp., West began June 1980. Germany's Ruhrkohle AG, and U.S. DOE and EPRI.

4-22 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE 9 BILATERAL DIRECT COAL LIQUEFACTION PROJECTS

Project/Location Subtechnology Product Size Operator/Contact Status Australia/Japan Exxon Donor - LPG 1.21 bpdoe Australian Coal Corp. Preliminary Solvent - naphtha Nippon Brown Coal study under way. Wandoan, central - fuel oil Liquefaction Company Construction and operation to be completed by 1983. Australia/Japan SRC 20.000 bpdoe Victoria Brown Coal A 2-year feasi- Committee, Mitsui bility study is La Trobe Valley Coal Liquefaction Co. planned. Opera- (brown coal), tion estimated Victoria to begin in 1986. China/Japan To be determined Mitsui Corporation; Discussions under China will spend way for joint Yiminhe open pit $6 million to estab- venture to build coal mine in Inner lish first bench-scale coal liquefaction Mongolia liquefaction unit and plant at Viminhe; pilot plant. SRC-1 and -Il processes are favored; EDS process also being considered.

Japan/Canada H-coal process - hydrocarbon gas 50,000 bpdoe Petro-Canada, British Several liquefac- - hydrogen sulfide Columbia Resources tion processes Vancouver, British - ammonia Investment Corp., being considered; Columbia - light distillate West Coast Transmis- H-coal likely - heavy distillate sion; two Japanese candidate. - residual fuel firms.

TABLE 10

DIRECT COAL LIQUEFACTION BY INDIVIDUAL COUNTRIES

Project/Location Subtechnology Product Size Operator /Contact Status Australia Modified Fluor's 100.000 bpdoe Broken Hill Proprietary If study approved, consol donor operation will solvent begin in late 19801s. United Kingdom Liquid solvent Heavy 61 bpdoe U.K. Department of Construction to extraction products Energy begin before end of 1980; finali- Super-critical gas British Petroleum (BP) zation of a cost- solvent extraction Co. sharing agreement National Coal Board among U.K. DOE, (NCB) BP, and NCB is awaited at present. Soviet Union 2.75 bpdoe Construction of Soviet Union's first coal liquefaction plant is underway. Plans being developed for a facility which will produce 75 metric tonnes per day.

SOURCE: Financial Times, International Coal Report; Pace Company Consultants & Engineers, Inc., Cameron Synthetic Fuels Report; Synfuels.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-23 Canada: project was initiated to develop special techniques for liquefying Australia's abundant brown coal reserves. The Canadian federal government is attempting to develop its western coal reserves by inviting foreign investors People's Republic of China: to establish commercial coal conversion facilities in western Canada. Canada's federally owned oil company. The People's Republic of China (PRC) favors the solvent Petro-Canada, is expected to take the lead in developing refined coal process for alternative fuels development. coal liquefaction and gasification plants, followed by The PRC chose this process after a year's research in other Canadian companies and Japanese firms. In addi- Kentucky by a team of Chinese coal scientists. The tion, Canada's federal energy minister expects West nation is promoting the development of coal-based alter- Germany to show interest in developing the western native fuels because they would provide clean energy and reserves. Although Canadian legislation currently prohi- could thus alleviate recent air pollution problems bits the export of most energy fuels, the federal govern- created by coal-fired oower plants. The PRC has even ment plans to exempt coal-derived fuels. established a new university dedicated to modernizing coal production and conversion methods. At present, a I tal V joint Sino-Japanese venture is under consideration for the construction of n coal liquefaction plant at a new Italy's national hydrocarbon agency. ENI, has discussed open pit mine in Inner Mongolia. with DOE the possibility of entering into joint alternative fuels ventures. Although the discussions between West Germany: ENI's U.S. subsidiary and DOE have been closed, it is believed that coal conversion technologies are being Although West Germany is not currently developing a èonsidered, particularly in 'light of -Italy's abundance of domestic direct coal liquefaction industry, it is a mem- coal reserves. Reports indicate that DOE has tried to ber of a consortia involved iii two direct coal liquefac- involve ENI in an equity partnership arrangement for the tion projects in the United States: the SRC-It demon- SRC-1 demonstration plant. DOE officials have not yet stration facilit y in Morgantown, West Virginia and the resumed discussions, and it is not known whether a Exxon Donor Solvent project in Baytown, Texas. West similar arrangement will he discussed for the SRC-11 Germany will finance Ruhrkohle AG's 25-percent demonstration plant. So far, ENI and DOE have not interest in the joint venture company formed for SRC-11 concluded any arrangements. project development and the 4-percent interest in the Exxon Donor Solvent cooperative agreement. The Italian firm of Agip has joined the cooperative arrangement of U.S.. Japanese, and West German com- Comment: The report's description of the German in- panies that, together with DOE, are sponsoring the volvement might lead to the conclusion that Germany is Exxon Donor Solvent process. Agip plans to contribute not supporting an y liquefaction projects in Germany. more than $7 million to the program. This is not true. See page 4-6 of the March 1980 Cameron Synthetic Fuels Report for a detailed deserio- Japan tion of all of the German Coal Conversion Projects. Contraction of a 200 ton per day catalytic coal hydro- In October of 1980. Japan's Ministry of International genation plant is currently underwa y in Bottrop. Saar- Trade and Industry (MITI) created the New Energy bergwerke AG is currently constructing a pilot plant General Development Agency (NEGDA), a quasigovern- with a coal throughput of 6 TPD to test the Saarberg mental agency responsible for fostering alternative process. energy development in Japan. NEGDA will provide financing for solar, geothermal, hydrogen, and coal technologies. Initial emphasis will be placed on coal conversion technologies by providing financial aid to locate and GAS PRICE DECONTROL PROMOTES COAL evaluate potential coal sources together with guaranteed GASIFICATION FOR NH 3 PRODUCTION loans for development of the coal. MITI has authorized NEGDA to allocate almost $50 million for coal liquefac- Ammonia producers in the U.S are anticipated to operate tion and $18.4 million for exploration and development at 90 percent of capacity this year, down slightly from of foreign coal mines. The goal of NEGDA is to supply S the 92 percent capacity operations they realized in 1980. percent of Japan's energy needs by 1990, with a production target of 290,000 bpd (5 plants) of coal liquids by Ammonia producers depend upon steam reforming of 1990 and 500,000 hpd by 1995. Japanese officials believe natural gas to provide the synthesis gas from which that coal-based alternative fuels offer the most feasible hydrogen is obtained to manufacture ammonia. The alternative energy technologies for Japan over the next decontrol of U.S natural gas prices portends increased 10-15 years, a departure from earlier Japanese efforts costs of production for ammonia manufacturers. While that emphasized solar and geothermal energy. U.S ammonia producers are not yet looking seriously at coal gasification as a means to supplement or replace Japan has entered into several multilateral and bilateral natural gas feedstock. any large increase in natural gas direct coal liquefaction projects. Of the two multi- prices will hasten the day when conversion to coal lateral projects. one - a feasibility study - involves the becomes feasible. United States and Britain; the second, a demonstration L.L. Jaequier, of W.R. Grace Company's Agricultural project, involves the United States and West Germany. y Japan's partners in the various bilateral projects include Chemicals Group stateg recentl that if natural gas Australia, Canada, and China. The Japanese-Australian prices rise to $611000 ft , the production cost of a ton of

4-24 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 3. ammonia will be $270. If prices rise to $1211000 ft the Plant Configuration Described production cost will be $500 per ton. During 1980, however, the contract price for ammonia was $107 per North Dakota lignite is received from the mine at the ton, but in certain areas, the price reached as high as plant site and is crushed, dried and fed to the Winkler $155. The natural gas requirement for producing am- Gasification system. With the addition of ox ygen and monia ranges from abut 33,000 to 27,000 cubic feet per steam, the coal is gasified in the fluidized bed Winkler ton of ammonia produced gasifier. The gasifier effluent is cooled in a heat recovery train generating high pressure steam and then Despite the relatively high operating rates of U.S. am- quenched with water for particulate removal. The raw monia plants, high prices for ammonia product, and good gas is compressed and fed to the shift conversion step to growth forecasts, there is no rush to build new ammonia generate additional amounts of hydrogen from carbon plants in the U.S. Decontrol of natural gas prices by monoxide and steam which results in a stoichiometric 1985 is a factor in causing the reticence to build plants. ratio of carbon and hydrogen. The gas is then treated in Most long-term, low-cost gas supply contracts will have the Acid Gas Removal Unit (Rectisol) to selectively expired by 1985, and ammonia producers will be paying remove hydrogen sulfide and carbon dioxide. From here "top dollar" for their gas supplies. the gas passes through Chloride and Sulfur Guard Beds to remove traces of chloride and sulfur compounds and then The U.S. has changed from being an exporter of ammonia is further compressed to the methanol synthesis loop as a into being a net importer. Three times as much make-up synthesis gas. ammonia is now imported as is exported. One company alone, Occidental Petroleum Corporation, anticipates it The make-up gas enters the synthesis loop at the suction will bring 2.8 million tons of ammonia into the U.S. in of the circulator and is mixed with the recycle gas. The 1981 from the USSR. mixture of the gases is then passed through the methanol converter where the reaction of carbon oxides and Despite the estimate that the U.S. industry will operate hydrogen to methanol takes place. The converter ef- at 90 percent of capacity this year, some thirty U.S. fluent gas is cooled in a heat recovery train, followed by ammonia plants have been shut down since 1975. It final cooling and crude methanol condensation. Crude seems that instead of providing new plants, the U.S. methanol is then distilled in a one column distillation industry will provide for new imports. section to remove the water. Fuel grade methanol is then transferred to the storage tanks. Just when or where coal gasification will be utilized for ammonia manufacture in the U.S. is not clear. TVA A number of ancillary process units are required to operates a small Texaco partial oxidation process coal provide an environmentally acceptable design and to gasifier to provide part of the gas feedstock for an allow the reuse of the water in the process units. existing 225 T/Day ammonia plant at Muscle Shoals. Contaminated process condensate and water recovered Alabama. This facility was described in the June 1979 from the drying units and other various process units are issues of Synthetic Fuels, page 4-8. We believe the treated in the water treatment section. An acid gas opportunity for coal gasification to become competitive stream, containing hydrogen sulfide, from Acid Gas in the ammonia industry may well occur in the Midwest, Removal is converted into elemental liquid sulfur in the where much ammonia is used, where coal is readily Claus plant. Flue gases from coal boilers, coal drying available, and where dedicated ammonia pipeline trans- units, and the incinerated tail gas from the Claus unit portation will improve overall economics. At the mo- are sent to the Flue Gas Desulfurization unit where most ment, however, the impetus is toward building ammonia of the SO is removed before the gas is discharged to the plants in foreign countries where natural gas is very atmosphere. cheap. Oxygen required for the gasification units is provided from an Air Separation unit. This unit also supplies nitrogen as inert gas required for coal preparation, EPRI STUDIES METHANOL PRODUCTION conve ying systems, instrumentation, and other utility VIA WINKLER GASIFICATION AND users. A Raw Water treatment unit is also included. ICI GAS SYNTHESIS This complex is designed to be self-sufficient with respect to all utility services, offsites, and other support The Electric Power Research Institute, on behalf of the facilities, including power generation. major U.S. utility companies interested in methanol as a fuel for the generation of peaking electric power, is Study Results Summarized evaluating several coal-to-methanol processing routes. EPRI has just published the results of its work in The plant thermal efficiency is calculated as the ratio of developing a conceptual design, capital requirements, the higher heating value (I-mv) of the methanol pro- and product cost for a lignite-to-methanol plant incor- duced to the total UHV of lignite as received to the porating Winkler gasification technology and ICI metha- plant: nol synthesis. Such information is useful for comparing various coal-to-methanol processing routes. The report. I-fflV Methanol - Plant Thermal EPRI AP-1592. is entitled, "Lignite-to-Methanol: An HHV "As received Lignite" x 10 - Energy Engineering Evaluation of the Winkler Gasification and ICI Methanol Synthesis Route." There is no other energy input to the plant. Sulfur produced as a byproduct was not considered in this efficiency calculation. The plant thermal efficiency is 47.4 percent.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-25 Other results of the study include: Output lb/hr

• Lignite Feedstock and Fuel Methanol 1,259,479 47.770 (as received), TPD Sulfur 29,829 • Fuel Grade Methanol Product, TPD 15.000 Utility & Potable Water 50.000 Ash to Landfill 491,219 • Plant investment, expressed in terms of first quarter of 1980, $ Million 1,545 Gypsum 36.295 Steam Ejector Loss 20.000 • Applying the economic premises used by EPRI for fuel conversion plant utility Vent Exhausts 14,787.011 type financing, the calculated levelized TOTAL 16,673.833 and first year product costs areas follows:

s/Million The total plant capital requirements were determined to Btu, HFIV be as follows: (Thousands of 1st Quarter 1980 dollars) Levelized for 30 years of operation, - including 6% annual rate of inflation on O&M cost items 7.72 Lignite Preparation and Handling $ 94,700 Gasification and Water Heat Recovery 122.300 First Year of Operation 4.10 Particulate Removal and Gas Cooling (1985) Raw Gas Compression 82,000 The North Dakota lignite, as received, contains 35.2 Gas Shift Conversion 26.200 percent moisture and was dried to 8 percent moisture before the gasification process. In order to assist EPRI Acid Gas Removal, Chloride and Sulfur 305,700 in the evaluation of the coal-to-methanol processing Guard, Make Up Gas (MUG) Compression. routes, the thermal efficiency was also calculated as if Methanol Synthesis, Distillation, and the same lignite contained only 10 percent moisture Hydrogen Recovery similar' to that of the Illinois No. 6 Coal. For this Davy S/H Flue Gas Desulfurization 30.300 purpe. it was assumed that the plant power require- Sulfur Recovery (Claus Process) ment will be unchanged and the coal to the dryer will be the only modification required. The following table Cooling Water 152.800 summarizes the plant thermal efficiency at the different Utilities and Offsites 395.300 moisture contents of the feedstock: - Installed Cost 1,209,300 Moisture Content Engineering and Home Office Cost 195.000 of Lignite Wt 35.22 10 Subtotal 1,404.300 Contingency 140.400 IN: Total Plant Investment 1,544.700 Lignite as received, LB/hr 3,9819391 2,704,830 Initial Charge of Catalyst and Chemicals 27.600 Heat of combustion, Btu/Lb(HHV) 6.460 8,975 Fee Allowance 7.000 Total Heat Input, Preproduction Costs 41.600 MBTU/Hr (HHV) 25,720 24.276 Inventor y Capital 57.600 OUT: Allowance for Funds During Construction 278.000 Fuel Grade Methanol, LB/hr 1,259,479 1.259,479 Land 1.400 Heat of combustion. Total Capital Requirement $ 1,957,900 Btu/Lb(HHV) 9,687 9,687 Total Heat Output, MBTU/I-Ir(IiHV) 12,200 12,200 # Thermal Efficiency, % 47.4 50.3 A total mass balance summar y follows: WELLMAN DESIGNS AND BUILDS SMALL GASIFIERS IN THE U.S. Input lb/hr Small capacity gasifiers are available in the U.S. from As Received Coal 3.981.391 the Wellman Thermal Systems Corporation. The capacities of their single gasifier units range from a minimum Air 12,373,373 of 20 million Btu/hour to a maximum of about 100 Lime 9,420 million Btu/hour. Their manufacturing facilities are located in Shelbyville, Indiana. Brief descriptions of Raw Water 309,649 Wellman gasifiers follow, under separate headings: TOTAL 16,673,833 4-26 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981

Weliman's 2-Stage Gas Producer is Most Versatile Model combustion, gasification, and devolatilization all occur in the one moving bed, and products from all three of The Wellman Thermal Systems Corporation's 2-stage these processes exit the gasifier as a single stream. gasifier is the most-advanced unit offered by the company. It's salient features are illustrated in Figure 1. The single-stage gasifier was developed many years ago to handle coke or anthracite coal as feed. When interest This gasifier processes coal having a top size of about developed in gasifying bituminous and other ranks of coal three inches and containing not more than about 15 which contain large amounts of volatile materials, the 2- weight percent minus-1/2-inch material. Coal is fed into stage gasifier was developed However, the 1-stage the top of the distillation zone and gravitates downward model gasifies coals containing volatiles, the condensible through the distillation, gasification, and combustion liquids merely accompany the off-gas stream. Gas zones. The rate of flow of solids is controlled by the treatment (tar removal, sulfur removal, etc.) schemes grate mechanism. will vary, being dependent upon the desired use of the gas product. Air, steam, and sometimes oxygen (if desired) enter at the bottom of the vessel and now upward There are Wellman coal gasifiers yield fuel gas products which two gas offtakes which can be utilized. Distillation zone range from 120 to 450 Btu/SCF, depending on the coal gases can exit the gasifier via the top gas offtake. feed characteristics and the off-gas treatment processes These high-analyses gases contain condensible tars. utilized. Gasification zone gases can exit via the bottom gas offtake. These gases are of lower Btu value, but are essentiall y free of condensible tars. PROCEEDINGS OF WORKSHOP ON CRITICAL COAL In the gasification zone, carbon remaining after distilla- CONVERSION EQUIPMENT PUBLISHED BY ESCOE tion of volatiles from the coal is completed, reacts with air (oxygen) and steam to produce CO. H • and some The Engineering Societies Commission on Energy, Inc. CO 2* The combustion zone in the lower Jction gene- (ESCOE) has published the Proceedings of the Workshop rates the heat required for the gasification and devolati- on Critical Coal Conversion Equipment which was held in lization processes. Huntington, West Virginia in October 1980. The workshop was sponsored jointly by ESCOE and the DOE. The The Single-Stage Model is Simpler Proceedings are available from NTIS as Document Num- ber FE-2468-88. Wellman's single-stage model accepts feed coal of the same size range as does the 2-stage model. However. Each session of the workshop concerned the equipment available for specific operations, such as slurry pumps, heat transfer equipment, expanders/compressor, and coal feeders. At each session, presentations were made COAL S concerning the state-of-the-art. Post-meeting reviews were made of the presented data, and conclusions were drawn. Some 225 participants reach a general consensus -- - COAL on three matters, which were: Construction and operation of demonstration plants will not be generally delayed by the TOP GAS *CE^L unavailability of components for their con- OFFTAKE struction. This mostly favorable conclusion is possible in part because the plants are - DISTILLATIoN eCHO.. -- ZONE being designed with careful consideration of GAS S the limitations of present hardware, but non- o FFTAK F optimal designs may result.

GASIFICATION ZONE Operability of coal conversion plants to be built in the near future will be constrained by the necessity of using some hardware items which have not been proven by demonstration CO M8US lION for significant times under realistic plant or ZONE test conditions. This will possibly result in decreased operating costs and reduced production rates during the early years of opera- ASH tion. j_ -_, PAN AIRS - Detailed design data and design practices for STEAM S coal conversion plants are not fully documented. Of most immediate concern are FIGURE I factors affecting operability and reliability THE WELLMAN TWO-STAGE COAL GASIFIER such as erosion, corrosion and fouling.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-27 Coal Slurry Pump Equipment is Adequate hydrogen, centrifugal compressors require a large number of stages. Concerning coal slurry pumping equipment, there are unique requirements in coal liquefaction and gasification Fans and blowers for high volume, low head, dirty gas applications. These include the need for protected seals, applications are expected to be available; however, ero- ruggedness, continuous duty, high reliability, long life, sion and corrosion may be a problem. and, for hot oil slurry applications, combined technology with both API-610 features and slurry pump features. Expanders will be required in only one of the currently General experience with slurry pumping machinery in active demonstration projects: COGAS. This applica- coal conversion to date is short life. Reasons have been tion, with an inlet pressure of about 75 psig, will inadequate process information, inadequate equipment probably require an expander with at least two stages. availability, improper pump selection and/or inadequate Expander experience with dirty gases is currently limited pump down-rating. Use of proper categories of abrasion essentially to single-stage fluidized catalytic cracking can be useful in down-rating pumps. (FCC) units; however, the similarity in erosion characteristics of FCC catalyst particles and the coal/ash The major t ypes of slurry pumping application in coal particles resulting from coal conversion reactors is un- conversion are aqueous slurr y, low head oil slurry ( P = known. 100 - ISO psi), oil slurry with high inlet pressure (> 600 psia), high viscosity slurr y (800 - 600,000 cp). and high Mechanical Feeders are Being Developed head oil slurry pumps (6 P >600 psi). Coal feeding is one of the critical steps common to all With some reservations, it is believed that most of the coal conversion processes such as gasification, liquefac- slurr y pumping- applications can currently be satisfied tion and fluidized bed combustion. This is the mechani- with adequate equipment, provided conservative design cal means by -which coal, at -essentiall y atmospheric principles and proper quality assurance procedures are pressure, is injected into vessels operating under pres- implemented and followed However, expected lifetime sures tip to 2000 pounds per square inch and higher. The of slurry pumps in coal conversion may not be as long as mechanical goals are challenging. The continuous dry can be expected for clean liquid pumps in petroleum feeding of a variety of coal sizes and types at flow rates refineries, and maintenance cost obviously will be much of 50 to 250 tons per hour must be accomplished for higher. demonstration and commercial-size plants.

Data for Heat Exchanger Design is Scarce For liquefaction in processes such as H-Coal and SRC-I and -Il, reciprocating slurry pumps are primarily used in The data base for heat exchange equipment in coal current practice. The dr y coal must be slurried with conversion is relatively slender, especially for the two recycle oils or water. most problematic stream types - hot coal/oil slurries (with and without concurrently flowing I-I, - rich gas), In first generation gasifiers, such as the Lurgi installa- and hot dirty gases. In coal conversion pilot plants, heat tions at Sasol. lockhoppers are used. Pressures of about recovery has generally been ignored or minimized, with 450 psig are normal. Lump coal is fed dry in a cyclic emphasis on obtaining process data and experience with process. In several second generation gasifiers such as other critical components. In demonstration and com- SYNTHANE and COGAS, lockhoppers also are used. mercial plants, extensive heat interchange will be re- Designed to operate up to 1000psig, these pressures were quired to increase the overall thermal efficiency in order not achieved on a continuing basis. A few processes such to minimize product costs. The broad conclusions were a HYGAS and BIGAS have used reciprocating slurry that fabrication capabilities are adequate; and that de- umps up to pressures of about 1150 psig. Third genera-p sign, especially on the process side, is difficult because tion pilot unit processes such as the Exxon Catalytic of the sparsity of physical-property and transfer-rate seem to be heading toward lower pressures (than the data and correlations. second generation) and are also using loekhopper systems for the present time. The demonstration sized plants Compressor Technology is Well Developed such as ICGG. COGAS and Conoco Slagging Lurgi also are slated to use lockhopper type systems. Compressorsare generally available for most critical applications in coal conversion. Centrifugal oxygen In atmospheric fluidized bed combustors, combination compressor availability is demonstrated in commercial mechanical feeding with pneumatic assist is used at the service to about 960 psia at a flow rate of 1500 tpd. Rivesville installation. Overfeed stokers are used at Reciprocating compressors can supply 700 tpcl at 1200 Georgetown. Flow splitting to achieve uniformity of psia. An agreement has been reached between DOE, feed has been a problem. DEMAG, and Rockwell to demonstrate a 1200 tpd "third easing" capable of about 1700 psia outlet pressure. Most planning demonstration plant requirements for oxygen can be met with existing equipment in parallel trains, while design pressures are being decreased to levels of demonstrated availability. Hydrogen compressors are available in either reciprocating or centrifugal designs for specified flow rates and pressures. Because of the low molecular weight of

4-28 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 ECONOMICS

ECONOMICS OF METHANOL AND/OR GASOLINE FROM 24,000 and 42,500 BPSD, respectively. In all eases, WYODAK COAL VIA LURCH GASIFICATION EVALUATED steam and power were generated onsite using coal-fired boilers with flue gas desulfurization. The Oak Ridge National Laboratory has published the results of the first phase of a technical and economic To investigate the effect of economies of scale, an assessment of coal liquefaction technologies which it is additional methanol production case was studied which conducting for the Department of Energy (under Con- was similar to Case B-2, except that the plant size was tract W-7405-ENG-206). Entitled, "Liquefaction Tech- reduced by a factor of 4. nology Assessment - Phase I: Indirect Liquefaction of Coal to Methanol and Gasoline Using Available Tech- Process designs, equipment summaries, cost estimates, nology," the report may be further identified by its and operating requirements were prepared by Fluor Engi- number, ORNL-5664. neers and Constructors, under a subcontract to ORNL. A condensed version of Fluor's work was included in the This first phase investigation covers indirect liquefaction ORNL report as an Appendix. of a western United States subbituminous coal using Lurgi dry-ash gasifiers. Major liquefaction technologies Economic calculations to determine product prices under employed were ICI low-pressure methanol synthesis and various conditions were made by ORNL using Fluor's Mobil-MTG conversion of methanol to gasoline. Four capital costs and operating requirements. Base-case major cases were studied, representing the following economic conditions included tOO percent equity financ- product slates: ing at 12 percent annual after-tax return on equity, no inflation, and a coal price of $1.00/10 Btu. The product Case B-i. Dry methanol (0.1 percent water) plus price corresponds to a production cost at the plant gate SNG, and includes taxes and return on investment Case B-2. Moist methanol (2 percent water) plus Production rates and base-case product prices are sum- substitute natural gas (SNG). marized in Table 1. Table 2 presents the basis for Case C-i. Maximum gasoline (by conversion of process design, and Table 3 summarizes the economic tOO percent of the SNG to synthesis gas), base conditions. Case C-2. Gasoline plus SNG. In the fifth case (methanol production in a 1/4-scale plant similar to Case B-2), the total capital investment Minor products included propane/butane LPG, crude was estimated to be $816 million and the methanol price diesel fuel, phenols, and ammonia. was $0.87/gaL This represents a substantial increase from the Case B-2 price of $0.56/gal. The costs The four cases investigated are similar in that the coal is correspond to a scaling factor of 0.65. gasified in all cases, and the resulting gases are shifted, treated to remove acid gases, and then passed through a Economic sensitivity studies showed that the two factors methanol synthesis reactor to produce methanol, either having the greatest influence on product price were the as a final product or as an intermediate product. By- method of financing and the inclusion of escalation or product SNG, crude diesel fuel. naphtha. and phenols are inflation. also produced The methanol is fractionated in Case 11-2 to produce a material containing <2 wt percent water, which is suitable for turbine fuel. In Case B-I. the water content of the methanol stream is reduced to <0.1 wt percent so that it may be used for blending wifh gasoline. In Case C-2. the methanol product is converted to gasoline-range hydrocarbons through use of the Mobil MTG process. In Case C-i a catalytic reforming operation is added to Case C-2 to convert most of the methanol synthesis purge gas to syngas, which is then used to produce additional methanol and, subsequently. gasoline.

In each case, the economic study was based on the detailed process design of a conceptual self-sufficient commercial facility using a coal feed rate to the gasifiers of 16,000 tons per stream da y (TPSD) on a moisture- and ash-free basis. This corresponds to a total as- received coal feed rate of about 30,000 TPSD to the facility. Methanol production rates in Cases B-2 and B-I were about 53,000 barrels per stream day (BPSD). Gaso- line production rates in Cases C-2 and C-I were about

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-29 TABLE 1

PRODUCTS AND PRODUCTION COSTS (Mid-1979 Dollars)

Methanol Production Gasoline Production With Maximized For Turbine- For Gasoline Co-Production By Reforming Grade Fuel Blending of SNG SNG Case Description (Case 8-2) (Case 8-1) (Case C-2) (Case C-I) Major Products Methanol, BPSD 53,500 52,770 Gasoline6 BPSD 24,160 42,580 SNG, 106 153 153 159 19 Propane LPG, BPSD 1,240 2,165 Butanes LPG, BPSD 2,200 3.460 Naphtha, BPSD 1,380 1,380 Crude diesel, BPSI 3,900 3,900 3,900 3.900 Crude phenols, 10 lb/SD 384 384 384 384 Ammonia, TPSD 110 110 110 110 Power, MW 0 0 0 14.3 Coal Feed Rate, TPSD of rnaf coal Coal to gasifiers 16,000 16,000 16,000 16,000 Coal to power plant 4,210 4,210 4,321 5,702 Total coal feed 20.210 20,210 20.321 21,702

Total Capital Cost, s106 2.145 29147 2,326 2,798

Annual Operating Cost, $106 331.1 331.2 340.6 375.7 Overall Thermal Efficiency 64.8 64.8 61.6 50.4 Production Prices For Base Case Methanol, $/gal ($Il%6 Btu) 0.56 (8.81) 0.57 (8.81) Gasoline, gal ($110 Btu) 1.25 (10.88) 1.59 (13.87) 514G. $/10 Btu 8.02 8.02 8.70 11.10 Overall average product cost, $/bbl FOE 49.64 49.64 56.41 78.44

TABLE 2 TABLE 3 BASIS FOR PROCESS DESIGN ECONOMIC BASE CONDITIONS

Feed coal type Wyodak Percentage of equity financing 100 Feed coal quality Annual after-tax rate of return on equit y. % 12 to gasifier TPSD 16,000 Operating life, yr 25 Gasifier type Mark IV Lurgi dry ash Construction period. yr 5 Federal income tax rate. 96 48 Plant location Northeast Wyoming State income tax rate, 96 3 Power produced for sale None Local property tax and insurance cost, 2.75 Char produced for sale None Estimating allowance, 96 20 Depreciation method Sum of years Preferred cooling medium Air digits over 16 year Environmental constraints Zero wastewater discharge; solid waste disposal consis- Coal cost, $110 Btu tent with proposed RCRA Dollar value base Mid-1979 guidelines; conformity with proposed NSPS air standards. apercentage of total depreciable capital

4-30 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 ENERGY POLICY AND FORECASTS

CONGRESSIONAL RESEARCH SERVICE REPORTS ON lives to promote commercialization; (3) numerous OUTLOOK FOR COMMERCIALIZATION OF COAL- institutional, environmental, and regulatory uncer- BASED SYNFUEI.S INDUSTRY tainties must still be addressed; and (4) labor and materials constraints and the lead time in opening The Congressional Research Service released a study in up new coal mines and in orderiag equipment most January focusing on the role of the Federal government be considered" in the commercialization process of the emerging coal- based synfuels industry. The study "Synfuels from Coal The potential impacts of gasification and liquefaction and the National S ynfuels Production Program: Tech- processes are reviewed in the report. Pollution control nical. Environmental, and Economic Aspects," was pre- and occupation and health problems are discussed in pared at the request of the Senate Committee on Energy detail with sources well documented Some potential and Natural Resources, it is an update of the 1979 advantages of synfuels plants are provided, while the Committee Report "Synthetic Fuels from Coal: Status environmental problems that will be encounters are also and Outlook of Coal Gasification and Liquefaction." The addressed. earlier study was reviewed on page 4-14 of the Decem- ber 1979 Cameron Synthetic Fuels Report. The most notable conclusion of the report is that: The most recent study examines the technical, environ- "Provided adequate control technology is used, the mental. economic and public policy aspects of producing overall potential of pollution appears to be signifi- synfuels from coal and provides background information cantly less for synfuels production than if coal and analysis on the National Synftiels Production Pro- were burned in power plants scattered over wide gram and the role of coal-based synfuels in this Program. geographical areas. It also appears that impending (For a review of the Program see page 1-4 of the environmental regulations may have considerable September Cameron Synthetic Fuels Report). A variety impact upon the synfuels industry, although the of options to promote synfuels commercialization and to magnitude of the impact is uncertain. Indeed, it is improve the Federal role in this process is also pre- this uncertainty as much as anything that causes sented Several areas, issues, and potential problems industry considerable concern." that might be considered during future congressional oversight hearings are identified Comment: The political uncertainty has increased with the actions of the Reagan administration. While the The report describes the liquefaction and gasification report only became available in the Spring, the actions processes that could be commercial with either DOE or of the new Administration have rendered much of the Synthetic Fuels Corporation (SFC) support. The DOE's information in the report, if not entirely obsolete, at R&D program under the previous administration is least outdated. This is especially true for the descrip- detailed tion of the DOE's and the SFC's role in the National Synfuels Program. Funding for many of the DOE pro- The report concludes that, if the first gasification programs is currently in doubt, and will be determined by ject (Great Plains) were commercialized by 1985. and if congressional actions. Lack of Administrative action the Federal Government, including DOE and SFC. pro- regarding the SFC has caused concern in the industry, vides substantial economic or regulatory incentives for (see the General Section of this report for a related several additional projects, it is possible that commer- article concerning the SFC.) As the major thrust of cial gasification production levels by 1990 may reach .5 - synfuels commercialization was to be transferred to the LO billion cubic feet of high Btu-coal gas per day. SFC when it became operational, the delay in appointing Similarly, the SFC and DOE would have to provide the directors will certainly be a hinderance in the substantial economic incentives and Federal Regulatory commercialization of gasification and liquefaction pro- policies and practices to allow commercialization of the jects. liquefaction industry to achieve production levels of 100,000 to 200,000 barrels of oil equivalent per day by 1990. NATIONAL COAL ASSOCIATION FORECASTS COAL The report also concludes that: USE FOR SYNFUELS PRODUCTION "The emerging synfuels industry still faces many The National Coal Association (NCA) has just published uncertainties and must overcome many hurdles "A Forecast for U.S. Coal in the 1980s." Copies are before it will significantly contribute to U.S. available from the NCA at 1130 Seventeenth Street, energy supplies. The growth of this industry is N.W., Washington, D.C. 20076, at a price of $25. It's a expected to proceed slowly for many reason: (1) well-researched booklet, with a wealth of statistics and construction of a commercial plant is a massive forecasts concerning coal use to 1990. engineering and huge logistical undertaking; (2) there is lead time in establishing the National The NCA notes correctly that U.S. coal producers have Synfuels Production Program, i.e., time is required always been able to respond to increased demand for for the SFC and the DOE to grant financial incen- coal. Government forecasts and proposed policy in the

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-31 mid-1970s suggested rapidl y increasing demand for coal, and the industry added new ca pacity to meet the demand. But growth did not occur in the magnitude anticipated, and as a result, the industry is characterized by substantial over-capacity—the ability to produce more coal than is currently demanded. NCA conservatively estimates that the coal industry could have produced about 100 million tons more in 1980 than was demanded. This estimate is based on recent peak levels of production and probably understates excess capacity since it does not consider extra shifts that would he worked at these mines and some closed mines that could be reopened on short notice.

Much has been made of the increased role that coal is expected to play in America's energy future. Coat consumption will increase even with current policies in place. However, without policy and legislative initiatives that strike a balance between environmental gain and economic cost, NCA believes the U.S has little I'IbUflt 1 chance of reaching the nation's coal use goals over the next decade as stated, for instance, b y President Carter PRICE FOR COAL, OIL AND NATURAL in 1977 and b y the Energy Security Act. Counter to GAS DELIVERIES TO ELECTRIC UTILITIES these stated policies, other legislation and regulations - (DOLLARS PER MILLIONMTIJ) have restricted the increased use of coal. To achieve many of the current national objectives, such as lower rates of inflation, reindustrialization, more rapid econo- Coal Synthetic Fuels Production Goals Probably Will Not mic growth and improvements in the overall environ- Be Achieved mental conditions of our society, certain policy initiatives concerning coal will be necessary. The National Coal Association forecast suggests that the nation will fall short of the production goals set by the The NCA sees U.S. coal production increasing from 776 government in creating the Synthetic Fuels Corporation. million tons in 1979 to 1,015 million tons in 1985 and These goals were unrealistic considering the economic, 1,345 million tons in 1990. Exports of steam coal are technical, environmental and other regulatory conditions expected to increase from 2.5 million tons in 1979 to 39 in which svnfuels plants must be built. million tons in 1985 and 68 million tons in 1990. Exports of metallurgical coal will increase slightly over the The NCA forecast estimates that coal synfuels produc- years. tion is not likely to exceed 200.000 barrels a day of oil equivalent by 1990. This compares to the goals of NCA Says Coal Prices Do Not Follow Oil and Gas Prices 500,000 barrels per day in 1987 and 2 million barrels per day in 1992. of which two-thirds would come from coal. The competitiveness of the coal industry is reflected in historical prices of coal. In spite of the belief that coal NCA counted 36 pilot or process development units prices will follow oil and gas prices, the National Coal currently in operation and several demonstration plants Association contends that coal prices have followed near construction. There are five very small commercial neither. Figure 1, reproduced from the NCA booklet but gasification plants in operation and three more under based on data from FERC Form 423 submissions, construction. No commercial liquefaction plants are in presents the recent histor y of the prices of coal, oil, and operation in the U.S. natural gas delivered to electric utilities. The potential 1990 demand for coal from synfuels could In the past two years, the average price of coal has risen be as much as 75 million tons if problems of technology, at a rate slower than the general rate of inflation, let siting, and basic economics are solved early in the 1980s. alone the inflation in other fuels. The several recent There may also be a number of svnfuels facilities under instances of substantial price movements were attribu- construction in 1990 that could consume larger quanti- table largely to buying in anticipation of possible strikes. ties of coal in the 1990s. The forecast of coal consump- Recently published long-term price projections suggest tion for synthetic fuel production is perhaps more diffi- that coal prices will increase only slightly in real terms cult than any of the other sectors of coal demand due to over the next 20 years. the higher degree of uncertainty associated with this industry. About 80 percent of the coal sold in the U.S is sold under long-term contracts of 20 to 30 years. Utilities are NCA's forecast of coal consumption for production of anxious to secure long-term contracts since utility plants synthetic fuels is presented as Table 1. are engineered to utilize coal with very specific characteristics. Using a different type of coal usually results in lower level of efficiency. As a result, delivered prices tend to vary only with the costs of production and transportation.

4-32 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 TABLE 1

COAL CONSUMPTION FOR PRODUCTION OF SYNTHETIC FUELS

1979 1985 1990 Low 1 9 Most Likely 0.5 4 38 High U 75

The low forecast assumes that unfavorable conditions for synfuel plants will continue. Only projects for which construction is imminent or already underway will be in full scale operation in 1985. For 1990, only a handful of projects that are currently near construction (primarily smaller size projects) are in operation.

The most likely forecast assumes that at least some of obstacles to development of the industry are removed. More of the projects currently near construction will be built and by 1990 two to four large scale commercial plants and up to 20 smaller plants will be built

The high forecast assumes very favorable conditions for development of the synfuels industry so that six to 10 large scale facilities are in operation by 1990 and up to 40 smaller industrial plants.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-33 FOREIGN

CSR LTD. AND MITSUI TO EVALUATE SRC USING Valley. A plant of this size could produce about 800,000 VICTORIAN BROWN COAL tonnes of solvent refined coal and 400,000 tonnes of liquid products per annum. Later expansion of the An agreement to carry out a joint evaluation study of processing capacity could be achieved by duplication of the commercial production of solvent refined coal (SRC) plant units. The project at all stages will offer signifi- and liquid fuels from Latrobe Valley brown coal, was cant employment opportunities in the region. signed March 2 by R.G. Jackson, General Manager of CSR Limited and Akira Sasaki, Executive Vice-President An important advantage of the Mitsui SRC process is the of the Mitsui SRC Development Co. Ltd of Japan. The inherent flexibility of the product mix, which can be agreement covers the purpose, scope, and administrative varied to meet market and other requirements. workings of the evaluation study, which will be conducted on a 50 - 50 basis at a cost of over three million The indicative estimate at this time of constructing the dollars (Australian). The basic details of the agreement plant and associated mining and infrastructure facilities were negotiated in Tokyo early February 1981. is that it would be about A$1.5 billion in 1980 dollars. One of the purposes of the evaluation study will be to The purpose of the study is to evaluate the technical, define capital and operating costs more precisely. economic, and environmental viability of constructing a solvent refined coal plant in the Latrobe Valley with a The evaluation study will also investigate the possibility - capacity of 6,000 tonnes of dry coal per day, using the of downstream product processing in Australia. Both the Mitsui SRC technology and, where appropriate, to evalu- solid and liquid products have wide application in many ate the further processing of the products in Australia sectors of industry. Solvent refined coal, the solid The study will take about 15 months with a target date product, can be used as a clean fuel because of its very of completion of June 30, 1982. low sulfur and ash content and can be easily liquified by heating or further processing. It also has uses as a Prime responsibilities for various aspects of the study coking additive and as a raw material for downstream and the scope of the study are defined in the agreement. processing in the carbon and chemical industries (carbon SRC plant engineering, including the latest SRC techno- anode and carbon fiber). The liquid product is suitable logy and processes, plus the study of the marketing of for use as transport fuel and chemical feedstock. products in Japan. will be the responsibility of Mitsui SRC Development Co. Ltd. CSR will be responsible for the evaluation of mining PRELIMINARY DESIGN STUDY TO BE MADE FOR A (including mining technology and resource evaluation), COAL GASIFICATION PLANT IN BRAZIL infrastructure and transport (including plant location), marketing in Australia, environmental and socio-econo- The March 4 issue of the Commerce Business Daily mic impact studies, industrial relations, and discussions contained a request for expressions of interest from A with governments and government authorities. Econo- and E firms for a preliminary study of a medium or low- mic analyses and the commercialization plan will be the Btu coal gasification plant in Brazil. The plant would be responsiblity of Mitsui SRC Development Co. and CSR located in Mogi-Guaeu, in the State of Sao Paulo. The jointly. plant would produce 2 million cubic meters of medium- Btu gas/day which would be distributed to serve the It is the intention of the parties to proceed towards needs of energy-intensive industries located in the vicin- commercial development if the evaluation study shows ity of the plant. that the project is commercially viable. The plant and associated facilities would take up to four years to The preliminary design studies will include site screen- construct and could be in commercial production as early ing. processing design, facility design, product comhus- as 1987, if a decision to proceed with development were tors in the service area to retrofitting to make use of made in 1983. medium Btu gas in place of oil. Expressions of interest were to be submitted to the U.S. The equity interests in the project are presently 50 y percent CSR and 50 percent Mitsui SRC Development Department of Energ , P.O. Box 2500, Washington, D.C. Co. Ltd., although both CSR and Mitsui SRC Develop- 20013. The estimated completion date for the study is ment Co. have the right to invite other parties to September 30, 1981. participate, subject to Foreign Investment Review Board guidelines, if a decision were made to proceed with development.

If the study proves successful, it is envisaged that a commercial plant using 6,000 tonnes of dry coal daily could be established involving the open-cut mining of 7 million tonnes of brown coal per annum in the Latrobe

4-34 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 LAND

DOE COAL PRODUCTION GOALS ARE more than one-half of total U.S. production. Within the INCREASED West, the largest growth comes from the Western North- ern Great Plains region which includes western Montana, The Department of Energy's preliminary coal production Wyoming and northwestern and eastern Colorado. Coal goals were issued in August, 1980. (See page 4-51 of the production in this region triples from 1979 to 1990 and December, 1980 Cameron Synthetic Fuels Report for a more than quintuples by 1995 under medium demand review of those figures). The 1980 biennial update was conditions. The Western Northern Great Plains also released early this year by the DOE. accounts for over 50 percent of total western coal production by 1990. Substantial production growth also Three scenarios were used to develop low, medium and occurs in the Gulf and Central West regions. A more high coal production goals for 1985. 1990 and 1995. In detailed breakdown of the production goals by western the medium scenario, coal production doubles between states is contained in Table 1 and by Department of the 1979 and 1990. Approximately two-thirds of this produc- Interior coal production regions in Table 2. tion growth is expected to occur in the West. Under 199° high demand conditions and 1995 medium and high Table 3 compares DOE's final national coal production demand conditions, western coal production constitutes goals issued in 1980 with those issued by DOE in June 1978 and April 1979. The final medium national goal TABLE I

COAL PRODUCTION GOALS For 1985. 1990 and 1995 By Western States (million short tons)

1985 1990 1995 State Low Medium High Low Medium High Low Medium High E. No. Great Plains

North Dakota 29.0 29.0 29.0 34.3 50.8 59.7 53.6 85.6 103.7 South Dakota 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.9 1.9 Eastern Montana 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 0.3 Total fl 293 29__3 1T-6 771 1fl 87.8 105.9 Powder River Basin

Montana 53.9 56.6 79.3 57.2 109.4 176.4 98.4 211.3 385.0 Wyoming 133.5 136.6 142.3 148.6 185.1 235.8 161.0 279.5 388.8 Total T7 TI Tfl 'Iff1 4T27'Z 23U4 490.8 773.8 Rest of Wyoming 55.3 57.8 66.7 59.5 71.4 81.6 74.1 104.4 130.1

Colorado 33.8 33.9 38.2 28.3 35.1 43.3 35.0 49.3 59.9 Utah 25.1 30.2 35.1 35.9 48.8 63.0 49.2 74.2 82.6

New Mexico 33.3 37.7 44.2 55.9 64.1 67.4 61.0 71.8 77.4 Central West 15.0 15.2 16.7 14.8 21.5 26.9 18.3 32.7 44.7 Gulf 69.7 69.7 70.1 121.9 151.6 209.7 161.7 213.5 213.5 Arizona 12.1 12.1 12.1 11.2 11.6 11.6 11.2 11.5 11.8

Northwest 3.4 4.2 3.7 4.7 5.3 6.2 5.4 6.7 7.2 Alaska a a a a a 1.9 a 3.8 5.7 TOTAL 464.4 483.3 537.7 572.6 755.0 983.8 729.2 1146.5 1512.6

aNligible

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-35 TABLE 2

COAL PRODUCTION GOALS For 1985. 1990 and 1995 By DOl Coal Production Regions (million short tons)

1985 1990 1995 Region Low Medium High Low Medium High Low Medium High No. Appalachia 179.8 194.5 215.9 222.7 291.0 341.5 270.0 372.3 494.7 Cen. Appalachia 198.2 208.7 224.6 214.7 230.2 257.6 202.5 229.5 255.2 So. Appalachia 18.5 19.5 20.6 16.0 17.0 18.4 13.6 15.9 19.5

Eastern Interior 179.7 211.8 246.0 243.7 327.0 384.6 303.7 450.0 484.3

Western Interior 15.0 15.2 16.7 14.8 21.5 26.9 18.3 32.7 44.7 Fort Union 29.3 29.3 29.3 34.6 51.1 60.0 53.9 85.9 105.9 Powder River 187.1 193.2 221.6 205.8 294.3 412.2 259.1 490.9 773.8 Green River-Hams Fork 73.9 76.5 88.6 75.1 90.8 105.3 93.4 130.9 160.9 Uinta-SW Utah 36.4 41.4 47.1 45.8 60.5 76.7 60.8 89.2 101.2 Denver-Raton Mesa 5.3 6.3 7.8 4.2 10.5 14.3 7.3 18.4 24.2 San Juan River 31.9 35.4 40.7 54.5 57.6 58.9 57.6 Texasa 61.2 63.7 - 69.7 69.7 70.1 121.9 - 151.6 209.7 161.7 213.5 213.5

Total' 1024.8 1101.5 1229.0 1253.8 1603.1 1966.1 1502.0 2190.4 2710.6

alneludes Louisiana. bNot equal to totals in Table I because DOI regions do not cover all coal producing areas. TABLE 3

COMPARISON OF DOE COAL PRODUCTION GOALS ISSUED IN JUNE 1978, APRIL 1979 AND DECEMBER 1980 Medium Level (million short tons)a

1985 1990 June April December June April December Region 1978 1979 1980 1978 1979 1980 No. Appalachia 213.0 176.4 194.5 225.3 247.5 291.0 Cen. Appalachia 205.2 247.8 208.7 206.2 225.1 230.2 So. Appalachia 21.4 18.4 19.5 13.8 12.4 17.0 Total 439.6 442.6 422.7 445.3 485.0 538.2

Midwest 204.4 222.5 211.8 312.3 290.5 327.0 Total East 644.0 665.1 634.5 757.6 775.5 865.2 E. No. Gt. Plains 21.9 27.7 29.3 22.5 32.2 51.1 W. No. Gt. Plains 305.6 196.8 273.3 529.0 503.3 388.8 Total 327.5 4T3 302.6 551.5 535.5 439.9 Central West 10.6 11.9 15.2 10.3 11.9 21.5 Gulf 57.7 70.2 69.7 79.6 71.8 151.6 Rockies 43.8 35.1 41.6 53.3 41.2 60.8 Southwest 28.3 19.7 49.8 65.0 22.8 75.7 Northwest 4.4 6.1 4.2 3.7 6.1 5.3 Total 144.8 143.0 180.5 211.9 153.8 314.9 Total West 472.3 367.5 483.4 763.4 689.3 754.8

TOTAL U.S. 1,116.3 1.032.6 1,117.9 1,521.0 1,464.8 1,620.0

a No comparison is presented for 1995 due to the fact that the present update represents the first attempt to develop goals for that year.

4-36 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 issued in 1980 is less than t percent above the corres- mands assumes that by 1990, 60 percent of the total ponding June 1978 goal and 8.3 percent above the demand is generated by plants located west of the corresponding April 1979 goal for 1985. Comparable Mississippi and 40 percent from plants located to the figures for 1990 are 6.5 percent and 10.6 percent. The east of this boundary. A higher western percentage was major reasons for this increase are: higher demands for assumed because first generation commercial plants coal exports and coal-derived synfuels, more stringent favor the use of western coal according to DOE. Also, restrictions on the use of natural gas in boilers, higher lignite deposits located in the Fort Union Formation and expected world oil prices, lower limits on additions to in Texas are better suited for conversion to synfuels than nuclear capacity and higher expected conversions of for electricity generation. A 50-50 split was assumed utility boilers to coal.Factors in the 1980 analysis for 1985. which act to reduce coal demands, and hence coal production, include the lower expected growth rates in The type of coal specified for plants located in each electricity demand and higher real increases in coal demand region is the most abundant coal type found in transportation costs. On balance, however, the positive the nearest supply region. Certain Texas plants plan to demand factors outweigh the negative demand factors, utilize bituminous coal from the Illinois basin and would, resulting in somewhat higher national coal production therefore, deviate from this assumption. goals from the 1980 analysis than from the 1978 and 1979 analysis. While the regional synfuel demands for coal were based on planned or expected capacity of both liquefaction and Assumptions Regarding Synfuels Production Described gasification plants, the coal feedstock for both types of plants was assumed to be the same on a heat equivalent In explaining the assumptions made in the various scen- basis. Specifically, a plant producing 50,000 barrels per arios, DOE stated that regional demands for synthetic day of oil equivalent has an estimated coal feedstock fuels are subject to considerable uncertainty. While requirement of .192 quads and a product output of .106 several studies have addressed various aspects of the quads. While the product mix for coal synfuel plants is development of a synthetic fuels industry (e.g., USD01, an important concern for energy policy, it is of less 1979: Western Interstate Energy Board; ERDA, 1976; concern in determining the coal feedstock level required DOE, July 1979 and January 1980), to date there has to meet a specified syrifuel demand. Therefore, DOE did been no comprehensive integrated analysis of the re- not specify the product slate for each plant. source, social, economic and environmental aspects of siting and developing a synthetic fuels industry. Difference Between Preliminary Report and Update Are Noted For 1985. the national demands for coal synfuels were allocated to the National Coal Model demand regions A number of changes were made by the DOE in the according to the expected operating capacity for 1985. updated report. In the update, DOE realistically in- For 1990 and 1995, allocations were based on plausible creased the number of supply regions from 30 to 34 by plant locations and an assumed growth pattern in adding one region in Wyoming, one region in New Mexico regional plant capacities. The growth pattern specified and two regions in Colorado. With these additions, was based on two criteria: coal availability/suitability Wyoming contains two regions (Powder River Basin and and regional/technical diversity. The first criterion was Green River-Hams Fork), New Mexico contains two considered a prerequisite for siting a plant because the regions (San Juan River and Denver-Raton Mesa) and economics of coal conversion and transportation favor a Colorado contains four regions (Green River-Hams Fork, plant location close to the coal fields serving that plant. Uinta-S.W. Utah, San Juan River and Denver-Raton According to DOE, the second criterion becomes more Mesa). critical at the medium and high demand levels because of the large number of plants required. While some coal Included in additional changes which DOE details, was a demand regions contain sufficient coal reserves to supply several s revision of the coal synfuel demand scenarios to reflect ynfuel plants, other factors, such as water a 55 percent thermal elf iciencyinsteadofa 60 percent. Also, availability, storage and transportation, air quality stan- the proportion of total synfuels production obtained from dards. coal transportation facilities and community im- coal was set at 2/3. pacts, limit the total plant capacity that can be sited in a single region. Some of these constraints are likely to ### # be binding in the sparsely populated arid regions of the West. To reduce the likelihood of exceeding these constraints, as well as the technical and economic risks that accompany a regional concentration of synfuel plants, a dispersed regional siting pattern was assumed. Since a dispersed siting pattern implies the use of several coal types and possibly different conversion technologies, according to DOE, the technical and economic risks would be lower than for a more concentrated pattern.

Table 4 presents the regional synfuel demands for coal and Table 5 shows the number of plants in each region assumed for the low, medium and high coal production goals. The regional distribution of coal feedstock de-

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-37

TABLE 4 REGIONAL DEMANDS FOR COAL BY SYNTHETIC FUEL PLANTS (QUADS)

Coal Type and Low Medium and High Demand Region 1985 1990 1995 1990 1995 Bit urn inousa

Colorado (CO) .192 .577 096 .192 .192 .577 Eastern Kentucky (EK) Illinois (IL) 192 .192 .096 .289 .385 .385 Southern Ohio (OS) .192 Texas (TX) 096 096 .192 .192 Utah (UT) .192 .577 Western Kentucky (WK) .192 .577 .192 .385 .385 Western Pennsylvania (WP) 096 192 .192 .096 .385 .577 West Virginia (WV) Alabama (AM) 096 .192 .096 .192 Sub,bituminoust) -

Montana (MT) .192 .192 .385 .770 .096 .192 .192 .577 New Mexico (NM) Wyoming (WY) 096 .385 385 .096 .385 .770 Lignite

North Dakota (DM) 096 .192 .385 .096 .385 .770 Texas (TX) 096 .192 .385

Total 385 1.540 2.309 385 3.849 7.698

11,000 Btu/lb or 22 million Btu/st b 9,000 Btu/lb or 18 million Btu/st C 7,000 Btu/lb or 14 million Btu/st d Total demand may differ slightly from sum of state demands due to rounding

4-38 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 TABLE 5

DISTRIBUTION OF SYNFUEL PLANTS BY NCM DEMAND REGION?

NCM Aggregate Synfuel Svnfuel Demand Level Year Demand Region Plant Sitesb !9!L Medium and 1985c E. No. Central IL 1 1

Total East 1

W. No. Central DM 1 1 Mountain WY 1 1

Total West 2 2

Grand Total 3 3

1990 Middle Atlantic WP 1 2 South Atlantic WV 2 E. No. Central IL, OS 1 3 E. So. Central EN, WK 1 2

Total East 3 9

W. No. Central OM 1 2 W. So. Central TX Id 2 Mountain M T. CO. WY,U T, N M 4 7

Total West 6

Grand Total 9 20

1995 Middle Atlantic WP 1 2 South Atlantic WV 1 3 E. No. Central IL,OS 2 5 E. So. Central EN, W K 1 6

Total East 5 16

W. No. Central DM 2 4 W. So. Central TX 3 Mountain MT,CO.WY,UT,NM 4 17

Total West 8 24

Grand Total 13 40

Plants have a capacity of 50,000 barrels per day, unless otherwise indicated. b See Table 14 for explanation of region codes. C Includes only plants of 25,000 barrels per day. d Includes one plant of 25,000 barrels per day.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-39 EXPRESSIONS OF LEASING INTEREST IN for detailed figures and comparison.) PORT UNION COAL GIVEN High Interest In Synfuels Indicated In Expressions June is the target date for the Fort Union Regional Coal team to make recommendations to the Secretary of the With only one exception, the expressions of interest Interior on a preliminary leasing target for that region. noted that industry was considering synfuels. In preparing the preliminar y target, the Department of Interior called for expressions of leasing interest. Table The submission from Tenneco included a description of I is a tabulation of the companies that responded to that the Tenneco SNG from Coal Project (see Status in request. Projects - Coal). Three firms (U.S. Steel, Consolidated Coal and Tosco Corporation), mentioned synfuels as a Management Framework Plans (MFP5) have been com- possible use for their coal without a specific project pleted for three study areas in the region: Golden Valley identified County, North Dakota; Rcdwater Area of Eastern Mon- tana; and the West-Central North Dakota area. Figure 1 Northern Minerals Company, a subsidiary of lntcrNorth. gives the areas for tract delineation in the Redwater and Inc. (formerly Northern Natural Gas Company), noted Golden Valley areas, as well as the location of the Ft. that a typical synfuels plant would use about 13 million Union region. Figure 2 shows the West Central MFP tons of lignite per year, with a planned life of 20 years. location. thus requiring a lease block of 260 million tons of recoverable reserves with approximately 300 million tons Fort Union coal represents about 11 percent of the in place. In addition, Northern specified that "the lease western coal reserves. It is primarily lignite, high in block must be located such that the synfuels or syngas -moisture -content, low in -sufur, with a heating value - plant is accessible to a liquid fuels pipeline or a natural between 5,950 and 7.510 Btu's per pound. Currently, gas pipeline." FUi'thero critical -requirement is-access- eleven lignite mines produce about 15 million tons per to approximately 12.000 acre feet of water per year. year, with another mine and coal gasification project According to Northern, when evaluating the previous under construction. items in terms of the Redwater and Golden Valley Management areas, the following could be divided into Preliminary DOE production goals for the area were set lease blocks acceptable for s yngas development; Circle. at 48 million tons per year by 1990. However, as stated Burns Creek-Thirteen Mile Creek, Southwest Glendive. in the article on DOE's updated leasing goals, this region and Sidney. Blocks suitable for synfuels development are accounts for a large percentage of the increased coal more restricted due to the location of the Northern production in the revised figures. (See previous article border pipeline. It appears that the Burns Creek-

EXPRESSIONS OF LEASING INTEREST CONCERNING COAL IN THE FORT UNION COAL REGION

Coal Heating Value, Sulfur. Type of Production Starting Area BTU/Pound Mine MMT/Year Date

Burlington Northern Circle

Big Sky International Golden Valley/Redwater

Consolidated Coal Co. Burns Creek/Thirteen 6,500 to 0. 5 to Surface Mile Creek/Redwater 7,000 1.20

Kerr-McGee Corp. Redwater 6.000 to 0.60 Surface 8,000

Northern Minerals Co. Redwater/Golden Valley

Northern Resources, Inc. Circle 6,000 to Surface 16 7,000

Tenneco Coal Company Golden Valley/Redwater 6.050 .80 Surface 13.5 Tosco Corp. Glendive/Redwater United States Steel Burns Creek 6.736 0.32 Thirteen Mile Creek

Weseo Resources, Inc. Redwater 7,200 0.42 surface 1988

4-40 CAMERON SYNTHETIC FUELS REPORT, JUNE 1991 C H L A I 't TH I I

UNtIL & r AREAS TRACTDELINEATION Redwater . • Golden Valley FF_1KRCRA Areas (E]Tract Delineation Areas otal Ft. union Coal Region

1 RED WATER AND GOLDEN VALLEY TRACT LOCATION

Thirteen Mile Creek and Sidney KRCRAs have portions gasification plant. According to Weser, Resources, Inc., which are suitable for synfuels development, the market for the coal they are interested in would most likely be a mine-mouth coal gasification plant. The To stimulate development of the synfuels and syngas proposed plant would use the McCone County coal as a industries, Northern requested that the FILM take into feedstock to produce 250 mm scf of gas per day. consideration the general criteria for synfuels and syngas plants when leasing blocks are established Specifically, Northern Resources, Inc. stated in their expression of to designate several tracts in each KRCRA which are leasing interest that they were investigating the possibi- designed to accommodate syngas or synfuels develop- lity of a 10 million TPY coal to methanol plant. (See ment. Circle West Project - Status of Projects.)

In a related expression of interest, Burlington Northern, # # # # Inc. (BNI) told the BLM that BNI has committed its coal to a project by agreeement with Northern Minerals and has stated its intent to grant surface owner consent when BNI owns surface over U.S. Coal. BNI also stated that an agreement is under development with WESCO Resources to lease UNI coal to supply a high Btu coal

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-41 INDIAN a2TJT' MERCtO EfE3P --S __SJ '•C" Y LEGEND SCOAL DEPOSITS PRELIMINARY LOGICAL

SJARk 4 - -4 - WEST CENTRAL MFP COAL DEPOSIT MAP

FIGURE 2 WEST CENTRAL MFP LOCATION STUDY PROCESS FOR LEASING region-wide leasing alternatives for the projected June, FORT UNION COAL OUTLINED 1983 lease sale. The focus of this phase is on a comparison among tracts within the region and on an In August of 1980, a Project Management Plan was evaluation of potential leasing patterns on it regional issued by the Bureau of Land Management. The Plan is a basis. guide and workbook for the staff engaged in a coal project. it supplements federal coal management regu- Based on the analyses reflected in Phase 1 and 2. the lations, the Memorandum of Understanding for the Fort focus in Phase 3 is on reaching and implementing a final Union Regional Coal Team (BLM) coal program dirce- leasing decision, which ultimately rests with the Secre- tion, and other legal and regulatory documents. tary of Interior. Included in this phase are lease-sale schedule recommendations from the Regional Coal Team The Plan defines the steps through which the BLM Lead and the lead BLM State Director, economic evaluations State Director may meet the requirements of the Seere- by the Geological Survey, and consultations among the tary's coal management program, which is aiming for a Secretary, the Attorney General, state governors, and decision about federal coal leasing in the Fort Union Indian tribe leaders. region by June 30, 1983. It describes the organization for the project, the division of labor, and the areas and Facility Impact Implications Evaluated techniques for study. - Of special interest to the s ynfuels industry is the Preli- Phase I of the program began with the completion of the minary Facility Evaluation Report (PFER) that will be BLM Management Framework Plans (MFP). Based on the prepared for each tract. At the June 24-25. 1980 findings in the MFP as to which areas are suitable for meeting, the Fort Union Regional Coal Team approved further leasing considerations, Phase I is focusing on the an approach to end-use implications of coal develop- delineation of tracts into Logical Mining Units (LMU). inent. Site-Specific Analyses are currently underway. Also, an evaluation will be performed addressing the impacts of Using the expression of leasing interest as a starting likely associated power and synfuel plants. During this point, the team will postulate a likely use or reasonable phase and during part of Phase II of the program, the alternate uses by site (tract or tracts). The objective of application of unsuitability criteria will continue, this evaluation is to present the most probable major impacts of development in a total context for review by The first step in Phase 2 is the establishment of leasing the team and for inclusion in the Regional EIS. targets, i.e., tonnages of federal coal, for the region. Based in part upon these leasing targets, the individual The PFER's will describe assumed facility operations and tracts will be ranked and grouped for evaluatidn into requirements, and will have an evaluation of associated

4-42 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 major im pacts. The PEER's and site specific analyses demand and supply relationship existing between the will also he aggregated in the cumulative assessment and facility and tract, respectively. regional EIS in a manner designed to present an array of decision options for analysis or on which to structure Following the description of tract facility relationships different options. will be a section describing the area which would be impacted as a result of facility construction and opera- The types of facilities to be addressed in the Preliminary tion. In some cases the area being discussed will be of a Facility Evaluation Reports will fall into three basic different size and/or shape depending upon the environ- categories of energy-conversion: mental component being discussed (e.g., air quality versus economic conditions). The description of the area Two 500 Mw steam-fired electric generating will focus upon describing those items likely to be most units. heavily impacted by the facility (e.g., employment, SO 250 million standard cubic foot per day coal emissions, etc.). At the end of this section will be gasification plants. description of the likely future conditions expected to 100.000 barrels/day coal liquefaction plants occur in the area without the proposals. For most (including methanol). components this will involve describing the more significant trends discussed in detail in the Site-Specific Tract The Energy Production and Projects Group, consisting of analyses done by the districts. RLM and State representatives, will develop requirements concerning the inputs required for operation of A facility impact analysis will follow the area descrip- these facilities. This group will consult with appropriate tion and will assess impacts to the area as a result of industry and government representatives in determining facility development. requirements for water, land, coal, labor. etc., for each of the three types of facilities to be studied in the The final portion of each Volume II will be a discussion reports. Unless specifically stated, the facilities are of major issues (problems, trends, etc.) and resource assumed to be mine-mouth. concerns along with a description of measures that could be undertaken to lessen impacts in the area. The analyses in the PEER will be geared toward providing an assessment of the of the impacts from a facility upon the area, rather than the exact site where the facilit y is assumed to be built. Consequentl y, the bulk of RECORD HIGH BID SUBMITTED FOR FEDERAL the PEER analysis will involve components like air LEASE quality and social and economic conditions, which are more area-oriented to begin with. Other environmental Leasing under the Federal Coal Management Program components (e.g., soils, vegetation, hydrology, etc.) will continued in April with a sale of two tracts in the Green be discussed to the extent that these would be signifi- River-Hams Fork region. cantly impacted by facility construction and operation. The Pinnacle tract, about 15 miles southeast of Steam- Each Preliminary Facility Evaluation Report (PEER) will boat Springs in Routt County received only one bid. consist of two volumes. A single volume I will be Energy Fuels Corp. of Denver offered $25.00 an acre for developed which will apply to any of the three types of the 273.22 acres which contain an estimated 729,000 facilities under study. A volume II will be prepared for tons of recoverable coal reserves. each facility describing the existing area and impacts expected to occur in the area as a result of facility The second tract, the Hayden Gulch tract, contains an construction and operation. Table 1 shows the facilities estimated 63,640,000 tonsof recoverable reserves. The expected to be associated with tracts in the Montana bidding for the tract lived up to the competitive title of portion of the study area. the sale. Four sealed bids were submitted, these were: Hayden Gulch West Coal Co. at $100/acre, Peabody Coal Volume I will contain a description of the facility. For Co. for $26/acre, and Atlantic Richfield Co. and Free- each type of facility, a prototype plant will be described man United Coal Mining Co. both for $25/acre. The sale which represents the size, process technology or techno- was then opened to oral bidding and after 21 bids, logies, and other characteristics most likely to be pro- Hayden Gulch, a joint venture between W.R. Grace and posed in the Fort Union Region. The description will Hanna Mining won the bidding at $1,700/acre. Freeman include ancillary facilities such as water supply systems, Coal's top bid was $1,600/acre, Atlantic Richfield electric transmission systems, etc., along with a discus- $510.00. Peabody did not enter the oral bidding. sion of construction and operation aspects of the facility that are relevant to determining impacts that could #### occur in the vicinity of each tract. Volume II will begin with a summary, which will describe the area, the facility impacts, and major issues. Only the more significant items within these three categories will be discussed in the summary.

The next section will address the overall relationship between the facilities described in Volume 1 and the tracts associated with those facilities including the coal

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-43 TABLE I

ASSUMED END-USE OF COAL BY TRACT (Golden Valley and Redwater Areas only)

Known Recoverable Tract Coal Resource Area Number Tract Name End-Use

Circle 1 Circle West Two 500-Mw generating plants and methanol plant

Is Circle West "A" Two 500-Mw generating plants or methanol plant

lb Circle West "B" Two 500-Mw generating plants or methanol plant 2 Redwater River - 250 MMSCF/D coal - gasification plant - Burns Creek- Thirteen Mile Creek 3 Thirteen Mile Synfuel Plant

3a Thirteen Mile "A" Two 500-Mw generating plant

3b Thirteen Mile "B" Two 500-Mw generating plant 4 Burns Creek-North Synfuel plant

5* Burns Creek-South Synfuel plant 6** Burns Creek-East Synfuel plant Glendive Wilbaux -Beach 7 Glendive Synfuel plant

B Wilbaux-Beach-North 250 MMSCF/D coal gasification plant

9 Wilbaux-Beach-South 250 MMSCF/C coal gasification plant

* Only one tract may be made available from this area. ** This tract would be made up from a combination of areas from tracts 4 and 5.

4-44 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 LEASE SALE SCHEDULED FOR ALABAMA SUBREGION Upper Sulfur Springs Church - 48,850 tons of in- place Federal reserves; small business tract in The Final Environmental Impact Statement (FEIS) for Fayette County. the Alabama Subregion of the Southern Appalachian Coal Region was released in January by the Bureau of Land Rock Springs Church - 25.93 million tons of in- Management (BLM). place Federal reserves in Tuscaloosa County. Comments received by BLM on the Draft EIS did not Elm Grove - 69,000 tons of in-place Federal bring about significant changes in the data, analysis, or reserves; small business tract in Walker and Fay- conclusions it contained. Therefore, the DEIS now ette Counties. serves as Volume I of the FEIS (See Page 4-61 of the March 1981 Cameron Synthetic Fuels Report for a Tracts that will be offered at the second sale are: review of the dralfl. Wiley - 14.3 million tons of in-place Federal Volume II responds to the comments received on the reserves in Tuscaloosa County. draft, reprints the comment letters, and makes whatever revisions, additions, or deletions are required in the Dividing Range - 1.05 million tons of in-place DEIS. Volumes I and II constitute the Final Environ- Federal reserves in Fayette County. mental Impact Statement. The EIS showed that developing all 13 tracts of the preferred alternative at the same Jess Creek -- 7.72 million tons of in-place Federal time could possibly cause a significant environmental reserves in Walker County. impact to the quality of the water supply for the city of Tuscaloosa.

The newly appointed Secretary of the Interior, James INTERIOR ANNOUNCES GUIDELINES Watt, addressed this issue in announcing his intent to FOR POSSIBLE 5-YEAR EXTENSION offer tracts for lease in north-central Alabama during OF PRE-1976 FEDERAL COAL LEASES 1981. He agreed to a "phased-in" leasing approach in announcing the first sale for June 25. 4981 with the Last January 6, the (former) Under Secretary of the second sale no later than December, 1981. Interior announced the final guidelines that will govern development of Federal coal leases that were issued Seven tracts will be offered in the June sale at the prior to the Federal Coal Leasing Amendments Act of Alabama State Capitol in Montgomery, Alabama. The 1976. second sale, at a date to be determined, will be for the six remaining tracts. If significant competitive interest These guidelines are rather controversial. They extend is shown for Alabama leasing, additional tracts will be the law's requirements for new leases to older ones. considered by the Department for a sale early in 1982 Holders of both new and old leases are now given a after consultation with the Governor and regional coal deadline of June 1. 1986 to produce one-fortieth of the team. reserves in a lease or logical mining unit, or risk cancellation of the lease. It is not clear whether or not Federal coal leasing in Alabama has been limited in the the Reagan administration will continue the policies set past, due to the scattered nature of the Federal coal forth in these guidelines. New Interior Secretary James holdings. The 13 tracts are being offered for lease at Watt, in testimony before the House Interior Committee, this time to allow existing operations to continue pro- suggested that changes would be made. He stated that duction, to eliminate potential bypass situations, and to the new administration's system would let market forces promote the orderly development of publicly-owned coal determine which tracts of land should be developed, and in this north-central area of Alabama. at what time. However, as of May 29, no official change had been made to the January 6 guidelines. The tracts that will be offered at the June sale are as follows: By notice published in the Federal Register (45 FR 7318) on February 1, 1980, Interior requested public comments Upper North River - 338,347 tons of in-place on policy options for exercising the Secretary's discre- Federal reserves; potential bypass situation in Fay- tion to extend the 10-year diligent development period ette County. for Federal coal leases. North River - 6.14 million tons of in-place Federal Following receipt of comments on the Federal Register reserves; potential bypass situation in Tuscaloosa notice, a "Secretarial Issue Document" was prepared County. within Interior that proposed three different options, which will be reviewed briefly. Goodwin Creek - 826,787 tons of in-place Federal reserves; potential bypass situation in Walker The first approach would aggressively seek to cancel as County. many as possible undeveloped pre-FCLAA Federal coal leases that are not likely to meet diligent development Harris Cemetery - 35.400 tons of in-place federal requirements by June 1, 1986. Only lessees with mines reserves; small business tract in Fayette County. in actual production could apply for an extension to the 10 lease year diligent development period The supporting rationale behind this policy option would be to

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-45 discourage coal production from leases that contain less A contract exists to sell or use 24 percent of favorable royalt y rates than those leases issued after the lease reserves before the end of the passage of the FCLAA. This category of leases may also extension period. have environmental problems associated with their development which can be more easily avoided with the new leasing procedures in the Federal coal management program. Conditioning those extensions that are granted SURFACE MINING REGULATIONS AND LITIGATION by requiring the achievement of other worthwhile objec- REVIEWED tives, restricting lease assignments once an extension has been approved, and exercising discretion to grant Relatively few regulatory notices were published in the less than the (till 5 year extension period are logical Federal Register during the second quarter of 1981. adjuncts to this restrictive approach. Choosing this This, is a result of the new Administration's desire to option increases the burden of clearing sufficient quanti- reassess and possibly modify recently-proposed regula- ties of coal to fulfull the Federal share of the Nation's tions issued by the Carter Administration. The abolish- total coal energy needs on the Department's new leasing ment of the U.S. Regulator y Council and the establish- program, and would be certain to arouse vocal opposition ment of the Presidential Task Force on Regulatory from the coal industry, the Department of Justice, and Relief are subjects discussed in an article which is the Department of Energy. presented in the General section of this quarterly. A second option, diametrically opposite to the restric- Regulations which were published in the Federal Regis- tive option, is a policy to grant extensions in all possible ter since February 1981, are reviewed in chronological cases where a lessee has even the remotest chance of order: producing commercial quantities before the end of the extended term, in hopes of maximizing coal production Federal-Register, Fcbruaryd: from Federal lands. A lenient interpretation of the three reasons allowed by the regulations in granting The Interior Department is considering guidelines pro- extensions would essentially allow a 5-year grace period duced in a staff option paper which tighten procedures from the diligence requirements for up to 440 leases for obtaining exemptions due to diligence regulations containing significant reserves of Federal coal, although that require commercial quantities of coal to be deve- the Department would continue to be uncertain as to loped on existing federal leases by June 1, 1986. Interior how much of this coal would be developed. While it officials have noted that approximatel y 300 lessees who might be popular with a large segment of industry, this obtained coal leases prior to Aug. 4. 1976, will probably approach is at odds with existing statutory and regula- apply for lease extensions since they have not submitted tory provisions requiring diligent development of Federal mine plans for approval yet. This staff option paper coal leases. suggests that all applicants submit OSM-approved mining plans and have binding agreements to sell one-fortieth of The last of the three overall policy guidance options in the logical mining units' reserves in the first full year of the SID is the "preferred" approach, so labeled because it production in order to he granted an extension. Another represents an avenue that respects the diligence provi- proposal requires lessees seeking extensions to formally sions of both regulation and statute, while clearing the agree to comply with diligence requirements on all other road for coal production from economically efficient and federal leases which they hold. environmentally suitable leases. This option would seek to encourage responsible coal development from the Federal Register, February 26: holders of pre-FCLAA leases where the lessees have A bill (S.572) was introduced to expand the scope of made serious commitments toward bringing Federal coal small operators assistance (SOAP) program which was into production. but will need more time to produce established under section 507(c) of the 1977 Surface commercial quantities than the June 1, 1986, diligent Mining Control and Reclamation Act. The purpose of development deadline. the bill is to provide greater assistance to the small operator so he can remain competitive in the current Undersecretary James Joseph opted for the last or market. It also changes the definition of a small "preferred" approach in his January 6 order announcing operator from one who mines 100,000 tons or less per the final guidelines for extensions. Details of the year to one who mines 200,000 tons or less per year. "preferred" approach are presented in the Appendix of this quarterly at Pages 5-1 through 5-4. However, he Federal Register, March 12: slightly modified items La, 6., and 7, as noted in Appendix Page 5-5. In summary, the Department still OSM seeks comments concerning the granting or denying sets January 1, 1986 as the time by which lessees would of a petition submitted regarding 201(g) of the Surface have to produce 24 percent of the lease or logical mining Mining Control and Reclamation Act to amend the unit reserves on risk lease cancellation. However, one bonding forfeiture regulations. The current regulation extension, not to exceed 5 years, may be granted if. allows a reclamation bond posted for an increment of a permit area to be used for reclamation on any part of More time is needed to develop projects the permit area for which a forfeiture has been declared. utilizing advanced technology; or, The proposed change would limit use of the proceeds of a bond posted for an increment of the permit area to just A project is of magnitude involving mine that increment. output of at least five million tons of coal per year for a surface mine or two million tons per year for an underground mine; or,

4-46 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Federal Register, March 18: whether to establish different inspection requirements for inactive or abandoned sites; The Interior Department announced full approval of a cooperative agreement between OSM and the state of whether to use fly-overs in conducting partial Wyoming. Under the agreement. Wyoming will have Federal inspections and monitoring. primary responsiblity for the regulation of coal mining under the Surface Mining Control and Reclamation Act. Legislation Wyoming became eligible for the agreement as a result of the Interior Department's approval of the State's S.382 is the Regulatory Reduction and Congressional regulatory program. Control Act of 1981 which requires agencies to prepare an economic analysis of all proposed and final rules, and Federal Register, April 17 estimates the cost of the rule on various sectors of the affected economy. When final regulations are published, OSM is seeking comment on draft revised rules to the the agency must submit a copy of the regulation to "State window" regulation and bonding regulations for Congress. surface coal mining operations. These draft rules are part of a broad and comprehensive review of OSM S.401, the Regulatory Cost Reduction Act of 1981 re- regulations ordered by Interior Secretary James Watt. quires each agency head to use the most cost-effective OSM is proposing to require that alternatives must be as method of achieving a goal or objective unless he deter- effective as the OSM regulations in meeting the intent mines that national interest requires using a less cost- of the Surface Mining Act. This would replace the effective alternative. This bill directs the President to "State window" concept which required states to submit develop ways to determine compliance costs and to alternative approaches to OSM regulations based on local compare the cost-effectiveness of alternatives, subject agricultural or environmental conditions. The draft to public notice and comment procedures. revisions would also amend the existing rules for performance bonds, including the form and amount of such 5.572 amends the Surface Mining Control and Reclama- bonds, the terms and conditions, and the requirements tion Act of 1977 regarding Small Operator Assistance by for bond release. adding a section that provides additional financial assistance to operators over and above that already granted Federal Register, April 22: in the Act. OSM has proposed changes in its interim and permanent regulatory programs which could, if adopted, relax the The Securities and Exchange Commission has decided to rule on ordering the closing of a coal mine if a violation postpone adoption of rules relative to disclosure of is not corrected 90 days after the notice of violation was financial data by mining companies. The commission issued. The proposed rule lists four circumstances under stated that it was "sensitive" to the fact that some of which the 90-day period could be extended. the information it wanted might result in the disclosure of proprietary and confidential information. Federal Register, Ma y 4 Recent hearings before a House Judiciary subcommittee OSM is seeking comments and recommendations from on omnibus regulatory reform focused on H.R. 746, the the public to be considered in drafting proposed revisions "Regulatory Procedure Act of 1981. H.R. 746 is spon- for 30 CFR Parts 840-845. The revisions were drafted in sored by the subcommittee chairman, George Danielson reponse to the Secretary's directive to remove burden- (D-CA) some or Counter productive regulations and also in response to comments from the states and general Litigation public. OSM specifically requested comments on the following: The U.S. Court of Appeals for the District of Columbia ruled that the Surface Mining Act grants to the Interior Secretary the "rulemaking power enabling him to specify 1. The economic effects of the draft regulations by regulation, criteria necessary for his approval of a including effects on prices, markets, com- proposed state program." This reverses the decision last petition. employment, productivity or costs; year that the Secretary's authority is limited to deter- 2. the effects of the draft rules on small enti- mining whether states have satisfied the minimum infor- ties; mation requirements of the Act. 3. less costly alternatives to the draft regula- Eleven electric utility companies presented oral argu- tions which still meet the requirements of ments before U.S. Supreme Court asserting that the Surface Mining Control and Reclamation Montana's coal severance tax is "an unconstitutional Act of 1977; burden on interstate commerce." The case, Common- 4. specific information about whether the wealth Edison Co. at al. vs. State of Montana, is on potential benefits of the draft rules outweigh appeal from the Montana Supreme Court. the costs; The Reagan administration is attempting to settle out- 5. changing the point system for assessing of-court one monstrous pile of litigation over strip penalties (30 CFR 845.13); mining regulations. This litigation resulted from chal- 6. modification of 30 CFR 845.14 to adjust the lenges to the validity of some 30 regulations issued by dollar amounts for points; the Interior's Office of Surface Mining.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-47 The Supreme Court has agreed to consider the constitu- regulations and those governing competitive lease sales. tionality of an Indiana law allowing the mineral rights to (See article in the General section). Interior Secretary a land tract to lapse if they are not used for 20 years. James Watt is soliciting views from government, busi- The Court will hear a challenge to a state court ruling ness, industry and environmental leaders for ideas on that mineral rights beneath a property belong to the how to reform federal regulations. surface owner of the property after two decades of disuse. The Office of Surface Mining has proposed amending its interim and permanent surface mining regulations to In February 1981, the Supreme Court heard arguments on provide coal mine operators more "latitude" in conduc- the constitutionality of the 1977 Surface Mining Act. ting blasting operations. The proposed rule moves the Last October, the High Court agreed to review chal- 1000 feet limit, but requires that mine operators demon- lenges by the Virginia Surface Mining and Reclamation strate their ability to blast near inhabited areas. Association and other parties, that the Act violates states' rights guarantees. These groups also say the The Interior Department issued final rules on prime government should be restricted from mining property farmlands exempting surface mine operations under per- without "just compensation." mits issued before August 3, 1977 from both the farmland permit applications requirement and performance In April 1981, the U.S. Court of Appeals upheld Interior standards. Department's rights to set minimum standards on the information states must collect from surface coal operators before granting then mining permits. The appeal was brought by Peabod y Coal Co. which argued that only states have the right to increase information requirements of the Act. - - - - - Policies and Programs

The Interior Department has lifted a freeze on West Virginia's abandoned mine land reclamation. Coal operators in the state have contributed more than $60 million into the AML fund since the fee collection was started on October 1. 1917. The state is now eligible for more than $30 million for a land and water restoration program.

Andrew Bailey, acting director of the Office of Surface Mining, received a directive from Interior Secretary James Watt to make "a sweeping review" of rule and regulations of the 1977 Surface Mining Act. This review is being performed to determine which OSM regulations are needlessly burdensome or exceed the intent of Con- gress.

OSM is considering extending the deadlines within which states must resubmit those portions of their programs originally rejected by the Interior Secretary. This extension offer may be made before a review of OSM's regulations is completed. This could result in new conditions and revised regulations. However, before offering extensions, OSM is required to initiate a proposed rulemaking process, including a public comment period.

In a policy memo to regional directors, Andy Bailey instructed that OSM inspections should be confined to specific situations, including failure by a state to enforce the program after being instructed to do so by the Interior secretary; imminent danger of significant environmental harm that the state fails to repair; inspections to ensure compliance with OSM enforcement actions; oversight inspections which the memo calls "premature" since the department has not yet established inspections requested by the state. Bailey's memo emphasizes the agency's desire to give states the most responsibility in regulating their programs.

Vice President Bush released a list of existing regulations under review that include all the surface mining

4-48 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF COAL PROJECTS INDEX OF COAL INTEREST

Company or Organization Project Name Page A. C. Valley Corporation A. C. Valley Corporation Project ...... 4-57 A. Stokes Associates Keystone Project ...... 4-72

Acurex Aerothcrm Corporation Acurex Aerotherm Low-BTU Gasifier for Commercial Use 4-57 AGIP Exxon Donor Solvent Process Development ..... 4-65

Airco, Inc. Medium BTU Synthesis Gas Study 4-74

Air Products and Chemicals, Inc. Keystone Project ...... 4-72 Solvent Refined Coal Demonstration Plant (SRC-1) 4-80

Alberta Research Council Underground Coal Gasification, Canada 4-87

Allis-Chalmers Hampshire Gasoline Project 4-70 KILnGAS Project ...... 4-72

Amax, Inc. Amax Coal Gasification Plant 4-57

American Natural Resources Great Plains Gasification Project 4-69 Amcrigas, Inc. Keystone Project ...... 4-72

ANG Coal Gasification Company Great Plains Gasification Project 4-69

Appalachian Regional Commission Pike County Low-BTU Gasifier for Commercial Use 4-78

ARCO Underground Coal Gasification - Rocky Hill Project 4-89 Underground Coal Gasification - University of Texas 4-87

Arkansas Power & Light Company Central Arkansas Energy Project ...... 4-59 Ashland Synthetic Fuels, Inc. H-Coal Project ...... 4-71

Atlantic Richfield Exxon Donor Solvent Project ...... 4-65

Baltimore Gas and Electric KILnGAS Project ...... 4-72

Basic Resources, Inc. Underground Coal Gasification -University of Texas 4-87 Underground Gasification of Texas Lignite- Tennessee Colony Project ...... 4-90

Basin Electric Great Plains Gasification Project 4-69

Baukol-Noonan Coal Co. InterNorth Methanol Plant 4-71

Bechtel Inc. Cherokee Clean Fuels Project 4-60 Cool Water Coal Gasification Project 4-62 Medium BTU Synthesis Gas Study 4-74

Bell Aerospace Textron Bell High Mass Flux Gasifier ...... 4-57

Bethlehem Steel Co. Keystone Project 4-72 Low/Medium BTU Gas for Multi-Company Steel Complex. 4-73

Billings Energy Corporation Forest City Coal Gasification Project 4-67 Black, Sivalls & Bryson. Inc. Lignite Briquette Gasification Plant ...... 4-73

British Department of Energy Composite Gasifier Project 4-61 National Coal Board Liquid Solvent Extraction Project 4-76 National Coal Board Low-Btu Coal Gasification Project 4-77 National Coal Board Supercritical Solvent Extraction Project 4-77

British Gas Corporation Composite Gasifier Project 4-61

Brookhaven National Laboratory Flash Hydropyrolysis Project ...... 4-66

Burlington Northern Circle West Project 4-60

Caterpillar Tractor Company Caterpillar Tractor Low Btu Gas From Coal Project 4-58

Celanese Corporation Celanese Costal Bend Project ...... 4-58 Celanese East Texas Project ...... 4-58

Central Illinois Light Co., Inc. ICGG Pipeline Gas Demonstration Plant Project 4-71 KILnGAS Project 4-72

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-49 Company or Organization Project Name Central Illinois Public Service ICGG Pipeline Gas Demonstration Plant Project ..... 4-7! Central Maine Power Central Maine Power Co.'s Sears Island Project ..... 4-59 Central Power and Light Chemically Active Fluid Bed Project ...... 4-59 Cities Service CS/R Process Development ...... 4-63 LC Fining Processing of SRC Extract ...... 4-73 Medium BTU Synthesis Gas Study ...... 4-74 Tennessee Synfuels Associates Mobil-M Plant ...... 4-81 Two Stage Liquefaction ...... 4-84 Clark Oil and Refining Corp. Clark Synthesis Gas Project ...... 4-60 Cleveland Electric Illuminating Co. NASA Lewis Research Center Coal-To-Gas Cogeneration Power Plant ...... 4-76 Coal Fuel Conversion Co. Ott Hydrogenation Process ...... 4-78 COGAS Development Company COGAS Process Development ...... 4-6! ICGG Pipeline Gas Demonstration Plant Project ..... 4-71 Columbia Gas System Inc. Columbia Coal Gasification SNG Project ...... 4-61 Combustion Engineering Two-Stage Entrained Gasification System ...... 4-84 CONOCO Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Emery Coal Conversion Project ...... -64 H-Coal Project ...... 4-71 Medium BTU Synthesis Gas Study ...... 4-74 Underground Coal Gasification - University of Texas .... 4-87 Zinc Halide Hydroeraeking Process Development ..... 4-86 Consolidated Natural Gas System Ohio Valley Synthetic Fuel Project ...... 4-78 Consolidated Gas Supply Corp. COGAS Process Development ...... 4-61 Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Consolidation Coal Company Underground Coal Gasification, Prieetown Project ..... 4-88 Consumer Energy Corporation Combined Cycle Coal Gasification Energy Centers . . . 4-61 Consumers Power Company KILnGAS Project ...... 4-72 Continental Group, Inc. Tennessee Synfuels Associates Mobil-M Plant ...... 4-74 Cook Inlet Region, Inc. Beluga Methanol Project ...... 4-58 Cooperative Power Association InterNorth Methanol Plant ...... 4-71 Crow Indian Tribe Crow Indian Coal Gasification Project ...... 4-62 Curtiss-Wright Corporation Gas Turbine Systems Development ...... 4-67 Department of Energy Acurex Aerotherm Low-BTU Gasifier for Commercial Use 4-57 Bell High Mass Flux Gasifier ...... 4-57 BI-GAS Project ...... 4-58 Cities Service/Rockwell Process Development ...... 4-60 Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Exxon Catalytic Gasification Process Development . 4-64 Exxon Donor Solvent Process Development ...... 4-65 Fast Fluid Bed Gasification ...... 4-66 Firing of Iron Ore Pelletizing Furnace with Low-BTU Producer Gas ...... - 4-66 Flash Hvdropyrolysis Project ...... 4-66 Flash Pyrolysis Coal Conversion ...... 4-67 Florida Power Combined Cycle Project ...... 4-67 Gas Turbine Systems Development ...... 4-67 Grace Coal-to-Methanol-to-Gasoline Plant ...... 4-68 Grand Forks Liquefaction Process for Low Ranked Coals 4-69 GREFCO Low-Btu Project ...... 4-70 Hampshire Gasoline Project ...... 4-70 H-Coal Project ...... 4-71 ICGG Pipeline Gas Demonstration Plant Project ..... 4-71 InterNorth Methanol Plant ...... 4-71 ITT Coal To Gasoline Plant ...... 4-72 Keystone Project ...... 4-72

4-50 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Com pany or Organization Project Name Page LC Fining Processing of SRC Extract 4-73 Low-Medium BTU Gas For Multi-Client Steel Complex 4-73 Lummus Coal Liquefaction Development 4-74 Memphis Industrial Fuel Gas Demonstration Plant 4-74 Minnegasco High-Btu Gas From Peat Feasibility Study 4-75 Minnegasco Peat Biogasification Project 4-75 Minnegasco Peat Gasification Project 4-75 Mobil-M Project 4-75 Molten Salt Process Development 4-76 New England Energy Plant 4-77 Philadelphia Gas Works Synthesis Gas Plant ..... 4-78 Pike County Low-Iltu Gasifier for Commercial Use 4-78 Riser Cracking of Coal 4-79 Slagging Gasifier Development 4-80 Solvent Refined Coal Demonstration Plant SRC-I 4-80 Solvent Refined Coal Demonstration Plant SRC-II 4-80 Two-Stage Entrained Gasification System ..... 4-84 Two-Stage Liquefaction 4-84 Union Carbide Coal Conversion Project ...... 4-84 Underground Coal Gasification Hanna Project 4-87 I-be Creek Project ...... 4-88 Mitchell Energy ...... 4-86 Pricetown Project 4-88 Steeply Dipping Bed Project 4-89 University of Texas ...... 4-87 University of Minnesota Low-BTU Gasifier for Commercial Use ...... 4-85 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-85 Dow Chemical Dow Coal Liquefaction Process ...... 4-63 Dravo Engineers and Constructors Keystone Project 4-72 duPont Underground Coal Gasification - University of Texas 4-87 Dynatech RID Company Minnegasco Peat Biogasification Project 4-75 EG&G New England Energy Project ...... 4-77 Electric Power Research Institute Conoco Pipeline Gas Demonstration Plant Project. 4-62 Cool Water Coal Gasification Project 4-62 Exxon Donor Solvent Process Development .... 4-65 If-Coal Project ...... 4-71 Two Stage Entrained Gasification System 4-84 Elgin-Butler Brick Co. Lignite Briquette Gasification Plant ...... 4-73 El Paso Natural Gas Company Burnham Coal Gasification Project ...... 4-58 Emery Synfuels Associates Emery Coal Conversion Project ...... 4-64 Energy Impact Associates Keystone Project 4-72 Enrecon, Inc. Enrecon Coal Gasifier ...... 4-64 Environmental Protection Agency Chemically Active Fluid Bed Project 4-59 Underground Coal Gasification - University of Texas 4-87 Extractive Fuels Inc. Underground Coal Gasification 4-86 Exxon, USA Catalytic Gasification Process Development 4-64 Donor Solvent Process Development ...... 4-65 Exxon Texas Project 4-65 Exxon Wyoming Project - Coal Gasification. 4-65 Underground Coal Gasification - University of Texas 4-87 Florida Power and Light Florida Power Combined Cycle Project ..... 4-67 FMC Corporation COGAS Process Development ...... 4-61 Ford, Bacon & Davis Mountain Fuel Supply Company Coal Gasification Project 4-76 Forest City, Iowa Forest City Coal Gasification Project 4-67

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-51 Company or Organization Project Name S Foster Wheeler Energy Corporation Chemically Active Fluid Bed Project 4-59 Froedtert Malt Corp. lnterNorth Methanol Plant 4-71 Gas Research Institute Bell High Mass Flux Gasifier ...... 4-57 Exxon Catalytic Gasification Process Development 4-64 Minnegasco Peat Gasification Project 4-75 General Electric Company Central Maine Power Co.'s Sears Island Project 4-59 Cool Water Coal Gasification Project 4-62 Gas Turbine System Development 4-67 GEGAS-D Project ...... 4-68 General Refractories Company GREFCO Low-Btu Project 4-70 Glen-Ger y Corporation Acurex Aerotherm Low-BTU Gasifier for Commercial Use 4-57 Georgetown Texas Steel Corporation Midrex Electrothermal Direct Reduction Process 4-75 W. R. Grace and Company Grace Coal-to-Methanol-to-Gasoline Plant ..... 4-68 Grace Synthetic Fuel Liquefaction Plant 4-68 Grand Forks Energy Technology Center Grand Forks Liquefaction Process for Low Ranked Coals 4-69 Slagging Gasifier Development 4-80 Great Plains Gasification Associates Great Plains Gasification Project 469 GRI Exxon Catalytic Gasification Process Development 4-75 Minnegasco Peat Gasification Project 4-64 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-85 Gulf Mineral Resources Company Conoco Pipeline Gas Demonstration Plant Project 4-60 Gulf Oil Corporation Solvent Refined Coal Pilot Plant SRC-II ...... 4-80 Gulf Research & Development Corp. Underground Coal Gasification - Steeply Dipping Beds 4-89 Hampshire Energy Group Hampshire Gasoline Project ...... 4-70 Hercules Inc. Whitehorne Coal Gasification Project 4-85 HEW Underground Coal Gasification - University of Texas 4-87 Houston Natural Gas Corp. Medium BTU Gasification Project 4-74 Howmet Aluminum Corporation Howmet Aluminum Project 4-71 Hydrocarbon Research, Inc. Fast Fluid Bed Gasification Project ...... 4-66 H-Coal Project ...... 4-71 Illinois Coal Gasification Group ICGG Pipeline Gas Demonstration Plant Project 4-71 Illinois Power Company KILnGAS Project 4-72 Illinois, State of KILnGAS Project 4-72 Inland Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-73 Institute of Gas Technology Riser Cracking of Coal 4-79 International Coal Refining Co. Solvent Refined Coal Demonstration Plant (SRC-I) 4-80 International Telephone and Telegraph ITT Coal to Gasoline Plant 4-72 InterNorth InterNorth Methanol Plant 4-71 Interstate Power Co. InterNorth Methanol Plant 4-71 Iowa Illinois & Electric lnterNorth Methanol Plant 4-71 Iowa Power & Light Company KILnGAS Project ...... 4-72 Iowa, State of Forest City Coal Gasification Project 4-67 Japan-SRC, Inc. Solvent Refined Coal Demonstration Plant (SRC-II) 4-80 Japan Coal Liquefaction Development Co. Exxon Donor Solvent Process Development ..... 4-65 Johnstown Area Regional Industries, Inc. Keystone Project 4-72 Jones and Laughlin Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-73 Kaneb Services Hampshire Gasoline Project ...... 4-70

4-52 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 Company or Organization Project Name ?QZ2 Kentucky, Commonwealth of H-Coal Project ...... 4-71 Ken-Tex Project ...... 4-72 Pike County Low Btu Gasifier for Commercial Use . . 4-78 Solvent Refined Coal Demonstration Plant - SRC-j . . 4-80 Tri-State Project ...... 4-82 Koppers Co. Hampshire Gasoline Project ...... 4-70 Tennessee Synfuels Associates Mobil-iM Plant ...... 4-81 Laramie Energy Technology Center Underground Coal Gasification - Hanna Project ..... 4-87 Lawrence Livermore Laborator y Underground Coal Gasification - Hoe Creek Project .... 4-88 Lehman Brothers Kuhn Loeb, Inc. Keystone Project ...... 4-72 Lone Star Gas Underground Coal Gasification - University of Texas .... 4-87 Lurnmus Company Lummus Coal Liquefaction Development ...... 4-74 Two Stage Liquefaction ...... 4-84 Mapco Synfuels Mapco Coal to Methanol Plant ...... 4-74 Memphis Light, Gas and Water Memphis Industrial Fuel Gas Demonstration Project . . . 4-74 Michigan Wisconsin Pipe Line Co. Great Plains Gasification Project ...... 4-69 Midrex Corporation Midrex Electrothermal Direct Reduction Process ..... 4-75 Miller, J. W. ITT Coal to Gasoline Plant ...... 4-72 Minnesota Gas Company InterNorth Methanol Plant ...... 4-71 Minnegasco High-Btu Gas From Peat Feasibility Study . . 4-75 Minnegasco Peat Biogasification Project ...... 4-75 Minnegasco Peat Gasification Project ...... 4-75 Minnkota Power Cooperative lnterNorth Methanol Plant ...... 4-71 Mississippi Power and Light Company De Soto County, Mississippi Coal Project ...... 4-63 Mississippi, State of Dc Soto County, Mississippi Coal Project ...... 4-63 Mitchell Energy Underground Coal Gasification ...... 4-86 Mitsui Solvent Refined Coal Demonstration Plant - SRC-11 . 4-80 Mobil Oil H-Coal Project ...... 4-71 Mobil-M Project ...... 4_75 Underground Coal Gasification - University of Texas .... 4-87 Mono Power Company Cherokee Clean Fuels Project ...... 4-60 Emery Coal Conversion Project ...... 4-64 Monongahela Power Company KILnGAS Project ...... 4-72 Montana Dakota Utilities InterNorth Methanol Plant ...... 4-71 Morgantown Energy Technology Center Underground Coal Gasification - Pnicetown Project .... 4-88 Mountain Fuel Resources, Inc. Emery Coal Conversion Project ...... 4-64 Mountain Fuel Supply Company Coal Gasification Process 4-76 NASA Lewis Research Center NASA Lewis Research Center Coal-To-Gas Cogeneration Power Plant ...... 4-76 National Coal Board Liquid Solvent Extraction Project ...... 4-76 Low-BTU Gasification Project ...... 4-77 Supercritical Gas Extraction Project ...... 4-77 National Steel Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-73 Natural Gas Pipeline Co. of America Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Nokota Company Dunn Nokota Methanol Project ...... 4-63 Norfolk and Western Railway Companies Whitehorne Coal Gasification Project ...... 4-85 North Dakota Synthetic Fuels Group InterNorth Methanol Plant ...... 4-75 North Shore Gas Company ICGG Pipeline Gas Demonstration Plant Project ..... 4-71 Northern Illinois Gas Company ICGG Pipeline Gas Demonstration Plant Project ..... 4-71 Northern Indiana Public Service Co. Low/Medium BTU Gas For Multi-Company Steel Complex 4-73

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-53 Company or Organization Project Name Northern Natural Gas Company Minnegasco Peat Biogasification Project ...... 4-75 Minnegasco Peat Gasification Project ...... 4-75 Northern States Power Co. InterNorth Methanol Plant ...... 4-75 Northwest Pipeline Corporation Nices Project ...... 4-77 Northwestern Public Service lnterNorth Methanol Plant ...... 4-71 Northwestern Wisconsin Electric Co. lnterNorth Methanol Plant ...... 4-71 Occidental Research Corporation Flash Pyrolysis Coal Conversion ...... 4-67 Ohio Edison Company KILnGAS Project ...... 4-72 Pacific Gas and Electric Co. Cherokee Clean Fuels Project ...... 4-60 Crow Indian Coal Gasification Project ...... 4-62 San Ardo Cogeneration Project ...... 4-79 Wyoming Coal Conversion Project ...... 4-85 Panhandle Eastern Pipe Line Co. COGAS Process Development ...... 4-61 Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Wyoming Coal Conversion Project ...... 4-85 Peat Methanol Associates Peat Methanol Associates Project ...... 4-78 Peoples Energy Company Great PlainsCoat Gasification Project ...... 4-69 Peoples Gas, Light & Coke Co. ICGG Pipeline Gas Demonstration Plant Project ..... 4-71 Philadelphia Gas Works Philadelphia Gas Works Synthesis Gas Plant ...... 4-78 Phillips Petroleum Corporation Exxon Donor Solvent Process Development ...... 4-65 Pittsburg and Midway Coal Mining Co. Solvent Refining Coal Demonstration Plant (SRC-II) . . . 4-80 Placer Amex Inc. Beluga Methanol Project ...... 4-58 Potomac Edison Company KILnGAS Project ...... 4-72 PPG Industries Medium BTU Synthesis Gas Study ...... 4-74 Public Service of Indiana KILnGAS Project ...... 4-72 Public Service of New Mexico Underground Coal Gasification - New Mexico ...... 4-86 Public Service of Oklahoma Chemically Active Fluid Bed Project ...... 4-59 KILnGAS Project ...... 4-72 Ralph M. Parsons Co. De Soto, County Mississippi Coal Project ...... 4-63 Republic of Texas Coal Company Underground Coal Gasification - Mitchell Energy ..... 4-86 Rockwell International Cities Service/Rockwell Process Development ..... 4-60 CS/R Process Development ...... 4-63 Molten Salt Process Development ...... 4-76 Rocky Mountain Energy Company Cherokee Clean Fuels Project ...... 4-60 Underground Coal Gasification - Hanna Project ..... 4-87 Ruhrgas Carbon Conversion. Inc. Wyoming Coal Conversion Project ...... 4-85 Ruhrkohle AG Exxon Donor Solvent Process Development ...... 4-65 H-Coal Project ...... 4-71 Solvent Refined Coal Demonstration Plant (SRC-H) . . . 4-80 Sandia Laboratories Underground Coal Gasification-Washington State ...... 4-89 Sasol Limited Sasol Two and Sasol Three ...... 4-79

Shell International Petroleum Co. S.K. Gasification Process ...... 4-79 Shell Oil Company Zinc Halide Hydrocraeking Process Development ..... 4-86 Southern California Edison Cool Water Coal Gasification Process ...... 4-62 Southwestern Electric Power Chemically Active Fluid Bed Project ...... 4-59 SRC International, Inc. Solvent Refined Coal Demonstration Plant (SRC-II) . . . 4-80 Standard Oil of Indiana H-Coal Project ...... 4-7t Standard Oil Company of Ohio Beacon Process ...... 4-57 Ohio Valley Synthetic Fuels Project ...... 4-78

4-54 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 Company or Organization Project Name Stearns-Roger Incorporated BI-Gas Project ...... 4-58 Slagging Gasifier Development ...... 4-80 Stone & Webster Engineering Group Central Maine Power Co.'s Sears Island Project ..... 4-59 Sun Gas Compan y Conoco Pipeline Gas Demonstration Project ...... 4-62 Tenneco, the. Great Plains Gasification Project ...... 4-69 SNG from Coal ...... 4-81 Tennessee Eastman Co. Chemicals From Coal ...... 4-60 Tennessee Gas Pipeline Company COGAS Process Development ...... 4-61 Conoco Pipeline Gas Demonstration Project ...... 4-62 Great Plains Coal Gasification Project ...... 4-69 Texaco, Inc. Central Maine Power Co.'s Sears Island Project ..... 4-59 Cool Water Coal Gasification Project ...... 4-62 Lake DeSmet SNG From Coal Project ...... 4-73 Medium BTU Gasification Project ...... 4-74 San Ardo Coal Generation Project ...... 4-79 Texaco Coal Gasification Process Development ..... 4-82 Texas A&M University Underground Coal Gasification of Texas Lignite ..... 4-90 Texas Eastern Corporation Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 New Mexico Lurgi Coal to Gas/Methanol Plant ...... 4-77 Tri-State Project ...... 4-82 Texas Energy and Natural Resources Advisory Council Lignite Briquette Gasification Plant ...... 4-73 Texas Gas Transmission Corp. Ken-Tex Project ...... 4-72 Tri-State Project ...... 4-82 Texas Mining and Mineral Resources Research Institute Underground Coal Gasification - University of Texas .... 4-87 Timberline Fuels. Inc. Ott Hydrogenation Process Project ...... 4-78 TOSCO Corporation TOSCOAL Process Development ...... 4-82 Transco Company Great Plains Gasification Project ...... 4-69 Transco Coal Gas Plant ...... 4-82 Transcontinental Gas Pine Line Co. Conoco Pipeline Gas Demonstration Plant Project ..... 4-62 Great Plains Coal Gasification Project ...... 4-69 Transwestern Pipeline Company Lake DeSmet SNG From Coal Project ...... 4-73 TRW. Inc. Beacon Process ...... 4-57 TRW Coal Gasification Project ...... 4-83 TVA TVA Ammonia-From-Coal Project ...... 4-83 TVA Medium BTU Coal Gasification Plant ...... 4-83 Union Carbide Corporation Low/Medium BTU Gas For Multi-Company Steel Complex . 4-73 Union Carbide Coal Conversion Project ...... 4-84 Union Electric Company I{ILnGAS Project ...... 4-72 United Coal Company Whitehorne Coal Gasification Project ...... 4-85 United Energy Resources Inc. Medium BTU Synthesis Gas Study ...... 4-74 University of Minnesota University of Minnesota Low-BTU Gasifier for Commercial Use 4-85 University of New Mexico Underground Coal Gasification - New Mexico ...... 4-86 University of North Dakota Grand Forks Liquefaction Process for Low-Ranked Coals. . 4-69 University of Texas Underground Coal Gasification ...... 4-87 USBM - Twin Cities Metallurgical Firing of Iron Ore Pelletizing Furnace with Low-BTU Research Center Producer Gas ...... 4-66 Utah International Crow Indian Coal Gasification ...... 4-62 New Mexico Lurgi Coal to Gas/Methanol Plant ...... 4-77 West Penn Power Company KILnGAS Project ...... 4-72

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-55

Company or Organization Project Name West Texas Utilities Company Chemically Active Fluid Bed Project ...... 4-59 Westinghouse Electric Fairmount Lamp Div. Coal Gas Project ...... 4-65 Keystone Project ...... 4-72 Westinghouse Advanced Coal Gasification System for Electric Power Generation ...... 4-85 Wheelabrator-Frye Solvent Refined Cool Demonstration Plant - SRC-1 4-80 Wyeoal Gas Inc. Wyoming Coal Conversion Project ...... 4-85

4-56 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS (Underline Denotes Changes Since March 1981)

SYNTHETIC FUELS FROM COAL

********************fl,***,**********4.*COAL CONVERSION

A.C. VALLEY CORPORATION PROJECT - A.C. Valley Corporation The A.C. Valley Corporation, a privately funded development company, proposes to construct and operate a 10,000 barrel per day coal liquefaction project in the Allegheny-Clarion Valley Region of Pennsylvania. Koppers gasification, ICI methanol synthesis, and Mobil methanol/conversion to gasoline processes will convert 4,950 tons per day of high sulfur coal to gasoline. A.C. Valley expects to raise the necessary capital from private sources for this project and submitted an application for a Federal Loan Guarantee to the SFC.

Project Cost: $600 million

ACUREX-AEROTI-IERM LOW-BTU GASIFIER FOR COMMERCIAL USE —DOE, Acurcx-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 'lTD Wellman-Galusha gasifier located at York, PA. The low-Btu gas is used to fire a brick kiln at the Glen-Ger y 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 Btu including cost of capital.

Project Cost: $1.6 million (50/50 DOE/participant funding)

AMAX COAL GASIFICATION PLANT - AMAX, Inc.

AMAX, Inc. is conducting a feasibility study for converting a plant formerly used by U.S. Steel in Duluth, Minn. to a coal gasification plant. The first phase of a two-phase study has been completed for the development of a site for the production of fuel-grade methanol from coal,

Project Cost: Feasibility Study -$4.5 million.

BEACON PROCESS - TRW, Inc. and Standard Oil Company of Ohio The Beacon Process, invented by TRW, is a joint development project with Standard Oil Company of Ohio to convert low Btu gas from air blown coal gasifiers or underground coal gasification to SNG and electricity. A modeling study of fixed and fluid-bed reactors for the process has been completed. Development is currently at the bench-scale stage and will be ready for PDU scale-up in the near future. A cooperative agreement provides for DOE cost sharing during a thirty month development period.

Project Cost S. Not available

BELL 111GM MASS FLUX GASIFIER - Bell Aerospace Text in, 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 100 milliseconds, A 0.5 ton-per-hour air blown reactor is being used for process evaluation. Reactor nominally operates at IS 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. Sixt y-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 IDU has been upgraded to incorporate a pressurized product gas handling system and improved product material collection and measurement capability. Current contract with DOE/GUI began September 1979. Design, fabrication and erection of PDU is complete. Checkout gasification tests were initiated during July 1980.

Project Cost: 1.5 million Phase I

*New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-57 STATUS OF SYNFIJELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont.)

BELUGA METHANOL PROJECT - Cook Inlet Region, Inc.. Placer Amex Inc. The Cook Inlet Regional Corporation is conducting a feasibility study for a 7,500 'F1'!) methanol plant using Alaska's subbituminous coal. A winkler 4 atm. gasifier will be used for gasification. IC! process will be used for methanol synthesis. Loan guarantees and price guarantees were requested from the SFC. A state industrial site application has been applied for. Plant site is on private land owned b y Cook Inlet Region, Inc., approximately 60 miles west of Anchorage. Construction is expected to begin the second quarter of 1984.

Cost: $3.9 million (study) RI-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 b y Stearns-Roger Incorporated. Initially, program management functions were provided by the Phillips Petroleum Company for nCR the prime contractor. Roth 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 SCUD of SNG. Efforts are currently directed to solving operating problems using Rosebud subbituminous as test coal and to improving operabilit y 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 pla nt has had continuous runs of 170. 120 and 100 hours on Rosebud coal with all systems operating satisfactorily and reliably. Majorthrust of the ram in FY 1981 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. RURNUAM 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. flue to an eleven-weekgg strike in the last quarter of 1979 and some minor equipment changes that had to he made, debu ing was not resumed until May 1980. Tests have been run on existing radiant tubes using producer gas with no adverse effect. Gas is currently being produced with modifications to equipment and proceeding as necessary. After 20 weeks of operation, the system was shut down in December 1980 for the holidays. p The system has been O erating since Februar y and the y expect to run it until the Jul y vacation shut-down.

Project Cost: $5-1 million, CELANESE COSTAL BEND PROJECT - Celanese Corporation Celanese Corporation has contracted with Stearns Roger. Inc., to complete a feasibility study for a gasification project to provide chemical feedstocks as well as fuel at the Celanese, Bishop, Texas plant. Lignite or subbituminous coal would be shipped to the facilit y. Plans call for completion in the late 1980's. Project Cost: Over $10 million for both East Texas and the Costal Bend project studies

*New or Revised Projects.

4-58 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUEL.S PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (ConL) *CELANESE EAST TEXAS PROJECT - Celanese Corporation Celanese has contracted with Rust Engineering to prepare a feasibility study for a pnssible mine mouth coal gasifiction facility to produce chemical feestocks from Texas lignite. The project is expected to be completed in the late 1980's.

Project Cost: Over $IC million for both East Texas and the Costal Bend project studies. CENTRAL ARKANSAS ENERGY PROJECT - Arkansas Power & Light Company Arkansas Power & Light Company is sponsoring a combined cycle cogeneration process using the Texaco coal gasification p rocess. Loan guarantees were requested from the SF0. The project would be located at the White Bluff steam electric station, five miles from Redfield. Arkansas. The project will he designed to produce 120 billion Btu's per day of medium Btu gas. When burned in one or more combined cycle cogeneration plants, approximatel y 430 MW of electrical energy and 1.8 million pounds per hour of Process steam will he produced from the gas. Project Cost: Undetermined

CENTRAL MAINE POWER Co.'s SEARS ISLAND PROJECT - Central Maine Power Co., Texaco Inc., General Electric Co.. and Stone & Webster Engineering Corp. A feasibilit y studyf or a commercial-scale coal gasification combined cycle power plant to be located on Sears Island, Maine was initiated in October 1980. with DOE funding. The stud y's objectives include: (i) develop process design including equipment and process selection: (2) determine capital costs and construction timetable: (3) evaluate operating and maintenance costs, reliability, and operating characteristics; (4) compare the cost of energy from the IGCC plant to a coal-fired plant and identify benefits and risks; and (5) prepare plans for final design and financial arrangements. Texaco provides design of coal grinding and gasification using the Texaco Coal Gasification Process. GE provides the design of the combined cycle part of the plant, including turbines, electrical and steam systems. SWEC provides design of coal receiving, handling and storage, plant la yout. oxygen plant and balance of plant. Preliminary engineering is approximately 35 percent completed and the heat and material balances are virtually complete. At ISO conditions, the preliminary plant capacity is 520 MW net at 5,120 tons/da y coal.The heat rate is currentlyl ca culated at approximately 9.500 [flu/Kwh. The equipment includes 4 gasifiers plus I spare. 2 sulfur removal trains, 4 gas turbines and heat recovery steam generators, and 1 steam turbine. The design coal is Kentucky No. 9(11.800 Btu/lb.. 3.9 percent sulfur. 15 percent ash). Project Cost: $3,560,773 (DOE Contract). CHEMICALLY ACTIVE FLUID RED 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 Faso 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 GAS) 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-Stu fuel. The plant is located at CP&L's La Palma Station, San Benito, TX. The three other utilities share construction and operating expenses with CP&L. The plant is designed to use lignite or heavy high sulfur fuel oil as primary fuel. The unit has gasified No. 6 fuel oil for 510 hours in five separate runs. The generator has produced up to 22 MWe power with the boiler firing product gas from the gasifier. No. 6 fuel oil input was approximately 17.000 lb./kr. at the 22 MWe load. During the periods of operation, the product gas from the gasifier has produced 4.4 x 10 Kw hours of electricit y. Measured stack emissions have been with NSPS limits. In addition, initial trials with Texas Lignite and Eastern Bituminous coal have produced 110.000 kW hours of electricit y. Additional operation on Eastern bituminous coals is planned for early second quarter 1981. Project Cost: $13.5 million

New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-59 STATUS OF SYNPUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.) 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 constructing a multi-million dollar project to produce industrial chemicals from coal. Texaco's coal gasification process will be used to produce the synthesis gas for manufacture of acetic anydride. Other chemicals, including methyl alcohol and acetic acid will also be produced Bechtel Inc., is in charge of the process design, engineering, and procurement. Construction began late in 1980 in Kingsport, Tennessee, with start- up planned in mid-1983. Locally mined coal will be used Status: Engineering is proceeding as planned. Daniel International unit of Fluor Corp. is the general construction contractor while Bechtel Petroleum, Inc.. Houston, Texas, is providing construction management.

Project Cost: Unavailable

CHEROKEE CLEAN FUELS PROJECT - Rocky Mountain Energ y, Bechtel Corporation, Pacific Gas & Electric Co.. More Power Co. Rocky Mountain Energy (RIME), a subsidiar y of Union Paefic, is conducting a feasibility study of a high Btu coal gasification plant in Sweetwater and Carbon Counties, Wyoming. A combination of Lurgi and Koppers Totzek gasifiers would be used to produce 125 MMSCFD of SNC, beginning in 1986 and increasing to 250 MMSCFI) in 1989.

Cost: Study: $4 million. - - CIRCLE WEST PROJECT - Burlington Northern Burlington Northern (BN) has studied the feasibility of locating a proposed commercial plant for fertilizer and liquid fuels from coal on BN-owned Dreyer Brothers ranch near Circle, MeCone Count y , Montana. FIN 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 NH q plus 2.174 TPD fuel-grade methanol. Basin Electric Power Cooperative joined BN- IDre yer Bros. in September 1977, to evaluate the feasibility of a power plant having common coal mining facilities with BN plant. Lignite would be used in synthetic fuels or fertilizer plant or for Basin Electric plant.

Project Cost: Undetermined CITIES SERVICE/ROCKWELL PROCESS DEVELOPMENT - DOE and Rockwell International (Energy S ystems Group) Rockwell is developing coal liquefaction and gasification using the Cities Service /Rockwell (CS/R) Flash H ydro- pyrolysis Process (PUP). Technique involves the near instantaneous and thorough mixing of streams of pulverized coal and hot hydrogen in a compact coal conversion reactor derived from Rocketd yne 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 TPII throughput levels. DOE awarded Rockwell an $18 million contract to design, construct, and operate an 18 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 Lurnmus, a subsidiary of Combustion Engineering, Inc., has been selected by Rockwell International Corporation to develop the commercial design concept for a 250-billion Btu/da y 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 18-ton/day integrated process development unit test program currently being undertaken by Rockwell International.

Pfojcct Cost: $3.2 million (PDU Studies) $18 million pilot plant *CLARK SYNTHESIS GAS PROJECT - Clark Oil and Refining Corp. Clark requested $4 million from the DOE for a feasibility study for a synthesis gas plant. The project will use a Koppers-Totzek gasifier and the ICI process to convert the synthesis gas into methanol and the Mobil M process to convert the methanol to gasoline. The proposed site is near New Athens, Ill. The feasibility study is planned to be completed the first quarter of 1982. Clark requested a combined system of loan and price guarantees from the SEC.

Total Cost:$4 million feasibility study

*New or Revised Projects.

4-60 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.)

COGAS PROCESS DEVELOPMENT - CODAS 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 IOU tons of coal per day is located at the Coal Utilization Research Laboratory (CURL) of the National Coal Board in Leatherhcad. England. Process development is now primarily under the DOE/ICGG Pi peline Gas (SPG) from Coal Demonstration Plant Program. Demonstration plant process design is completed and detailed engineering is nearing completion. 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 exchanged an interest in some of its West Virginia coal lands for an interest in some of Exxon Coal's Illinois coal lands.

Project Cost: Undetermined

COMBINED CYCLE COAL GASIFICATION ENERGY CENTERS - Consumer Energ y 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. 321 MW power generation and 220 ST/D elemental sulfur. Feedstock is high sulfur Missouri coal. Status: The Economic and Technical Feasibility Report, including preliminary environmental and socio-economic impact study, has been completed. Preliminary engineering and design phase to start in early 1981. Phase I includes 7 work tasks and will last one year. Construction is scheduled for 1983. and start-up date for both facilities is projected as late 1985. The project team consists of the following: Consumer Energy Corporation, Associated Electric, Cooperative Inc., Lutz. Daily & Brain, Consulting Engineers, Foster Wheeler Energy Corporation, Midwest Research Institute, Arthur Andersen & Co., Stern Brothers & Co., Lazard-Freres & Co., Mudge, Rose. Guthrie & Alexander, and Stockard, Andereck, Hauck, Sharp & Evans.

Project Cost: 416.4 million (each plant)

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 temoerature. resulting in substantially complete gasification. The molten slag produced is removed by tapping, using the technique successfully develo ped for the Slagging Gasifier. The very hot product gas passes into the fixed bed to yiel d its heat to the descending lump coal.A feasibility study for a 150 tonne pilot plant was completed by lIumphres and Glasgow, Limited. Worle y 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)

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-61 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont.)

CONOCO PIPELINE GAS DEMONSTRATION PLANT PROJECT - DOE and Conoco Coal Develo pment Co.(CCDC). with co-offerors Consolidated Gas Supply Co. Electric Power Research Institute. Gull 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. Currentl y 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 SNO. 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 seeping meeting was held in Caldwell, Ohio in December 1979. A Draft Environmental Impact Statement (DEIS) was delivered to EPA in October 1980. The final EIS was scheduled to be available in mid-May. Status: The engineering design, is complete. A 90 percent design review was held in Ma y. All environmental permits are have been acquired for the projecCXfl process licenses necessary for e6nstructiiiliavibeenacquirec1. - Project Cost: Design Phase - $37 million

COOL WATER COAL GASIFICATION PROJECT - Southern California Edison, Texaco, EPRI, Bechtel Corporation. General Electric Sponsors plan a 1,000 tons coal per day demonstration plant using oxygen-blown Texaco coal gasification process. During initial shakedown, medium-Btu 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, and construction is scheduled to commence in July 1981. 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 (Utah). 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 and construction contractor and also executed an agreement in September to contribute $25 million to the project. An agreement in principle has been reached with Airco. Inc. to provide ox ygen and nitrogen from an on-site facilit y, thus reducing

on utner organizations are acing actively sougnt to join in tne elIort as larding participants. for the project have been obtained and final engineering design b y Bechtel is well underway. Project Cost: $300 million

*CROW INDIAN COAL GASIFICATION PROJECT - Crow Indian Tribe, Utah International. Pacific Gas and Electric Corporation The Crow Indian Tribe requested $2.8 million from the DOE for a feasibility study for a mine mouth coal gasification plant. The 65,000 bbl/d Lurgi plant will be designed by Fluor. Utah International will mine the coal from the Indian's land. Pacific Gas and Electric will operate the plant. Cost: $2.8 million (study) $3 to $4 billion (project)

*New or Revised Projects.

4-62 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont) CS/R IIYDROPYROLYSIS 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 qualit y gas and light aromatic liquids. Reactor is of entrained flow type with short residence time (c 2 sec.) and rapid quench of the reactor products. Cities Service holds patent No. 3,960.700 on the p rocess. 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--79ET14943 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 IDE SOTO COUNTY. MISSISSIPPI COAL PROJECT - State of Mississippi. Mississippi Power & Light Compan y, 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 byN. Bunker Hunt. Mississippi Power & Light Co. (MP & L) 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-da y laboratory pilot plant. The process uses an expendable mol ybdenum based catal yst. A solution of a water soluble molybdenum compound is emulsified in rec ycle solvent and the resultant emulsion is dispersed in the slurr y of pulverized coal and recycle solvent prior to liquefaction. H ydroelones are used to achieve a partial solids removal from the reactor product and to provide a partial recycle of catalyst to the reactor. !I ydroclone underflov is extracted with paraffinic solvent in a countercurrent liquid-liquid extractor to produce solids-free, low sulfur deasphalted oil and a high solids residue which is suitable as a gasifier feedstock. The recycle solvent for the process comprises 3 parts of hydroclone overhead to I part of deasphalted oil. Dow 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 possibilit y with a number of oil companies. Project Cost: Undetermined DUNN NOKOTA METHANOL PROJECT - The Nokota Company In Februar y 1980. Nokota filed a "Prevention of Significant Air Quality Deterioration Permit Aoolication" 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 o perate the plant and nine. Ninety percent of the environmental baseline studies are com plete, and all critical permits are expected to be obtained by Summer, 1982. Mechanical construction is scheduled to begin during Summer, 1983; and mechanical completion is scheduled for Fall, 1986. with full production by Summer. 1987. 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.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-63 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont) EMERY COAL CONVERSION PROJECT - Emery Synfuels Associates, (Mountain Fuel Resources. Inc., Mono Power Company, and Conoco Coal Development Company) Emery Synfuels Associates proposes to build a gasification plant at a site near the town of Emery, Utah. Preliminar y approval of the site has been secured from the Utah Interagency Task Force on Power Plant Siting. Mountain Fuel Resources, Inc., has signed an option agreement to acquire water rights from the Muddy Creek Irrigation Co. Initial plant designs are being prepared based on the Lurgi process. The projected plant would produce 125 billion Btu's per day of substitute natural gas and methanol. Mountain Fuel Resources, Inc., Mono Power Company, a subsidiary of Southern California Edison Company. and Conoco Coal Development Compan y are conducting a feasibility stud y of the technical, economic, regulator y, and business aspects of the project. Completion of the studys i scheduled for November 1981. The Bureau of Land Mangement will act as lead agency for preparation of the draft EIS for the oroicct. Seaming meetimrs to receive nubile comment on the nrMnntu,nrn

Project Cost: Undetermined ENRECON COAL GASIFIER - Enrecon. Inc. Enrecon is developing a fluidized bed, medium-Btu coal gasification process in Golden. Colorado. The process can utilize a proprietary catalyst to improve gasifier performance. The 60 TPD Phase I pilot plant began operation in December 1979, and was operated - tip to August. - 1980. New -kinetic and equilibrium -models predict-system oerformance for different feed materials for SNG and synthesis gas production. Preliminary design work is underwa y for a scaled-up 600 TPI) demonstration plant, in addition to a preliminary economic assessment and Phase II program. Enrecon predicts over 80 percent cold gas efficiency at over 400 Btu/SCF using either western subbituminous or eastern bituminous coals. of Santa Fe International, has been commissioned to conduct an evaluation of how the

com

Estimated Cost: Over $5.0 million for 60 TPD Phase I pilot plant, $7-8 million for Phase II non-integrated PDU, totally private to date. EXXON CATALYTIC GASIFICATION PROCESS DEVELOPMENT - DOE. Gill 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 (CR1) 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 7CO 3 ) which promotes both the steam-carbon gasification and methanation reactions when added to the feed coal. Operating at 1.300° F and with the promotion of the R 7CO3 catalyst, the gasification rate is high enough to yield a high CH 4. concentration. Since the amount of CO and I{2 recycled back to the gasifier balances the amount of CO and H leaving the gasifier. the net products of gasification are mainly CF!4 with lesser amounts of CC) 2' II 2S. and NH 3' inee methane is produced directly in the gasifier, the need for water shift and methanation reactors and for an oxygen plant are eliminated One of Exxon Corporation's Dutch affiliates, Esso Steenkool Technology, plans to construct and operate a 100 ton-per-day pilot plant at Rotterdam. Europort, Holland. and operation is expected to begin in mid-1985. The new plant is part of an 8-year pilot project and is expected to cost more than $500 million. DOE participation in the supporting research and engineering in the U.S. in 1981 and beyond is being negotiated.

Project Cost: $16.8 million (DOE contract)

4-64 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.)

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 stud y activities. The $296 million program runs for 8.5 years (1976 to mid-1984). The overall costs of the project are proportioned as follows: DOE -50 percent. Exxon - 22 percent. EPRI - 12 percent. JCLD - 8 percent, Philli ps - 2 percent, Atlantic Richfield - 2 percent, Ruhrkohle - 2 percent. and AGIP - 2 p ercent. Contracts for the pilot plant were awarded in September 1977: Arthur C. McKee and Co., design; Daniel Construction Co., construction. Pilot plant start-up began in March 1980; coal-in operation began June 24, with Illinois No. 6 coal The unit has logged over 3300 hours of coal in operation as of the middle of May with a longest run of 3 days. Exxon, Company U.S.A. is the plant operator. A program to operate a FLEXICOKING* prototype on PUS vacuum bottoms feed is now underway. Part I, engineering design studies, (5.6 M$) was approved by the project sponsors. Part II of this program, revamp and operation of the 750 B/D FLEXICOKING unit, is being supported by the U.S. Department of Energy - 50 percent. Exxon - 36 percent, JCLD -8 percent, Atlantic Richfield - 2 percent, Ruhrkohle - 2 percent, and AGIP - 2 percent. Field construction began in 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: $296 million - Phases lIlA-V $5.6 million - Part I: FLEXICOKING 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 and Smith. The plant would produce 800 .MIMCFD of 400-Btu gas and 10,000 bbl/da y of liquids. The products could be used for industrial fuel or chemical raw materials. SASOL has tested a 16.000 ton sample of the coal to determine the technical feasibility of the Lurgi process for gasifying this lignite. Exxon signed a licensing million agreement with Lurgi Kohle and Mineraloltechnik of West German y for the preliminary design phase. Concurrent with the design phase are environmental permitting and product marketing activities. A decision to construct the plant will be made upon completion of those activities which are expected to last two years. The Reg ion VI Environmental Protection Agency held an EIS scoping meeting for the project late in 1980 in Jacksonville. Texas. The draft EIS should be available for review in September 1981.

Project Cost: $20+ million for detailed design $2 billion for commercial plant

EXXON WYOMING PROJECT. COAL GASIFICATION - Exxon Coal, USA Exxon is studying the possibilit y of constructing a coal gasification plant in northern W yoming. Gas from the plant could be processed to produce SNO. 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

FAIRMONT LAMP DIVISION PROJECT - Westinghouse Electric Corporation The Westinghouse Lamp Division at Fairmont. West Virginia, requires clean fuel gas, electric power, and steam for the production of electric light bulbs for fluorescent and automotive use. To assure a fuel gas supply, and to conserve energy, the Lamp Division management chose a Westinghouse gasification system to provide the clean fuel gas, power, and steam from a 13 ton-per-hour-coal-fed gasifer to fuel a 6-megawatt combustion turbine, with 50,000 pounds-per-hour of waste heat steam production, and 515,000 sef-per-hour of medium-Btu fuel gas production. A feasibility and preliminary design study for this project has been proposed to DOE. A formal application for financial incentives will be submitted to the SFC u pon obtaining results of the study.

Project Cost: $1.9 million.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-65 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont)

FAST FLU!!) BED GASIFICATION - DOE and Hydrocarbon Research, Inc. (Subsidiary of Dynalectron Corporation) URI has designed, constructed and operated a nine TPD Process Development Unit (PDU) to further develop the Fast Fluid Bed (FF6) Gasification process. The FF8 concept was developed at the City University of New York. It operates at high gas velocit y with recycle of solid char. The advantages of this mode are high ca pacity, good turn down and the ability to gasify caking coals at temperatures intermediate between conventional fluid beds and entrained beds. The process can produce a low or medium-Btu gas. The PDU gasifier is located at the IIRI 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 Metallurgi- cal Research Center, DOE, and I7 corporations with interest in iron and steel, coal gas, and industrial engineering. The U.S. Bureau of Mines announced plans to install a 36 TPI) Wellman-Galusha coal gasifier at the Twin Cities Metallurgical Research Laboratory (Minn.) in March 1977. The 6 1. 6" diameter gasifier, supplied by Hanna Mining Co., provides-low-Btu fuel gas for a 12 TPD pilot grate-kiln taconite pellet induration furnace presentl y 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 coal fines was started October 1979, but was aborted after 10 hours. Phase I of the contract has been completed and Phase El is underway. Modifications to the gasifier facility were completed and testing began in October 1980. A 30 day continuous operation with North Dakota "Indian Head" lignite was completed in November 1980. The test used approximately 1000 tons of lignite, and included pellet testing. A 10-day gasification test with briquettes (2 1/4 x 2 1/4 x 1 3/8 pillow shape) made from a mixture of coking coal and a refuse derived fuel (RDF) via the Simplex Process was scheduled for early spring 1981. The Bureau of Mines is now in the process of seeking a contractor to operate the gasifier under the direction of the Bureau and a Government-industry group called MIFGA (Mining and Industrial Fuel Gas group). RFP Package for Contractor Service will be submitted in May - award should be made by September 30. 1981. Ten day around-the-clock tests will commence in June 25 as follows: June 16-25 - Medium caking bituminous coal from West Virginia *July 23 - August 1 - North Dakota "Indianhead" lignite fines (3/4" x 1/411) August 13-22 - Colo-W yo subbituminous coal Sept. 15-24 - "Simplex" Briquettes Oct 20-29 - Texas lignite or high caking, high sulfur bituminous coal includes pelletizing tests 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 u p to 4,000 psig and 900' C. The purpose of the study is to determine the effects of reaction variables and the process chemistr y 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 (tO percent benzene 10 percent oils) and gases (31 percent CH 41 10 percent CU 6, 4 percent CO). Maximum conversion to gases occur at 875° C and 2500 psi with 90 percent conversion to all gases (89 percent CU 4 • C 2 Ua and 1 percent CO). Yield data for subbituminous coal have been obtained Benzene yields are up to t5 per with 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

4-66 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Coat)

'FLASH PYROLYSIS COAL CONVERSION - DOE. Occidental Research Corporation DOE awarded Occidental a three year $4.5 million cost sharing contract in October 1980 to further develop the flash pyrolsis process of coal conversion. Occidental had a previous contract with DOE to study the process from 1976 to 1978. Developed originall y by Occidental, the process heats coal rapidly at atmospheric pressure in a chamber filled with an inert gas, devoid of oxygen. Under these conditions, the coal breaks down into a carbon-rich char and hydrogen rich gases and liquids which can be upgraded to useable fuels. Earlier work on n 3 TPD unit had indicated methods of upgrading liquid yields that will be tested in the present program. The effect on product yield of varying the make-up of the inert gases used in the process will be tested. In addition, the chemical reactions taking place when the hydrogen donor quench li quid contacts the hot product vapors will he studied. Initial work will be on non-caking coals.

Project cost: Total: $4.5 million DOE: $2.25 million Occidental: $2.25 million

'FLORIDA POWER COMBINED CYCLE PROJECT - Florida Power and Light, DOE The DOE awarded Florida Power and Light $1,380.796 for a feasibility study for a medium Btu combined plant to be located in Pinellas Count y . Florida.

Project Cost: $1,380,796

FOREST CITY COAL GASIFICATION PROJECT - Outings Energy Corp: Forest Cit y , Iowa: State of Iowa I3illinv's Energy Corporation proposes to build a h ydrogen-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 oressure swing adsorption process to produce 4.1 billion Btu per day of hydrogen. H ydrogen to he used for power generation and to supplyf uel to an industrial complex. Project funded $100,000 by Iowa State appropriation, and $65.000 contribution from Forest City. Additional funding requested throu gh the Department of Energy. Schedule calls for groundhreaking by January 1, 1983. The application to the SFC cited, plans to use the Texaco gasifier for the project.

Project Cost: Phase I - Economic Analysis, technical viability-$165.000 Patents and Impact Statements - 24 months Phase 2- Engineering, contract issuance (12 months) Phase 3- Construction - $50 million (24 months)

GAS TURBINE SYSTEMS DEVELOPMENT —DOE. General Electric Co.. and Curtiss-Wright Corp. General Electric and Curtiss-Wright are currently participating in Phase II of a three-phase DOE sponsored program. the High Temperature Turbine Technology (117T) 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 lrfl'T Program (Technology Testing and Test Support Studies) was awarded to General Electric ($31.5 million) and to Curtiss-Wright ($27.4 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 Ill of the IITTT 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 Ill - Undetermined

'New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-67 STATUS OF SY14FUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont) GEGAS-D PROJECT - General Electric Co. G.E. has developed 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 were evaluated on the 24 TPD reactor. An overall objective of this facility is to provide a realistic simulation of an integratéWjüification, gas turbine combined cycle system. G.E. has operated the gasifier at rated conditions on Pittsburgh #8 and Illinois #6 caking coals. Recent tests have been completed with the gasifier, physical gas cleanup and combustion systems in operation. A chemical cleanup (1125 removal) system has been added to the facility and check out tests have been completed. The total gasification, gas cleanup, turbine simulation is now operational. It has been utilized to evaluate gas turbine compatibilit y with this coal derived fuel class. The fuel plant simulator will also evaluate the critical component integration features. A test series has 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 I. A major project emphasis is the characterizing of the performance of the fuel plant's components and integrated system under steady state and dynamic load conditions. A $9.3M three year

Project Cost $3.1 million - - GRACE COAL-TO-METHANOL-TO-GASOLINE PLANT - (DOE, W. R. Grace & Co.) Cooperative Agreement No. DE-FCOI-80ET-14759 was awarded to W. R. Grace & Co. in August 1980. A Notice to Proceed with the performance of the efforts required under the Cooperative Agreement was executed on October 6, 1980. The Cooperative Agreement calls for the preliminar y 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. Contractual arrangements have been completed with the Ralph M. Parsons Company for architect/engineer and related services, and with Texaco Development Corporation for the supply of proprietary inputs regarding the TCGP. Activities undertaken to date include preliminar y land assessment studies, develo pment of mana gement plan documentation, initiation of

Project Cost: Preliminary design -$12.6 million (DOE) Construction cost - $3.0 billion (1980 dollars) GRACE SYNTHETIC FUEL LIQUEFACTION PLANT - W. R. Grace & Co. %V. R. Grace & Company is studying the feasibility of building a liquefaction plant using coal reserves in northwest Colorado in Moffat County 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. The project has been accepted for the Colorado Joint Review Process, Colorado's permit expediting process. In March of 1981, Grace applied to the Synthetic Fuels Corporation for a price guarantee of 75

Project Cost: $500 million

4-68 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.)

GRAND FORKS LIQUEFACTION PROCESS FOR LOW-RANK COALS —DOE, Grand Forks Energy Technology Center, Universit y of North Dakota Grand Forks Energy Technology Center (GFETC) and University of North Dakota (UND) researchers are engaged in liquefaction research to adapt a direct liquefaction process expressl y for use with low-rank coals, (LRC) and synthesis gas, effectively utilizing the properties unique to LRC, including high moisture and reactivity;to determine the effects of residence time distributions and heating rates, including staged heating, especially for the reactions between the CO in syngas and LRC which occur more rapidly than with El ; to develop a model, based on correlations of solvent properties, product yield and feedstocks, for predicting so?vent quality effects; to correlate liquefaction products, byproducts, and effluents with coal-specific effects; and to determine the treatability of LRC liquefaction wastewater. Recent work has sought to compare the liquefaction behavior for geographically dissimilar lignites, one from the Gulf Coast Region, Texas, and the others from the Northern Great Plains, North Dakota. The principal difference in the lignites studied is found in their ash composition, with the Northern lignites containing appreciably greater concentrations of alkali, especially sodium. In addition to screening tests performed in cold-charged and hot-charged time-sampled batch autoclaves, reactions were carried out in the GFETC continuous process (CPU) unit. Operating conditions in the nominal 10-lb/hr coal slurry CPU were 2000 to 2600 psig at 460' C. with H 2 or mixtures of if and CO. Once-through, coal-only reactions employed a surrogate recycle solvent. In recycle operation, a portion o the heavy product slurry, including ash and unreacted lignite, was used as the vehicle solvent for fresh lignite. Both Texas and North Dakota lignites gave a yield of distillable products on an MAF basis, 46 percent equivalent to that reported from a bituminous coal in the SRC II mode. These results indicate that the slightly higher hydrogen requirements and lower yields on an as- received basis for lignite may be more than offset by the substantially lower feedstock cost as compared to bituminous coal. Grand Forks concludes that lignite gives distillate yields which are comparable to bituminous coal if the process employs bottoms recycle, and that there is no appreciable difference in the liquefaction behavior of at least one Texas lignite in comparison with North Dakota lignite.

Project Cost; $1.42 million, FY 1980

*GRANTS COAL TO METHANOL PROJECT - Energy Transition Corporation Energy Transition Corporation proposed to build a 50 million gallon per year coal-to-methanol plant using the KBW gasifier. Ultimate production would be 500 million gallons per year. Price guarantees of 75 cents per gallon (January 1981 dollars escalated quarterly at the inflation rate plus 4 percent) were requested from the SFC. Preeonstruction activities for the plant would be gin in 1981. Plant location is the Lee Ranch, 32 miles northeast of Grants, New Mexico.

Project Cost; Undetermined

GREAT PLAINS GASIFICATION PROJECT - Great Plains Gasification Associates, (Subsidiaries of American Natural Resources Compan y , Peoples Energy Corporation, Tenneco Inc., Transco Companies. Inc.) Michigan Wiconsin Pipe Line Company, a subsidiar y of ANR, initiated design work for the Mercer County, North Dakotap project in 1973. ANG Coal Gasification Company was formed in 1975 to construct and operate the facility. An a plication 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. '['hey size of the plant was reduced to 125 million cubic feet/day in 1976, and Peoples Gas Company (now Peoples Energ 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 Transcon- tinental Gas Pipeline Corporation, in addition to the two original p roject 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 Lummnus 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.

*New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-69 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont.) GREAT PLAINS GASIFICATION PROJECT (Cont.) 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 of Great Plains' request for a Certificate of Public Convenience and Necessit y 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 IS. At the hearing. FERC issued the Certificate 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. aopeals 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, effectivel y placing another temporary obstacle to the construction of the Great Plains project, which had been expected to begin in April. 1980. As a result of the delay, ANG requested a $250 million loan guarantee to cover costs for the first year of construction. The White House announced approval of a conditional letter of commitment for the loan on July 18, 1980. On-November- 19, DOE announced eondtioaai approval for a loan guarantee of up to $1.5 billion of project costs. This new commitment incorporates the $250 million loan guarantee. DOE has previously testified before FERC in support of this project and has provided approximatel y $25 million to the project sponsors under a cooperative agreement for the planning and mobilization of the architect 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, 1980. The Appeals Court overturned FERC's decision in December. 1980, saying that the FERC overstepped its authority in granting the project provisions, including the surcharge, that would impact on gas customers prior to the start-up of gas production and delivery of synthetic gas into the nation's interstate pipeline system. After three months of negotiations among the project sponsors. the FERC staff and the intervenors. an offer of

Negotiations focused principally on the pricing provisions under which the synthetic gas will he sold by Great Plains to its four pipeline customers. Plans call for pipeline subsidiaries of each of the Great Plains sponsors to purchase 25 percent of the plant's output. or approximately 30 million cubic feet of gas per day Great Plains sponsors have notified the Department of Energy of the settlement offer. A DOE loan guarantee of $1.8 billion has been pending FERC approval of the settlement. - On Aoril 30. FERC approved the offer of settlement with modifications.

Project Cost: Plant (137.5 MMCFD) $1.6 billion Mine (Gasification Plant Share) $150 million Escalated to 1983 *GREFCO LOW-BTU PROJECT - DOE, General Refractories Company (GREFCO) DOE awarded General Refractories Company approximately $1 million to perform an engineering feasibility study for a low Btu mine mouth facility. The 3.5 billion I3tu/D of industrial fuel gas produced would be used for dr ying of building products and also for fuel in perlite-expanding furnaces.

Project Cost: Undetermined HAMPSHIRE GASOLINE PROJECT - Hampshire Energy Group (Northwestern Mutual Life Insurance, Allis-Chalmers. Koppers Co., and Kaneb Services) DOE Hampshire Energy Group requested $4 million from DOE to study the feasibility of converting western coal to gasoline at a site near Gillette, Wyoming. Combination Lurgi and Koppers gasifiers will be used with the Mobil MTG catalytic process to produce 19,377 barrels per day of gasoline. Fluor Corporation has begun work on the study. Hampshire Energy requested price and loan guarantees from the SF0.

Project Cost: $7 million (study)

*New or Revised Projects

4-70 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont)

H-COAL PROJECT - DOE, Ashland Synthetic Fuels, Inc., Conoco Coal Development Co.. Mobil Oil Corp., Standard Oil Co. (Indiana), Commonwealth of Kentucky. Electric Power Research Institute, Ruhrkohle AG (West Germany). Hydro- carbon Research Inc., (subsidiary of Dynalectron Corporation) During May 1980. coal liquefaction operations began on the 600 TPD H-Coal pilot plant located near Ashland's Catlettsburg, Kentucky oil refinery. Initial break-in operations were completed in mid-November and the plant was then shutdown for maintenance and mechanical improvements. To date, the plant has operated in the syncrude mode continuously for 45.5 days on an Illinois Basin coal feed. After a brief period of maintenance, the run will he continued A two year operating program on coal from Kentuokv. ng In the H-Coal process dried, ground bitu-minous. subbituminous or lignite coal is slurried with process derived oil then pumped and heated to reactor conditions. The coal is reacted with h ydrogen in an u pflowing ebullated catalyst bed. Reactor effluent is depressurized and hydrocloned into a low ash recycle and a high ash stream which is fractionated to final products. In a commercial plant, the solids bearing vacuum tower underflow could be gasified for hydrogen production. llRl is conducting a program of R&D support for pilot plant operations and process improvement for the pilot plant. Project funds have been proportioned -DOE (80 percent) and industrial participants (20 percent). Ashland has initiated a program for construction of a $3 billion. 50,000 BPD commercial scale plant to DOE, with Aireo Cr yoplants. Inc. participating. The Commonwealth of Kentucky have made payments totalling $1,000,000 to American Smelting and Refining Co.. (ASARCO). for an option on a 1600 Acre site in Breckinridge County KY., owned byf ASARCO or construction of a commercial-sized plant. The EPA, Region IV announced that an EIS would he prepared for the Breckinridge facility. Loan guarantees for the project have been requested of the SFC.

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-foot diameter single stage Well man-Galushn 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

'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.) JCGG 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 facilit y. ICGG has completed a conceptual commercial plant design, a demonstration plant tentative baseline design, and the demonstration plant process design. The 2,200 TPD coal gasification demonstration facilit y will produce 23 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 process licenser and Dravo Corporation as the architect-engineer. The process incorporates fluidized bed pyrolysis to produce both gas and liquids. 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. Status: DOE has prepared a draft environmental impact statement (DEIS) for in house review. Detailed engineering of the demonstration plant is nearing completion and an economic reassessment is being prepared for a commercial plant based on the completed design of the demonstration plant. In view of the Administration's revised budget recommendation, continuation of the project into construction is uncertain. Govt. Project Cost: Phase I Design $58 million.

'INTERNORTLI METHANOL PLANT - DOE, InterNorth, North Dakota Synthetic Fuels Group (Baukol-Noonan Coal Co., Cooperative Power Association, Froedtert Malt Corp., Interstate Power Co., Iowa Illinois & Electric, Minnesota Gas Co., Minnl

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-71 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont)

• I'fl' COAL TO GASOLINE PLANT - DOE, International Telephone and Telegraph, J.W. Miller I'll' was awarded approximately $4 million for a feasibility study to convert a former textile plant into a coal gasification plant producing 400 MMSCFD of pipeline gas from 30,000 tons of coal.

Project Cost: $3,747,703 ICEN-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 10 develop a coal gasification complex to be located on the Ohio River in western Kentucky. IIYGAS Process would be used to produce pipeline quality high-Btu 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 com plete Phase zero of the multi-phase program.

Project Cost: $750 million 'KEYSTONE PROJECT - Westinghouse Electric Corporation. Air Products and Chemicals, Inc; AmeriGas, Inc; Bethlehem Steel Corporation: Dravo Engineers and Constructors; Johnstown Area Regional Industries, Inc.; Energy Impact Associates, Inc.; Lehman Brothers Kuhn Loeb, Inc.; DOE The proposed Keystone Project will utilize domestic coal resources to produce coal liquids using coal gasification and indirect liquefaction technology. The eventual commercial plant will be a nominal 100,000 barrel per day methanol facility located in the Cambria County area of Western Pennsylvania. The objective of the Keystone Project is to produce methanol as a transportation fuel and fuel supplement. a combustion turbine fuel for power generation, and a chemical feedstock. A 10.000 barrel per day single-train module is planned to validate the commercial applicability of the s ystem. A feasibility award study for this project has been announced by the Department of Energy. Project Cost: $4.8 million - feasibility study. KILnGAS PROJECT - Allis-Chalmers, State of Illinois. Electric Utility participants are: Baltimore Gas and Electric Co., Central Illinois Light Company. Consumers Power Co., Illinois Power Co., Iowa Power & Light Co.. Monongahela Power Co., Ohio Edison Co., The Potomac Edison Co., Public Service Indiana, Public Service Co. of Oklahoma, Union Electric Co., 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. Site preparation, detailed engineering design and procurement of long-lead equipment are in progress. The plant will provide low-lItu (160 Btu/SCF) gas to the Wood River Station of the Illinois Power Company at East Alton, Illinois. Mechanical completion is scheduled for late 1982. Gilbert /Commonwealth Associates. Inc., is the Architect-Engineer. J. A. Jones Construction of Charlotte, N.C. was chosen as construction manager for the plant. State of Illinois has allocated $18 million in Coal Development Bond Act funds to assist in construction of the plant. The objectives of the KILnGAS Demonstration Program are the following: (1) Demonstrate technical performance at large scale (2) obtain o perating data for forecasts of commercial production costs; (3) obtain data to confirm process design: and (4) establish the design basis for proceeding with 4,000 to 5,000-TPD units. With the successful operation of the Commercial Module plant in 1983, Allis-Chalmers plans to offer these larger plants on a turnkey basis with normal commercial warrantees.

Project Cost: Estimated at $135 million, which includes two years of operation. Committed Funding Sources: Electrical Utility Participants $ 34 million State of Illinois $18 million Allis-Chalmers $ 83 million $135 million

'New or Revised Projects

4-72 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont.)

LAKE DE SMET SNG FROM COAL PROJECT - Texaco, Inc., Transwestern Pipeline Co Texaco and Transwestern Coal Gasification Co. (a subsidiar y of Texas Eastern Corp.) are continuing a privately funded study to evaluate the feasibilit y of constructing a commercial scale synthetic fuels plant near Lake Desmet in north-central Wyoming. The plant would convert approximately 38,000 tons of coal per day to approximately 127 million cubic feet of synthetic natural gas and 55,000 barrels per day of methanol. Texaco Inc. has approximately 37,000 acres at the Lake DeSmet site with 2.3 billion tons of coal underlying the property. Texaco has previously completed a multi-million dollar water development program and has sufficient industrial water supplies for the proposed gasification plant and other commercial projects. The two companies plan to become joint participants in the synfuels facility itself, with Texaco Inc. being the sole owner and operator of the mine suppl ying the feedstock for conversion to synfuels. Included in the study will be work in the areas of environmental acceptability, site selection, socio-economic impact, financial planning, and preliminary process design. Project Cost: Undetermined

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 < 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° F). The technical information derived from this work is being used in support of the current DOE-sponsored two-stage liquefaction program. H ydrocracking 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-I coal extract. Also SCT coal extracts show a lower C 1 - C gas yield. POD ooerations under this contract have been completed and a final report has been submitted to DOE Project Cost: $2.8 million

'LIGNITE BRIQUETTE GASIFICATION PLANT - Black, Sivalls & Bryson, Incorporated, Texas Energy and Natural Resources Advisory Council, Elgin-Butler Brick Company A feasibility study jointly conducted by Black, Sivalls & Bryson, Incorporated (BS&B), and Texas A & M, showed that briquetted lignite is usable as a gasifier feed stock. BS&B was awarded a contract to provide engineering design and economic analysis for the construction of a commercial lignite briquette gasification plant. Texas Energy and Natural Resources Advisory Council provided $100,000 of the contract and under the terms of a cooperative agreement, BS&B and Elgin-Butler Brick will contribute the equivalent of $100,000 and $50,000 respectively. The plant will be designed to produce fuel gas for the brick and ceramic kilns of Elgin-Butler who recovers 140,000 tons of lignite annually in the process of clay mining in central Texas. The design for the plant should be completed in May 1981.

Project Cost: $250,000 engineering design and economic analysis

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 economies 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

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-73 STATUS OF SYNPUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont) LUMMUS COAL LIQUEFACTION DEVELOPMENT - DOE and Luminus Co. Lummus developed a catalytic coal liquefaction process, clean fuels from coat (LCFFC) on a 30 lb/hr bench scale unit. The LCFVCProeess, employs a series of plug-flow, expanded catalytic reaction beds and a patented Lummus anti-solvent deashing technique for solids removal. While the program is no longer experimentally active, 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) *MAPCO COAL-TO-METHANOL PROJECT - Mapco Synfuels Mapco proposes to use the Texaco gasification process and the low pressure methanol synthesis loo p of Lurgi for a methyl fuel project. A mine-mouth site is located at the White County Coal Company Mines No. 1 & 2. Construction of the first 5.000 TPD module is scheduled to begin in 1982 with an expansion to 10,000 TPD of methanol later. The project requested that SFC guarantee to cover the difference between the price of #2 distillate oil (currently $.52 per gallon) and the market price of methanol (currently $75 per gallon). This differential would be escalated at the rate of 12 percent per year and would be for a period of tO years. The total support would not exceed $200 million;- A completion guarantee not to exceed $150 million which would function as a loan guarantee for the start-tip period was also requested, to be released upon the successful run specified by terms of a performance period test agreement acceptable to the lender of design and construction financing and Mapco.

Project Funding: Undetermined 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 260-6tu/SCF synthesis gas has been under study by Houston Natural Gas Corporation (IING) and Texaco, Inc., since late 1979. A preliminary engineering study was completed by Ebasco Services in January 1980. Texaco and HNG have received a DOE grant in August 1980, based on a $3.6 million request to study the feasibility of a 6.000 ton/dayf acility to be located adjacent to Texaco's oil refinery on the Mississippi River at Convent. LA. The facility would utilize synthesis gas to manufacture 26,000 barrels a day of methanol. Status: 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 he located in Louisiana. Initial output of the plant would be 125 million Btu dail y, 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 (MLGW) is under contract to DOE to design and construct medium-L3tu gasification plant converting 3158 tons of coal into 175 MMSCFD of 300 Btu/CF fuel gas. IGT's U-Gas 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 Compan y 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 1, 1979 for evaluation, and a contract to proceed into Phase LI was signed in May 1980. During Phase II Memphis Light, Gas and Water will continue in its present roll as prime contractor. Foster Wheeler Energy Corporation will complete the final design and supervise construction of the Demonstration Plant. Technicu support provided by IGT will include pilot operations at its Chicago Energy Development Center where the U-GAS Gasifier was developed *New or Revised Projects

4-74 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cant.) MEMPHIS INDUSTRIAL FUEL GAS DEMONSTRATION PLANT (Cont.) Construction of the plant is scheduled for completion in 1984 with demonstration period to be completed in 1986 at a total cost of about $830 million. In Phase Ill of the project Delta Refining will start-up and operate the demonstration plant with emphasis on safety and efficiency of operation. The final Environmental Impact Statement was issued in Ma y 1981. A record of decision should be finalized in June. As the Federal Government has shifted responsibility for support of synthetic fuels projects to the S ynthetic Fuels

Project Cost: Phase I -$1 1.00 million (DOE) Phase II - $450 million (DOEIMLGW) Phase III - $80 million ( DOE/MLGW)

*;lInItEx ELECTROTHERMAL DIRECT REDUCTION PROCESS - Midrex Corporation, Georgetown Texas Steel Corpora- tion Midrex was selected for a DOE award of $865.895 for a mine mouth feasibility study for a coal gasification plant to produce medium Htu gas to replace natural gas as a feedstock for the direct reduction of iron ore. Project Cost: $1,731,789

MINNEGASCO IIIGH-BTU GAS FROM PEAT - DOE and Minnesota Gas Company A feasibility study is being conducted for an 80 million CFD plant to produce substitute natural gas from peal in northern Minnesota. The study emeompasses work in technical, socioeconomic, environmental, regulatory, and financial areas. A decision to proceed to detailed design of the peat gasification plant will be made after completion of the study.

Project Cost: $3.67 million for 19-month project starting October 1. 1980.

MINNEGASCO PEAT F3IOGASIFICATION PROJECT - DOE. Minnesota Gas Company, and Northern Natural Gas Company, (Dynatech RID Company, Subcontractor) Minnegasco's laborator y scale research and preliminary economic evaluation of peat biogasification performed by Dy nateeh RID Company were very encouraging. DOE signed a contract with Minnegasco for co-funding a continuation of the experimental work on pretreatment and fermentation of peat to produce methane. The work is being conducted at Dy natech RID Company. Project Cost: $425,000 for 21-month project starting October 1, 1979.

MINNF.GASCO PEAT GASIFICATION PROJECT - DOE. Gas Research Institute, and Minnesota Gas Company and Northern Natural Gas Company (Institute of Gas Technolog y, Subcontractor) Minnegasco began evaluation of peat gasification in conjunction with laboratory and PDU-scale gasification of peat. The work is being conducted at IGT for conversion of peat to SNG. Current work being conducted on the program includes PDU work on wet carbonization, gasification of Florida and Alaska peat, and gasification tests on peat after dewatering by various methods. Peat gasification has advanced to pilot plant status at the modified UYGAS facility in Chicago Project Cost: $1.2 million for 1976-1978 project Minnegasco recently awarded additions totaling $3.9 million, to the DOE contract to extend work until December 31, 1981. MOBIL-M PROJECT - DOE. Mobil Oil Co. DOE selected Mobil for a cooperative agreement for a 40,000 IWO Mobil-M plant. The proposed project includes the engineering development of the mine, coal gasification, methanol synthesis, MTG, light h ydrocarbon processing, and product distribution facilities, and the essential supporting facilities. Construction could begin in 1985 with the plant becoming operational in 1991. Fluor Corporation will perform the site specific study for the plant that will use Lurgi gasification.

Cost: $25,000,000 DOE Agreement $73,000,000 Project New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-75 STATUS OF SYNPUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont)

MOLTEN SALT PROCESS DEVELOPMENT - DOE and Rockwell International Rockwell has designed, built and operated a 1 TPH PDU to test a molten salt coal gasification process for low-Btu gas production. The gasifier is designed to operate at 1,800° P and 20 ATM. ffThrence 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. 11,5 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-Stu gas from high-sulfur caking coal at feed rates up to 1500 lb/hr. A Phase 2 program is underway aimed at completing the development of the tow-Btu (airblown) Molten Salt Coal Gasification Process. Two runs were completed and a third scheduled for early May

Project Cost: $12.6 million (Phase 1) $4.4 million (Phase 2) $17.0 million (Total)

MOUNTAIN FUEL SUPPLY COMPANY COAL GASIFICATION PROCESS —Mountain Fuel Resource. 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 facilit y. The gasifier operates at slagging temperatures (about 2.800° F), and 150 psig. The heating value of the product gas is about 300 Btu/SCF. Both radiant and convective heat exchangers are used to recover heat from the process. Detailed engineering is 80 percent complete for a 30 TPD process development unit which will he used to fire an existing brick kiln at Salt Lake City. DOE funding is being sought.

Project Cost: $6.0 million

NASA LEWIS RESEARCH CENTER COAL-TO-GAS COGENERATION 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 p ractical convert to coal, the Lewis Research Center investigated several alternatives for using high sulfur coal in an environmentall y acceptable manner. Preliminary analyses indicated that a coal gasifier and cold gas cleanup system integrated with a combined cycle cogeneration powerolant could provide both steam heating and haseload 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 Corporation, and has verified technical and environmental benefits of the concept. The reference system selected for the conceptual design included two air-blown Westinghouse pressurized fluidized bed gasifiers to demonstrate multiple operation using Eastern U.S. high sulfur coal, a Holmes-Stretford acid gas removal system, and a 20 MW combined cycle electric generation powerplant utilizing an extraction steam turbine to provide up to 90.000 lb/hr of low pressure steam for heating. This plant would be a prototype for industrial cogeneration and could serve as a modular building block toward verification of a utility-size application. A capital cost of $58 million (1980 dollars) was estimated for the complete powerplant which included site development, design services, construction management and contingencies for this first-of-a-kind plant. A final report. NASA TM-81687, has been completed and an independent environmental assessment is being prepared. Funding options for detail design and construction are being investigated. The City of Cleveland, Ohio is evaluating applications of this plant to its Municipal Electric Plant.

Project Cost: $58 million

NATIONAL COAL BOARD LIQUID SOLVENT EXTRACTION PROJECT —National Coal Board, British Department of Energy The British Department of Energy is co-sponsoring pilot plant evaluation of the Liquid Solvent Extraction Process developed in a small pilot plant capable of producing 0.2 TPD of liquids. In the process. a hot, coal-derived solvent is mixed with coal. The solvent extract is filtered to remove ash and carbon residue, followed by hydrogenation to produce a synerude boiling below 300° C as a precursor for transport fuels and chemical feedstocks. Economic studies, supported by Badger, Ltd. have confirmed that the process can produce maximum yields of gasoline and diesel very efficiently. Work on world-wide coals have shown that it will liquifyeconomicallym ost coals and lignite and can handle high ash feed stocks. A 25 ton-per-day pilot plant has been designed with support from British Petroleum Co., and a decision whether to build the plant at Point of Ayr, North Wales is still awaited.

Project Cost: 25 million British pounds (1981 prices) Construction cost plus 15 million British pounds (1981 prices) operating costs.

New or Revised Projects 4-76 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (ConL)

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 NOB 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 temoerature 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. Texas lignite has been tested and the process found attractive for liquefying this feedstock. A 25 ton-per-day pilot plant has been designed with support from the British Department of Energy and British Petroleum Co. and Construction will start as soon as funds are allocated.

Project Cost: 25 million British pounds (1981 prices) construction cost, plus 16 million British pounds (1981 prices) operating costs.

*NEW ENGLAND ENERGY PLANT - EG&G and DOE Bechtel is conducting a feasibility study for EG&G for a New England Energy Park. EG&G requested $4 million from DOE for the study. A 4.300 acre site near Fall River, MA is under contract with approximately 1.900 acres allocated for the development of the park. Approximately 10.000 TPD of coal will be transported from Kentucky, Virginia, West Virginia and Pennsylvania and gasified to a medium Btu gas which will, in turn, fire a 400-650 MW combined cycle power plant and be used to produce 2,500 TPD of methanol. EG&G requested a loan guarantee of approximately $28 billion from the SFC.

Plant Cost: $2.3 billion

NEW MEXICO LURGI COAL-TO-GAS/METHANOL PLANT - Texas Eastern Corp. and Utah International, Inc. In January 1980, Texas Eastern and Utah International announced a joint feasibility study toward the construction of a coal-based synthetic fuels plant in northwest New Mexico. The plant would utilize the Lurgi gasification process to produce a synthesis gas which would then be converted to liquids, such as methanol, using other commercially available processes. In July 1980, the project was selected by DOE for feasibility study funding under the synthetic fuels commercialization program. 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. Negotiations are stilt continuing with the DOE for exact amount of funding and work program. Once the work starts, it is estimated that it will take 12 months to complete the feasibility study, which will include preliminar y plant design, construction schedules, capital and operating cost estimates, evaluation of plant site alternatives, further studies on the charateristics 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)

*NICES PROJECT - Northwest Pipeline Corporation Northwest requested loan guarantees from the SFC for a project located near Beardner, Oregon. The plant would produce 250 million cubic feet of high Btu gas per day to be used in an Integrated Gasification Combined Cycle Electric Generator. The plant would come on line initially in 1985, with full production scheduled for 1990.

Project Cost: Undetermined

*New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-77 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cont.)

'OHIO VALLEY SYNTHETIC FUELS PROJECT - Consolidated Natural Gas S ystem. Standard of Ohio The Ohio Valley Synthetic Fuels is a joint venture of Consolidated Natural Gas with the Standard Ohio Company (Sohio). They have proposed a project for construction in Mason County, West Virginia, on a CNG plant site. A combination of Texaco BGC/Lurgi Slagging coal gasification processes would be used to produce pipeline quality gas and methanol. CNG applied for potential SFC support. Sohio is prepared to move forward without the SFC. Preliminary engineering is scheduled to begin in 1982 with construction planned for 1984. A second plant is proposed with construction beginning in 1985. Project Cost: Undetermined

*fl HYDROGENERATION PROCESS PROJECT - Coal Fuel Conversion Compan y, Timberline Fuels, Inc. A 1000 BPD facility was proposed using the Ott Hydrogeneration coal liquefaction process (closed system). A mine mouth plant at Cheosa Canyon Ranch in Las Animas County , Colorado was proposed. A purchase agreement was requested from the SFC. Project Cost: Undetermined

'PEAT METHANOL ASSOCIATES PROJECT - Peat Methanol Associates Preconstruetion activities began in March 1981. The 1(8W gasifier will be Used for production of synthesis gas from peat to produce methanol. The project is located at the First Colony Farms near Creswell, North Carolina. Peat harvesting permit is held by the First Colon y Farms. The process will use 2.123 tons per day of peat to produce t58,000 gallons per day of methanol. Price guarantees of 75 cents per gallon with an adjustment each quarter from January 1, 1981 equivalent to actual inflation plus one half of one percent were requested from the SFC. Project Cost: Undetermined

'PHILADELPHIA GAS WORKS SYNTHESIS GAS PLANT - DOE. Philadelphia Gas Works Philadelphia Gas Works (PGW) was selected for a DOE award for a feasibility study for a $125 million medium Rtti coal gasification plant. The first facility of a potential series of modular plants would be built in northeast Philadelphia on a 21-acre site of an old PGW gasifier plant and would start operation in 1985. Project Cost: $125 million Study: $3.4 million

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-Fitu 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 has been completed by Stearns-Roger, Denver, Colorado. The sponsors have determined that further participation is no longer economically desirable. U.S. DOE has elected to terminate its agreement with Pike County.

Total Project Cost: $12,110,000 DOE - SO percent Kentuck y Department of Energy - 25 percent Appalachian Regional Commission -25 percent

*New or Revised Projects

4-78 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.) RISER CRACKING OF COAL - DOE and Institute of Gas Technology This project is a 4-year experimental stud y 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 1/8-75' 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 POD under Phase II of the project. In PDU operations, two stages of partial combustion were 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 stages. lowering the yields as a result. Experimental work has been completed And an Economic Assessment and a Final Report has been submitted. While additional mechanical development work is needed on the P013 reactor, the processing technique has been established and the economics are competitive with other coal conversion schemes. 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 stud y for a coal gasification/cogeneration plant to be located near San Ardo in the Salinas Valley, California. The stud y would evaluate the environmental and economic viability of gasif ying 4,000 tons per day of bituminous coal into medium Btu sy nthesis gas for generating electricity and steam. In light of the Administration's budget reduction recommendations, it is anticipated that the study will proceed without DOE funding. The plant would generate 210.000 KW gross per day of electricity for PG&E customers and 1.5 million pounds of steam per hour for steamflooding 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: Undetermined SASOL TWO AND SASOI, THREE - Sasol Limited 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 Rosjesspruit Colliery. The facilities include boiler house. Lurgi gasifiers. ox ygen 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 were 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 January, 1981, two years after the decision had been taken to build Sasol Three, physical construction on the site was more than 25 percent completed. A fourth plant is planned to be located at Sasolburg.

Project Cost: $3 billion (including offsites and mine) S. K. GASIFICATION PROCESS - Shell International Petroleum Co. Shell is developing a pressurized entrained bed, coal gasification process. A six TPD pilot plant has been in operation at Shell's Amsterdam laboratory since December 1976. A number of different coals and petroleum cokes have been successfully gasified at 450 psi pressure. This pilot plant has now operated for over 5000 hours. A 150 TPD prototype plant has been constructed at the German Shell Hamburg/l-larburg refinery. Since the start-up in November 1978, well over 1000 hours of operation have been logged. The longest run so far lasted for over 250 hours. The carbon conversion was over 99 percent and a synthesis gas was produced containing, before treating, less than 1.5 percent vol. CO2 and 0.1 percent vol. Cl-I4. Planning is underway for a 1200 TPD coal gasification plant to be built at Shell Chemie's Moerdijk site with operation expected to start late 1984. The coal gas from the plant will be used by a utilit y company for the generation of electricit y in a combined-cycle power station. Project Cost: Estimated at $150 million (excluding powerplant)

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-79 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) COAL CONVERSION PROJECTS (Cant)

*SLAGGING GASIFIER DEVELOPMENT - DOE. Grand Parks Energy Technology Center, and Stearns-Roger, Inc A slagging fixed-bed gasifier (SFBG) 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 operating 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 lignite aimed at generating wastewater for treatment testing was nearly finished by the end of April 1981. Six tests of over twenty hours of operation have been performed, including a new record run of over 65 hours of continuous slagging. During the 65-hour test the oxygen/steam ratio was reduced from 1.0 to 0.94, but the throughput remained high at over 1100 lbs/hr It2 of as-received coal. Gas production rote remained at over 31.000 SCFH, with a heating value of over 330 Btu/SCF. Over 4600 gallons of steady-state, lined-out wastewater were produced for subsequent treatment tests. Data received from Carnegie-Mellon University indicate that the key to SFI3G wastewater treatment is solvent extraction for phenol recovery. It was demonstrated that when phenolics were reduced to the range of about 10 mg/I, most other organic contaminants were reduced to detection limits. Solvent-extracted, ammonia-stripped wastewater did not require dilution prior to biological treatment, and it had less tendency to foam and had a lower COD, TOG. HOD, and color than did a similar wastewater sample which was diluted to the same phenolic level. Operation with a partially dried lignite is in progress to evaluate the performance of a gas pre-cooler (partial tar condensor) and a water-cooled stirrer prior to oneration with caking bituminous coals. Project Cost: $3.5 million. FY81

SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-0 - DOE. International Coal Refining Company, (Air Products and Chemicals lne./Wheelabrator-Fr ye Inc.. partnership) and Commonwealth of Kentucky An SRC pilot plant is operating on the site of Southern Electric Generating Co.'s E.C. Gaston Steam Plant near Wilsonville, Alabama. It was designed, built, and is operated by Catalytic. Inc. The process dissolves coal under pressure in the presence of hydrogen. The products are clean solid and liquid fuels with heating values of approximatel y 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-1 demonstration plant was completed July 31,1979 and submitted to DOE. To carry out the project, Air Products and Wheelabrator-Fr ye have established a new entity, the International Coal Refining Company (ICRC). Under terms of a cost sharing agreement. ICRC will invest $90 million in the project. the Commonweath of Kentucky will invest $30 million and the Department of Energy will fund the balance. A site for the demonstration plant at Newman, Kentucky is under option. Products include clean solids and liquids with heating values approximately 16.000 Btu per pound SRC liquids include heavy oil (650-850' F fraction oils), middle distillate (400-650° F oils) and naphtha (C-400° F fractions oils) for reformer feed for high-octane, unleaded gasoline blendstoek or BTX chemicals. Pub'lie hearings were completed in February on the Draft Environmental Impact Statement currently being reveiwed by DOE and the EPA.

Project Cost: $1. 488 billion (Demonstration Plant Only)

SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-11) - DOE and SRC International. Inc. (Pittsburg & Midway Coal Mining Co. (P&M), subsidiary of Gulf Oil Corporation; Ruhrkohle AG/VEBA: and Japan-SRC, Inc. led b y Mitsui) The SRC pilot plant at Ft. Lewis. Washington, has a capacity of 30 TPD of coal feed in the SRC II (liquid product) process. The SRC I mode produces a low ash/low sulfur fuel which is solid at ambient temperature. Dissolver conditions are 850° F under 11 9 atmosphere and tSOO psig for SRC I and 2000 psig for SRC II. The process has been developed by P&M from bendh-scale. The pilot plant was designed and constructed by Stearns-Roger and Rust Engineering, respectively, and has been operational since 1974. SRC U mode produces gaseous and distillate liquid products and has been tested using Kentucky 9 and 14. Illinois 6. and Pittsburgh seam (Powhaton No. 5 and No. 6, Blaeksvitle 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 Lummus antisolvent de-ashing unit which was sucessfull y commissioned in May 1979. Operation in the SRC II mode resumed in late October 1979, to evaluate demonstration plant design concepts and conditions.

*New or Revised Projects

4-80 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Change Since March 1981) COAL CONVERSION PROJECTS (Cont.) SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-H) (Cont.) Under a separate contract with DOE, SRC International has prepared a preliminary conceptual design of a 6,000 TPD SRC II demonstration module being planned for construction near Morgantown. West Virginia. Stearns-Roger has contracts to provide detailed and mechanical design functions, as well as technical support the environmental activities. SRC International is now developing a process design. Badger Energy, Inc., is providing engineering services for the demonstration plant. Kellogg Kaiser Engineers (EKE) of Houston and Oakland was selected as the construction manager for the proposed plant, pending negotiations to finalize terms of the contract. On July 31. 1980, the memorandum of understanding 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. SRC International. Inc., comprised of P&M. Ruhrkohle AG/VEBA of Germany, and a new entity in Japan to be called Japan-SRC. Inc., led by Mitsui 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

TENNECO, SNG FROM COAL - Tenneco, Inc. Tenneco, through subsidiar y 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 is conducting an ambient air quality and weather monitoring program in the state-line area. The data is to be used in computer modeling studies addressing potential impacts on regional EPA Class I areas. Tenneco Coal Gasification Co., a subsidiary of Tenneco, Inc., filed its first annual Long-Range Plan under the Montana Major Facilit y Siting Act in April 1980 for a million MMSCF per day coal gasification plant to produce pipeline quality gas using Lurgi coal gasification technology. In December, 1980, the project was selected by DOE for cooperative funding of the $40 million front end cost of the project. The schedule calls for first gas production in 1988. On Match 31, 1981 the Company submitted an application for a loan guarantee for the project to the U.S. Synthetic Fuels Corporation. Project Cost: $2.5 billion in 1980 dollars.

*TENNESSEE SYNFUELS ASSOCIATES MOBIL-M PLANT - DOE, Hoppers, Inc.. Cities Service, The Continental Group, Inc. The DOE selected the Tennessee S ynfuels Associates project under the interim program established by the Energy Security Act for loan guarantees negotiations for $700 million for a plant to produce gasoline from coal. Ultimately, DOE dropped the project from consideration under the Defense Production Act. The project will seek SFC funding. The plant to he located near Oak Ridge, Tennessee would use KBW gasification and the Mobil-M process to convert 10 million TPY of coal to gasoline. In April, the DOE announced its intent to propose an EIS to assess the proposed sale to the City of Oak Ridge, Tennessee (the City) of all or part of an approximately 1,500 acre tract located at the west end of the DOE Oak Ridge Reservation, across the Clinch River from Oak Ridge Gaseous Diffusion Plant. If the City acquires the property, it intends to resell it to Tennessee Svnfucls Associates (TSA) which in turn intends to use the property as the site for the project. TSA plans to construct the facility in five modules, each of which will produce approximately 10.000 barrels per day of liquid products. Cost: $1.2 billion

New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-81 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.)

TEXACO COAL GASIFICATION PROCESS DEVELOPMENT - Texaco, Inc. The Texaco Coal Gasification Process has been operating for several years at Texaco's Montebello Research Laboratory in California. The facility has two pilot gasifiers each capable of processing 15-20 TPD of coal. The process has been used on a wide variety of coals and, since the 1973 Arab oil embargo, the development of the Texaco Coal Gasification process has been greatly accelerated. Operation at pressures ranging from 300 to 1200 psi have been tested. These pilot units, along with the associated coal grinding and slurry preparation equipment, provide design information for a number of commercial projects that are underway. A 165 tons coal per day demonstration plant has been in operation since early 1978 in Oberhausen -Ilolten, 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 German y. The product gas is used as a feedstock to a variety of chemical synthesis processes. Several test runs lasting up to 30 days have successfully demonstrated continuous operation of the process. Operation at pressures between 300 to 600 psi has been completed The system is complete with a waste heat boiler consisting of a radiant and a convection section. A process optimization program is presently underway. The program includes evaluation of alternate equipment components, of alternate heat recovery concepts, and gasifying of a wider range of coals. The total program is planned to provide information for the design, with ever increasing confidence, of large scale coal gasification plants using the Texaco process. The Texaco Coal Gasification Process has also been licensed for use in a plant of a confidential U.S. chemical company process to gasify coal to produce fuel gas for electric power generation. In addition, over one-half of the coal gasification proposals submitted to the U.S. Synfuels Corp. on March 31, 1981, specified use of the Texaco Coal Gasification Process in production of medium Stu gas, methanol, gasoline, h ydrogen, and electric power. Other projects that propose using the Texaco Coal Gasification Process are described separately under the following headings: Cool Water Coal Gasification Project, Medium Stu Gasification Project, Central Maine Power Company/Sears Island Project, TVA Ammonia From Coal Project, Chemicals From Coal Project. W. R. Grace Methanol From Coal Plant, Lake DeSmet SNG From Coal Project, and San Ardo Cogeneration Project.

Project Cost: West German Demonstration Plant Program: $50 million

TOSCOAL PROCESS DEVELOPMENT - TOSCO Corp. TOSCO has under development an atmospheric, low-temperature (800-971? F) coal p y rol ysis system, named the TOSCOAL Process, at their 25 TPD pilot plant facilities, located near Golden, CO. The TOSCOAL Proccs 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 arc Wyodak subbituminous and Illinois No. 6 bituminous. Status - Development is continuing with an active pilot plant program.

Project Cost: Undetermined

TRANSCO COAL GAS PLANT - Transeo Energy Company Transco submitted an application to the SFC for a medium Btu gasification project. Located near Franklin. Robertson County, Texas, the project would convert 16,500 TPD of lignite to medium-Btu gas using Lurgi dry bottom gasification process and transportation via a dedicated pipeline to Houston Lighting & Power Company's (HL&P) P.H. Robinson Plant in Galveston County, Texas.

Project Cost: Undetermined

TRI-STATE PROJECT - Texas Eastern Corporation and Texas Gas Transmission Corporation. Kentuck y Department of Energy Planning continues by Texas Eastern Corporation and Texas Gas Transmission Corporation to build a plant using Lurgi gasification and Sasol Fischer-Tropseh 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 55,000 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 b y the DOE for Cooperative Agreement funding under the synthetic fuels commercialization program. Under the Agreement signed in February 1981, DOE will provide a total of $22.4 million of an estimated $45 million, with the remainder financed by the Tri-State. The Kentucky Department of Energy will also provide assistance for the project.

*New or Revised Projects

4-82 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont) TRI-STATE PROJECT (Cont.) The agreement authorizes commencement of a two-year project work program, which includes site-specific environmental, health, safety and socio-economic impact studies, capital and operating cost estimates, developing a financing plan, engineering studies to determine optimum plant size, product slate and negotiation of contracts for coal and other resource requirements. Separate from the DOE program. 22,000 tons of Peabody Coal's Camp No. I coal will be tested at a SASOL plant in South Africa. 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 slagging, entrained bed gasification process which is based upon proprietary slagging gasification and heat exchanger concepts. The gasifier technology is derived, in part, from advanced developments in TRW rocket engine and MW) programs. An 8 atmosphere pressure. 1-2 ton per hour version of this gasifer will be constructed and tested during 1981-82.

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 Tim ammonia plant. Plant construction was completed in mid-1980. A three-year period of demonstration is planned. Capital costs will total $43.2 million. Brown and Root, of Houston held the $25.6 million contract for the construction of the eight ton per hour coal gasifier. The air separation plant was built by Air Products and Chemicals, Inc. at a cost of $5 million. The remainder of the work was to be done by TVA. The coal gasifier will provide 60 percent of the gas feed to the existing ammonia plant. The existing plant retains the option of operating 100 percent on natural gas, if desired The initial feed to the coal gasifier will be Illinois No. 6 seam coal. Status: The gasifier was dedicated and started tip at the TVA's 13th Demonstration of Fertilizer Technology conference in October 1980. However, actual production of feed gas for ammonia manufacturer had not taken place by the end of March 1981 because of mechanical problems. TVA and the contractors are working to overcome the problem.

Project Cost: $60 million total TVA MEDIUM BTU COAL GASIFICATION DEMONSTRATION PLANT -Tennessee Valley Authority (TVA) The Tennessee Valley Authority planned to build 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 disoersed industrial and utility applications in the Tennessee Valley region. Consisting of several parallel trains, each capable of producing medium - Btu gas from moderate to highly caking eastern U.S. coals, the plant was to be a grass roots facility consisting of coal receiving and handling, gasification, gas cleanup, air separation systems, and all necessary ancillary facilities. Site preparation had been scheduled to begin in the spring of 1981 with operation of the first gasifier module scheduled to begin in 1985. Bechtel National, Inc., C.F. Braun Co.. and Foster Wheeler Energy Corporation were awarded a total of $2.7 million for conceptual design studies incorporating five different coal gasification processes for obtaining the medium 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 $55 million in 1980 supplemental appropriations to 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. for the Droiect cut by the Carter Administration couoled with subseouent Rea gan Administra-

TVA has indicated its willin gness to enter into contractual arrangements with potential private owners under which

i.t:t.S1,tHISa

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-83 STATUS OF SYNFLJELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont.) TVA MEDIUM BTU COAL GASIFICATION DEMONSTRATION PLANT (Cont.) ownership. Such reimbursement will be provided from the operating cash flows of the project. All work by TVA thereafter shall be on a current cost reimbursement basis. Project Cost: First Module: $4 billion

*TWOSTAGE 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 atomos pheric pressure. air-blown. entrainment gasification system to produce a low-mu gas from coal. A 5 TPII Process Development Unit (PDU) is in operation at C-Es Power S ystems facility in Windsor. Connecticut. The two-stage gasifier consists of a "combustor" section in which coal and char are burned under slagging conditions, and a "reduetor", where, the balance of the coal is reacted. A product gas with a heating value of 110-100 Btu/scf is produced. The combustor operates at p 3000° F. and the reductor outlet temperature is °1800' F. To-date, the PDU has produced 24 billion standard cubic feet of gas in more then 3,500 hours of gasmaking operation using Pittsburgh Seam Coal. Eleven multi-test "Runs" have been made to gather parametric test information. To address potential industrial applications, some of which require a slightl y higher calorific value gas. the PDU is currentl y being modified - to permit operation in-the oxygen-enriched mode. Testing began in March 1981 to provide operating experience and design data in this mode, while tests in both the air-blown and oxygen-enriched modes with other coals. are to follow. Based upon the success of the PDU, Combustion Engineering, in conjunction with Gulf States Utilities, has been awarded a separate contract for $5 million for the preliminary design of a demonstration plant. The Demonstration plant would be located at the Gulf States Utilities Power Plant at West Lake. The estimated $50 million PDU project covers all work through four coal tests, air-blown, and oxygen-enriched tests.

Project Cost: $50 million TWO-STAGE LIQUEFACTION - DOE and Cities Serviee/Lummus A program has been initiated between DOE and Cities Service/Lummus for study on the chemistry, mechanisms, and process conditions for the expanded bed upgrading of coal extracts. This study will he combined with the explorator y development of a two-stage liquefaction (TSL) 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-1 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 catal ytic in nature. The first phase of a parametric study on total reactor pressure, space velocity, and temperature has been comple ted. The high chloride content of SRC-1 coal extracts obtained from the P yro and Lafayette mines has essentiallyf no e fect on the LC- Fining hydroproeessing. 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 has been h ydrotreated in the LC-Fining unit. Process solvent is being used in the coal pasting step of feedstoek preparation for the SCT operation. The catalyst age in the LC-Finer was in excess of 1500 pounds 850° F+ SCT coal extract per pound of catalyst prior to a catalyst change as required by the contract work statement. Integrated operation of the TSL produced a C-850° P yield of 54.6 weight percent (MAF coal basis) at the hvdroen eonsumntinn of 47R wpioht

as Project Cost: $7.3 million

UNION CARBIDE COAL CONVERSION PROJECT - DOE, Union Carbide/Linde Division Union Carbide has been continuing work on the Coaleon process since the 1950's. In the first round of PL 96-126 solicitations, DOE awarded Union Carbide approximately $4 million for a feasibility stud y for the production of low/medium Btu gas. Project Cost: $3,945,676 (study)

*New or Revised Projects

4-84 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

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 180-Stu gas is used to fire a boiler for heating/cooling of campus buildings. The process produces fuel oil as a co-product which will be used as boiler fuel during gasifier maintenance. The Stoic gasifier was started initially in October 1978. Altogether five different western subbituminous coals have been fed to the Duluth unit. The heavy coal oil recovered by means of electrostatic precipitation has been stored and fired successfully in the University's boilers. The gasifier is now fully operational, and on an extended run providing fully the fuel needs for the campus heating plant.

Project Cost: $5.5 million (50/50 DOE/participant funding)

'WESTINGHOUSE ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERATION —DOE/Gm. Westinghouse Electric Corporation Since 1975, Westinghouse has operated a coal gasification pilot plant at Waltz Mill, Pennsylvania. The pilot plant utilizes a single stage fluidized bed gasifier with dry ash agglomeration and fines recycle. The gasifier has operated at temperatures of 1550° F to 1990° F and pressures between 130 psig and 230 psig. Tests have been performed with air feed to the gasifier to produce low-Btu gas and oxygen feed to produce medium-Btu gas. Pilot plant coal capacity varies from 15 TPD with air feed, up to 35 TPD with oxygen feed. A wide range of coals have been successfully processed, from Texas lignite and Wyoming Sub-C subbituminous to highl y caking Pittsburgh seam coal. The pilot plant has recently been integrated with Waltz Mill Test and Development Center, to provide the capability for combustion testing using coal gas as fuel. In addition, tests are currently planned for evaluation of particulate removal and heat recovery systems. A commercial size, 3 meter diameter cold now fluidized bed scaleup facility has been constructed and is scheduled for operation in 1981. The purpose of these facilities is to develop a sufficient data base to minimize the technical risks to acceptable levels associated with scaling up to demonstration and commercial size gasification plants. Several demonstration and commercial projects are currently in the feasibility study or design stages for application of the Westinghouse coal gasification system to various industrial and utility applications, including industrial fuel gas, combined cycle power generation and methanol production.

Project Cost: $50 million

'WHITEHORNE COAL GASIFICATION PROJECT - Hercules Inc.. Norfolk and Western Railway Company, and United Coal Company A consortium of Companies composed of Hercules, Inc.. Norfolk and Western Railway Company, and the United Coal Company has proposed a coal-to-methanol-to-gasoline project to be located near Longshop and MocCoy in Virginia. Loan and price guarantees were requested from the SFC for the project which will use the Texaco coal gasification process to gasify 10,000 TPD of coal. Lurgi Methanol synthesis and the Mobil Methanol process would also be used The project is scheduled to start operation in mid-1988 producing 23,000 BPD of gasoline.

Project Cost: Undetermined

'WYOMING COAL CONVERSION PROJECT - W yCoalGas. Inc., a Panhandle Eastern company; Ruhrgas Carbon Conversion, Inc., subsidiary of Ruhrgas A.G., B.R.D.; Pacific Gas and Electric Company A 150 billion Btu per sd capacity commercial pipeline gas project using Lurgi and Texaco coal gasification followed by methanation is being developed, and an expansion to 300 billion Btu per sd capacity is proposed. The plant will be 16 miles northeast of Douglas, Wyoming. Rochelle Coal Company, a partnership of subsidiaries of Peabody Coal Co. and Panhandle Eastern, 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 of water from the North Platte, and a permit to construct a 26,000 AF reservoir. Panhandle has rehabilitated the dam on another 26,000 AF reservoir and is entitled to one quarter of the volume and water rights. A water-well-based supply will back up these systems. WyCoalGas entered into a cooperative agreement with DOE on October 31, 1981 for partial Federal 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, and on March 31, 1981 filed with the U.S. Synthetic Fuels Corporation for financial assistance in the form of a loan guarantee and contingent price supports. Contractors are Bechtel, Lurgi, SASOL, Woodward-Clyde, Mountain West and others. Work under the Cooperative Agreement, to be completed in July 1982, is proceeding. First gas production is predicted for 1986.

Project Cost: Total Estimated Capital Required $2.66 billion, Stage I. escalated 'New or Revised Projects

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-85 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

COAL CONVERSION PROJECTS (Cont) ZINC HALIDE HYDROCRACKING PROCESS DEVELOPMENT - Shell Development Co., and Conoco Coat 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 hydroeracking orocess to produce distillate fuel and gasoline from coal or coal liquids. Early work involved reaction of Colstrip subhituminous coal in a two pound- per-hour scale unit. Initial runs in 1978 and 1979 used SEC from Ft. Lewis Plant in a I'DU scale reactor at 100 l./hr. DOE has decided to stop funding the project. Conoco remains enthusiastic because of the unusually high removal of N, 0, .5, and high gasoline yield, but no further work is now planned because of the personnel needs of other projects. A final report on the DOE contract has been sent to DOE.

Project Cost: $11 million (90 percent DOE, 5 percent Shell, 5 percent Conoco) .s.sss*******t*******t********* UNDERGROUND COAL CONVERSION PROJECTS

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 L5 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 - Mitchell Energy, Republic of Texas Coal Company, DOE DOE selected Mitchell for the first round PL 96-126 solicitations for a feasibility study of in situ gasification of deep Texas lignite. The medium Btu synthesis gas produced would be converted to methanol and high octane gasoline at a site on the Texas Gulf Coast. A small scale production test at 100 to 300 TPD will be conducted, and if successful, commercial production units of 1000 TPD would begin in 1985.

Project Cost: $809,000 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, RI5W. Product gas would be used in the power plant as boiler fuel, or as reducing gas to produce If for Claus plant. Target zone is a 15 to 17 foot thick seam of subbituminous coal, approximately 500 feet deep. ceological, environmental, and hydrological testing have been completed for the site. Environmental evaluation of the site was being funded by the 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, preliminar y geoteehnical assessment, and formation pre-burn testing. During June and Jul y of 1979, personnel of the 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

*New or Revised Projects

4-86 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981) UNDERGROUND COAL CONVERSION PROJECTS (Cont)

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 dee p 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, pyrol ysis, 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 economies 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 aoproximately 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 in x IS in rectangular pattern. After forward gasification between end-wells, a line-drive was attempted between the two pair of end wells. The latter step was difficult to control and lack of horizontal containment of produced gases led to termination of the gasification test. The gasification site was excavated during the fall of 1977 and the affected zone of the first burn dimensioned and documented. The project is being held in abeyance pending additional technical feasibilit y and economic viability studies. Project Cost: $10 million for 5-year program

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 a part) designed to provide environmental information--specifically effects to groundwater. Manna 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 the coal seam. Two new offset wells were drilled to reestablish linkage at bottom of seam. Subsequent gasification test indicated 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 coal seam. During the test, gas production of 4500 sef/min was achieved. The test was shut down Sept. 21, 1979 after 37 consecutive days of gasification. Under the new DOE Underground Coal Gasification Program, Hanna V has been deferred indefinitely. Activities at the site are concerned with environmental monitoring. As part of the permit requirements with the Wyoming Department of Environmental Quality, the site h ydrology 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 began in October 1980. Cores from both Hanna II and Hoe Creek 3 are being anal yzed. - 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

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-87 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

UNDERGROUND COAL CONVERSION PROJECTS (Cont.) UNDERGROUND COAL GASIFICATION, HOE CREEK PROJECT - DOE and Lawrence Livermore Laboratory The project is designed to develop a process for steam-oxygen gasification of underground coal, producing medium- Btu gas suitable for conversion to SNG or as a chemical feedstock. Methods for enhancement of coal bed permeability are included in the project. A preliminary two-well fracture and air gasification test, Hoe Creek No. I was conducted during October 1976 at a site 25 miles southwest of Gillette, Wyoming. Gasification at Hoe Creek No. 2, which utilized reverse combustion to link two process wells, was initiated on October 14. 1977 and completed December 25, 1977, primarily using air gasification. Oxygen injection producing 250-300 Btu/scf gas was carried out for two days during November 1977. Floe Creek No. 3, initiated in August 1979, was the first in-situ experiment to use a horizontal channel to control the combustion front as it moves through the coal seam. The experiment was carried out in a 25 foot seam of subbituminous coal at a depth of 165 feet from the surface. During the 47 day run 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 Gas recovery was composition was 37 percent U 2 , 5 percent CU 4 , 11 percent CO. and 44 percent CO T 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 floe Creek No. 3 experiment, including postburn coring; modeling; laboratory experiments; and environmental R&D.

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 Prieetown. West Virginia, and the target zone is high volatile Pittsburgh seam bituminous coal. Status -The reverse combustion linkage (RCL) phase of the test was initiated on June 9, 1979, with the successful ignition of the high ash, high sulfur coal seam. The initial linkage path over the forty foot section of the test field was found to be insufficient and a second pass of the flame front through the link was completed on July 8,1979. After successfully relaying the reaction front into the sixty foot section of the field, RCL was continued until breakthrough at the injection well on July 23, 1979. The gasification phase of the field test was initiated on September 23, 1979, and was continued until October 5, 1979. During the period, air injection into the 60 foot long coal seam section was maintained at about 1.8 MMCF/dav at 300 PSIG pressure. Production flow averaged 4.2 N1MCF/day at system baekpressures up to 120 P51G. A relatively clean combustible gas having an average heating value of about 127 Btu/ef (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. Post test core drilling (consisting of 4 core wells) was initiated in December 1980. and completed in February 1981. Burn analysis is continuing, with completion scheduled for September. Post monitoring of deep and shallow well water and surface streams is also

A one year effort is being made to inject actual data into a 3-D thermodynamic model to evaluate burn predictions and results. A contract was awarded to Williams Brothers Engineering Co. to assess the flat and steeply dipping bituminous coal

Plans are also being formulated to prepare a second burn in the Pricetown location using an existing deviated hole as the linking mode. Light off is scheduled for FY-83. A 30 minute film strip titled "Pricetown I UCG Test Data Diagnostic Film Strip" was completed.

Project Cost: $Ll million, FY 1977 $3.2 million, FY 1978 $0.9 million, FY 1979 $0.56 million in FY 1980 $0.592 million in FY 1981 So. 700 million in FY 1982

4-88 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

UNDERGROUND COAL CONVERSION PROJECTS (Cont)

UNDERGROUND COAL GASIFICATION, ROCKY HILL PROJECT - ARCO ARGO conducted an in situ coal gasification test near Rena Junction, Wyoming. A linked vertical well gasification program using three in-line wells was completed. Target zone was a 110 foot-thick coal seam at a depth of 630 feet. Construction took place in the summer 1978 with operation in August-September. Two 75-foot reverse combustion links were established at the bottom of the coal seam, and, significantly, the second link was a relay of the first. 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/5CF. 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 continuing program includes a second test to be conducted near the site of the first test during 1983 and 1984. This program is designed to demonstrate the technology on a scale adequate to assess the remaining uncertainties in proceeding to commercialization. ARCO's goal is to have a commercial module or plant in operation before 1990.

Project Cost; $70 - $80 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 450 ). The project includes site evaluation and environmental assessment, followed by two field tests for process evaluation. A site was selected eight miles west of Rawlins, Wyoming, in Section II, T2IN, R89W. The first test was completed in December of 1979 and met all of the test objectives. The coal was ignited at a vertical depth of 400 ft. utilizing a directionally drilled process well pair with a drilled link between well bases. The 35-day test included both water/air injection and steam/O 2 injection phases. According to plan, approximately 1200 tons of coal were utilized. During the air gasification phase, product gas quality initially climbed to ISO Btu/SCF and, as expected, gradually declined to the 120-130 Btu range over a 21-day period at production rates between 3000 and 4500 SCFM. The five-day steam/O test yielded 230-280 Btu/SCF gas at rates ranging between 2000-4000 SCFM. Post-test characterization has bee completed and included drill coring, sonar measurements, and TV camera lotminir of the resrrltnnt hirrn onuit'? Trnn

of 1980 preparations were begun for a second field test at the Rawlins site. The second test will include

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, was selected for DOE's first programmatic activity in the new Underground Coal Gasification program. SNL completed the site characterization activities which utilized surface geophysical techniques, borehole and cross-borehole geophysical techniques, and taking and analyzing overburden and coal cores, LLNL performed hydrologic testing and an environmental investigation. The surface geophysical techniques were used to delineate geologic structure and determine coal seam continuity. The reflection seismic data uncovered a more complex structure at the site than was determined from boreholes alone. The borehole geophysical logs were used to identify coal seams and their thicknesses, estimate overburden strength and coal quality, help determine lithologv, and used for stratigraphic correlation between exploratory boreholes. The cross-borehole, in-seam seismic wave studies were used to determine coal seam continuity, and the results of these studies are in basic agreement with the reflection seismic survey results. The coal quality was determined from coal cores. The hydrologic tests were used to estimate the permeability of the overburden and coal seam which will be used to estimate water influx rates for a UCG process. The environmental work evaluated the potential consequences to ground, air, water, and archeological conditions. The project activities, which are complete, uncovered no characteristic that would prevent a UCG test in the Tono Basin. The DOE is investigating the possibility of following testing on the site.

Project Cost; $850,000

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-89 STATUS OF SYNFUELS PROJECTS/COAL (Underline Denotes Changes Since March 1981)

UNDERGROUND COAL CONVERSION PROJECTS (Cont.)

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 gasif ying 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 SI Btu/scf with an average production rate of 285 MMI3tu/day. In the second phase utilizing steam-oxygen, the heat content of the product gas averaged 230 Btu/scf with the maximum value obtained being 260 Btu/scf.

Project Cost: Undetermined

UNDERGROUND GASIFICATION OF TEXAS LIGNITE - Texas A&M University Texas A&M is presently conducting field tests to develop the Linked Vertical Well process for in situ gasification of Texas lignite. The first project site was about three miles southwest of the campus at College Station, Texas. The objectives of the field experiment were to test the procedures of ignition, back burn, gasification, and to gather environmental- -data. Water-intrusion from an overlying aquifer prevented sustained combustion at this site. A second gasification test site has been selected in Milam County, Texas on lands owned-by Alcoa. Target- zone is a 14-foot thick lignite zone at a depth of 227 feet. Plans called for gasification of about 2,000 tons of lignite during the 1980 test.

Project Cost: $250,000/year

4-90 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT COAL PUBLICATIONS

Abner. David, "Cool Water Integrated Coal Gasification Combined Cycle Plant" presented at the 8th Energ y Technology Conference, sponsored by the AC'JA. EPRI. GRI, and NCA. held in Washington. D.C. on March 9-11, 1981.

Akiyama. S. and T. Hisamoto. "Chlnro!nethanes From Methanol." in Hydrocarbon Processing. March 1981 issue, pages 76- 78.

"Alberta Coal Can Be Readily Liquefied," a staff article in Oilweek, March 23, 1981 edition. pages 40-42.

Alger, J. R. M.. "Summary of IGCC Projects Worldwide," presented at the 8th Energy Technology Conference, sponsored by the AGA. EPRI, GRI, and NCA, held in Washington, D.C. on March 9-Il, 1981.

Alves, Gerald. Sr., "The TVA Ammonia from Coal Project - 1981 Update," presented at the 8th Energ y Technology Conference, sponsored by the AGA. EPRI. GRI, and NCA, held in Washington. D.C. on March 9-11, 1981.

Anderson. R. P., "Disposable Catalysts in the SRC Processes.." presented at the A.1.Ch.E. 1981 Spring Meeting, Houston, Texas, A pril 1981.

Anthon y, R. G. and B. B. Singh. "Olefins From Coal via Methanol." in Hydrocarbon Processing, March 1981 issue, pages 85- 88.

Arnold, J. M., "Materials Considerations for Coal Gasification," presented at the A.I.Ch.F.. 1981 Spring Meeting, Houston, Texas, April 1981.

Apffel, J. A. and T. M. Chen. "Application of On-Line Multidimensional Chromatography to Solvent Refined Coal," presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981.

Aude, Thomas.y "Pipeline Transportation of Coal," presented at the IGT symposium on Advances in Coal Utilization Technolog IV. held in Denver, April 22-24. 1981.

Bader. B. E. and H. E. Glen, "The Role of Site Characteristics in the Control of Underground Coal Gasification." presented at the A.l.CftE. 1981 Spring Meeting, Houston, Texas. April 1981.

flaltisberger. R. J. et al.. "Separation and Chemistry of Lignite Derived Preasphaltenes by GPC and NMR," presented at the 181st ACS National Meeting, Atlanta, Georgia. March 1981. - Barnett. W. P., "Materials Selection for the 5KG-I Coal Conversion Process.' presented at the A.I.Ch.E. 1981 Spring Meeting. Houston, Texas, April 1981.

Bartke, T. C., "The DOE Underground Coal Conversion Program Field Test Activities in 1979 and 1980," presented at the A.I.Ch.F.. 1981 Spring Meeting, Houston. Texas, April 1981.

Bauer, P. H. and D. T. Chazan. "0 Desenvolvimento do um Processo para Obtencao de Gas Combustivel de Baixo Poder Calorifico a Partir de Carvoes Corn Abs Torres Inertes," presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco. 124, Rio dc Janeiro, April 1981.

Baxter. John F.. "Issues Associated with the Potential Development of Underground Coal Gasification in Colorado," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24, 1981. Beeson, J. L. and D. A. Duncan, "Ethane. Phenols, Cresols, and BTX from Coal, Lignite, or Peat using HYFLEX TM Technology," presented at the A.I.CtLE. 1981 Spring Meeting. Houston, Texas. April 1981.

Bell, A. T. and T. J. Fredrick, "Participation of H ydrogen in the H ydrogenolysis and H ydrogenation of Coal-Related Codel Compounds Catalyzed by Zinc Halides," presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981.

Bhay net, Subhash, "Future Competitive Position of Illinois Basin Coal," presented at the IGT s ymposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24. 1981.

Biases, P. E., "The Zinc Chloride Process for the H ydrocracking of Coal," in International Journal of Energy Research, April-June 1980 issue.

Biljetina, R., "HYGAS - Western Kentucky Coal Results," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-91 RECENT PUBLICATIONS - COAL Bloom, Ralph, Jr., "The COGAS Process Demonstration Plant," presented at the 8th Energy Technology Conference, sponsored by the ACA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-1I, 1981. Bockrath, B. C. and R. P. Noceti, "Evaluation of the Donor Ability of Coal Liquefaction Solvents," presented at the 181st ACS National Meetin g, Atlanta, Georgia, March 1981. Boerieke, Ralph R., "Advances in Pressurized Fluidized Bed Stream Cycle Technology." presented at the lOT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Brule, B., "Calibration Curve for GPC Analysis of Asphalts," presented at the 181st ACS National Meeting, Atlanta. Georgia. March 1981. Burke. F. P. et al. "Reverse Phase Liquid Chromatographic Separation of Coal Liquefaction Solvents." presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981. Cammack. P., "Coal Preparation for Conversion Processes." presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on Tyne. England. April 1981. Canonico, D. A., "Metallurgical Constraints on the Design of Large Pressure Vessels for Coal Conversion Systems." presented at the A.I.Ch.E. 1981 Spring Meeting. Houston, Texas. April 1981. "Catalytic Combustion of Coal-Derived Liquid Fuels." EPRI Report No. AP-1666. prepared by Acurex Corporation for the Electric Power Research Institute. 1981. Chambers. W. C., "Competition Between S ynthetic Fuels Conventional Gasoline and Natural Gas." presented at the lOT symposium on Advances in Coal Utilization Technology IV. held in Denver. April 22-24. 1981. Chapman, James N., "Coal Fired MHD/Steam Electric Power." Production: Status Report, presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24, 1981. Christensen, J. J.. "Heavy Vessel Fabrication Capability for Coal Gasification." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Clarke, J. W., "Filtration in Coal Liquefaction: Influence of Solids Distribution upon Filtration Rates," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston. Texas, April 1981. Clinton, J. H. and C. W. Curtis, "Effects of Coal Minerals. By-Product Metallic Wastes and Other Additives on Coal Liquefaction," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texts, April 1981. "Coal Competition: Prospects for the 1980's," draft report by DOE's Office of Competition, Report #DOE/PE-0027. 1981.

Corbett, R. W.. "Developments in Critical Solvent Deashing," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Corman, James. 1110CC Experimental Simulation." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-I1, 1981. Cortez, D. and C. J. La Delfa, "Coal Pyrolysis Looks Good," in Hydrocarbon Processing, Vol. 60, No. 2, February 1981, pages 111-117. Cruz, S., R. Vitali, and S. Villa, "A Gaseificacao dc Carvao em Caseificadores a Leito Fixo corn Duplo Estagio." presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco, 124. Rio de Janeiro, April 1981. Cunha, C. C.,"Geracao de Calor Industrial por Combustao Fluidizada de Carvoes Brasileiros." presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara. Au. Rio Branco, 124, Rio de Janeiro, April 1981. Curtis, C. W. and J. A. Gum, "A Study of Deactivation and Regeneration of Catalysts Used in the LC-Fining of Solvent Refined Coal," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Cypres. R. and S. Furfari, "H ydrocarbonization and Flash Hydropyrolysis of Coal," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on T yne, England. April 1981.

4-92 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 RECENT PUBLICATIONS - COAL

Davis, G. 0. and D. F. Williams. "The Role of H ydrogen in UK Coal Liquefaction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Davis, Robert L, "Thermal Analysis of In Situ Conversion of Coal," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Derbyshire, J., at al., "Interactions Between Solvent Components, Molecular Hydrogen and Mineral Matter During Coal Liquefaction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. g DeVaux, George, "H-Coal Commercial Plan," presented at the 8th Ener y Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-I1. 1981.

Dickenson, R. K., "Coal Liquefaction." presented at Synthetic Fuels, Prospects Under the Reagan Administration. sponosored by U.S. National Committee of the World Energy Conference, Washington, D.C., April 1981.

DiSanzo, F. P., "Characterization of High Boiling Components in Fischer-Tropsch Liquids," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Dorstewitz, Ulrich, "The KGN Moving Bed Technology and Coal Compaction," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Doyle, James, "W.R. Grace Coal to Gasoline Project." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington. D.C. on March 9-11, 1981.

Duncan, Dennis, "Riser Cracking of Coal," presented at the IGT s ymposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. du Plessis, M. P., "Coal Conversion Research," in CIM Bulletin. February 1981, pp. 81-88.

Eccles, R. M. and G. R. DeVaux, "Current Status of H-Coal Commercialization," presented at the A.I.C1-LE. 1981 Spring Meeting, Houston, Texas, April 1981.

Eckhart, Michael. "Industrial & Utility Markets for Low- and Medium-Stu Coal Gasification," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-11, 1981.

Edgar, T. F. and H. P. Tsang, "Combustion and Gasification Properties of Texas Lignite," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Epperly, Robert. "Exxon Donor Solvent (EDS)." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-11, 1981.

Euker, C. A., "Catalytic Coal Gasification Process Development Unit Operations," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Finkelman, R. B., "Modes of Occurrence of Trace Elements in Coal," U.S.G.S. Open File Report #OF-81-0099, 1981.

Finseth, D. H.. "Analytical Chemistry in Support of Coal Liquid Stability Studies," presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981.

Franklin, H. D. and W. A. Peters, "Effects of Calcium Minerals on the Rapid Pyrolysis of a Bituminous Coal," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Franz, J. A. and D. M. Camaioni, "Radical Pathways of Coal Dissolution in Donor Media During Reactions of Coals and Specifically Deuterated Tetralin," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Freihaut, J. D. and D. J. Seer y , "An Investigation of Yields and Characteristics of Tars Released During the Thermal Decomposition of Coal," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Fumich, C., "Synfuels from Coal—The Next Five Years, The Next Twenty," presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981.

Furman, A. H., "Effect of Deep Bed Stirring on Gas Compositions in a Fixed Bed Reactor," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Gallagher, J. E., "Catalytic Coal Gasification for SNG Manufacture," in International Journal of Energy Research, April- June 1980 issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-93 RECENT PUBLICATIONS - COAL

Gangwal. S. K., "Fundamental Aspects of Catalysed Coal Char Gasification," in International Journal of Energy Research. April-June 1980 issue.

Cannon, R. E., "The AVCO Gasifier in a Combined Cycle Power Plant," presented at the IGT symposium on Advances in Coal Utilization Technology IV. held in Denver, April 22-24, 1981. Goldberg, M., "The Combustion Turbine - Future Design and Fuel Flexibility," presented at the 43rd Annual Meeting of the American Power Conference, at the Palmer House, Chicago, April 1981. Gomi, K. and Y. 1-lishinuma, "Effect of Preoxidation on Reactivity of Chars in Steam," presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981.

Gray, David, "The Impact of Developing Technology on Indirect Liquefaction," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Gray, Robert, "SNG Production in the Memphis Demonstration Plant," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington. D.C. on March 9-11, 1981. Gray, R. W., "Memphis Light, Gas & Water Fuel Plant," presented at the A.I.Ch. E. 1981 Spring Meeting, Houston, Texas. April 1981.

Haar, Lawrence, "Coal Supply/Demand:- 1980-2000," presented at the IGT-symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24. 1981.

Haggin, J.,"C 1 Chemistry Development Intensifies," in C & EN, February 23, 1981. pages 39-47 Hamilton, R., "Research and Development Support for the SRC Demonstration Program," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Hanson, R. L., et al., "Chemical Fractionation and Analysis of Organics in Low Btu Gasifier Effluents," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Harris. C. A., "Coal-Derived Pyrolysis Feedstocks," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

Hausler, D. W. and L. T. Taylor, "Specific Metal Detection in the Size Exclusion Separation of Solvent Refined Coal," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Henry, R. M., "Determination of Vapor-Liquid Equilibria for the SRC-II Liquefaction Process." presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

I-lerceg, Joseph E., "Molten Carbonate Fuel Cell Systems Development," presented at the !GT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Hill, George, "Pyrolysis Route for Coal Liquids Production (Univ. of Utah/Utah Power & Light Project)." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GEl, and NCA, held in Washington, D.C. on March 9-11, 1981.

Hillenbrand, L. J., "Coal Depolymerization," presented at the IGT s ymposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Ho, K. C.,"Repowering a Steam Turbine Plant Utilizing Coal Gasification Combined Cycle Technology," presented at the 43rd Annual Meeting of the American Power Conference, at the Palmer House, Chicago, April 1981.

Holmgren, J. D., "Coal Gasification/Combined Cycle System is Ready for Commercialization." in Modern Power Systems. March 1981, pp. 44-51. Hommert, P. and T. Bartel, "Instrumenting and Evaluating Large Scale In Situ Experiments," presented at the A. I.Ch. E. 1981 Spring Meeting, Houston, Texas, April 1981.

Huffman, G. P., "Investigation of the High-Temperature Behavior of Coal Ash in Reducing and Oxidizing Atmospheres," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Hughs, B. M., "Pyrolysis/(GC) 2 /MS as a Coal Characterization Technique," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

4-94 CAMERON SYNTHETIC FUELS REPORT. JUNE 1981 RECENT PUBLICATIONS - COAL Iluiba's, D. T. A.. 'The Role of the Catalyst in the 11-Coal Process,' presented at the A.I.Ch.E. 1981 Spring Meeting, Houston. Texas, April 1981. Humphrey, J. L., "A Preliminary Assessment of the Integration of a Coal Gasifier into a Petroleum Refinery," presented At the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. flung. Y. T., at al., "Activated Sludge Treatment of Diluted Slagging Fixed-Bed Coal Gasification Wastewaters," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. llurtiihise, R. J., et al., "Separation and Characterization of Polycyclic Aromatic Hydrocarbons and Alkylphenols in Coal Derived Solvents." presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981. IF.A Coal Research, "The Future Economics of Coal Transport," edited by H. M. Lee, Report #EAS D2/79, July 1980. tribe. Christman. "Great Plains Coal Gasification Associates Program," presented at the 8th Energy Technology Conference, sponsored by the AGA. EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11, 1981. Issacs, L. L. and W. V. Wang. "The Heat Capacities of Coal Chars," presented at the A.1.Ch,E. 1981 Spring Meeting, Houston, Texas. April 1981. .Jobst, IN.. "Chemical Feedstocks via Fast P yrolysis of Lignite," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Johnson, Craig R., "Gas From Coal: Market Prospects and Problems," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24, 1981. Johnson, Edward, "Coal and Oil Shale Reclamation and Revegctation Research Activities,' presented at EPA's Fifth National Conference entitled Interagency Energy/Environment R&D Program. Washington, D.C., May 1981. Jones, D. W. and K. D. Bartle, "Characterization of Alkanes in Extracts of Coals, Lignites and Related Fuels," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Jones, Fred L.. "Gasification of Western Coals: Fuel for Thought," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Jones, M. L., "Trace Element Analysis of the Magnetic Portion of Slag from the Grand Forks Energy Technology Center's Slagging Fixed-Bed Gasifier," presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981. Jordan, J., "Voltammetr y of Sulfur Pollutants in Coal Conversion Process Steams,' presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981. Justen, L., "Analytical Applications for Coal Liquefaction Process Monitoring,' presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981. Katz, E., "Coupled Column Chromatography Used for the Analysis of Coal Derived Liquids," presented at the 181st ACS National Meeting, Atlanta. Georgia, March 1981. Kaufman, H. C. and T. L. Reed, "Cool Water Coal Gasification—Combined-Cycle-Power Plant." presented at the A. I.Clt E. 1981 Spring Meeting, Houston, Texas. April 1981. Keiser, J. R. and V. B. Baylor. "Control of Fractionation Area Corrosion at SRC Pilot Plants," presented at the A. I.Ch. E. 1981 Spring Meeting, Houston, Texas, A pril 1981.

Kelly, J. F., "Coal Liquefaction in Canada: The CANMET Program," in CUM Bulletin, February 1981, pp. 72-80. Kennedy, C. R., "Refractories for Slagging Gasifiers: Problems, Solutions, and Trade-Offs," presented at the A. l.Ch. E. 1981 Spring Meeting, Houston, Texas, April 1981. Knoblauch, K. and E. Richter. "Application of Active Coke in Processes of SO and NO Removed From Flue Gases," presented at the Centenary Celebrations Conference of the British Society of Chemical Indstry, University of Newcastle on Tyne, England, April 1981. Knowlton, Ted, "Void-Gas Stripping in Standpipes." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-95 RECENT PUBLICATIONS - COAL

Knudson, C. L., at al. "Hydrogen-Carbon Monoxide Reactions in Low Rank Coal Liquefaction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Kolcsh, V. A.." Low Btu Gasification of Northern Plains Lignite in a Commercial-Sized Demonstration Unit," presented at the 43rd Annual Meeting of the American Power Conference, at the Palmer House, Chicago, April 1981. Kowalski, David P., "Coal Handling Technology for the Synthetic Fuels Industry," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Kucnzi, W., "Components and Typical Costs of Coal-to-Gasoline Plants," presented at the Engineering News Record conference, Making S ynfuels Plant Business Your Business, Washington, D.C., March 1981.

Kunesh, J. G. and M. Calderon. "Equipment Design in Coal Conversion Systems When Faced with Phase Separation Uncertainty." presented at the A.I.Ch.E. 1981 Spring Meeting. Houston, Texas, April 1981. Leppin, Dennis. U-Gas Status." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Levine, Seth. "Disposal of Coal Gasifier Waste Streams by Evaporation," presented at the IGT symposium on Advances in Coal Utilization Technology IV. held in Denver, April 22-24, 1981.

Lewis, James, "Test Results of the EPRIJB&w 6X6 Fluidized Bed Combustor." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24, 1981. Liceardi, A. L., "Coal Technologies Under Development. Prospects, Advances, Strategies and Timetable," presented at the lOT symposium on Advances in Coal Utilization Technology IV. held in Denver. April 22-24, 1981.

"Lignite-to-Methanol: An Engineering Evaluation of the Winkler Gasification and ICI Methanol Synthesis Route," EPRI Report Number EPRI AP-1 952, Project 823-3, October 1980.

Lin, Y. A., "Recent Developments in High Gradient Magnetic Separation for Coal Desulfurization," presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981.

Livingston, R.. et al., "ESR Study of Bibcnzyl During Pyrolysis with and Without H ydrogen," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Long, C. W., "Interaction of Design Materials Selection, and Process Parameters as Related to Open Cycle Coal-Fired MILD Power Generation." presented at the A.I.CItE. 1981 Spring Meeting, Houston. Texas, April 1981.

Manfred, Rolf K., "Coal Slurries as Alternate Utility Boiler Fuels." presented at the IGT symposium on Advances in Coal Utilization Technology IV. held in Denver, April 22-24, 1981.

Martin, E. and G. V. Sullivan, "Characterization of Residues from Selected Coal Conversion Processes," U.S. Bureau of Mines Report of Investigations #8501, 1980.

Matsunaga. A. and S. Kusa yanagi. "A Comparative Study of HPLC Column Packings for the Separation of Aromatic and Polar Compounds in Fossil Fuel Liquids," presented at the 181st ACS National Meeting, Atlanta, Georgia. March 1981. Mazliach, D.. "A Survey of Substitute Fuels (for Boilers)." presented at the 43rd Annual Meeting of the American Power Conference, at the Palmer House, Chicago, April 1981.

Mazzocio, N. J., "Study of Catalytic Effects of Mineral Matter Level on Coal Reactivity," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981.

McCabe. D. E. and J. D. Lander. "Design Properties of Steels for Coal Conversion Vessels," an interim report, number EPRI-AP-1508, to EPRI by Westinghouse R&D Center, 1980.

McCabe, J. T., "Components for Coal Gasification: The Transition From Pilot to Demo Plant," presented at the 8th y Energ Technology Conference, sponsored by the AGA. EPRI, GE!, and NCA, held in Washington, D.C. on March 9-11. 1981.

McMillan, D. G. and W. C. Ogier, "Coal Structure Cleavage Mechnanisms: Scission of Diphcnylmcthanc and Diphenyl Ether Linkages to Hydroxylatcd Rings," presented at the 181st ACS National Meeting, Atlanta, Georgia. March 1981. Reviewed in this issue.

4-96 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS -COAL Moroni, E. C., "Disposable Catalysts for Coal Liquefaction: Status Review,' presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. *"Montana Energy Almanac - 1980," an update of a 1976 almanac by the Montana Department of Natural Resources and Conservation, 32 S. Ewing, Helena, Montana 59620, phone: (406) 449-3780. *National Coal Association. "A Forecast for U.S. Coal in the 1980s," by the NCA, 1130 Seventeenth Street, N.W., Washington, D.C. 20076, 1981. National Coal Board. "Liquid Fuels From Coal," a NCB report prepared by the Coal Research Establishment, Stoke Orchard, Gloschester, August 1978. National Coal Board, "Proposals for National Programme on Coal Utilisation," prepared by NCB's Coal Research Establishment, Stoke Orchard, Cheltenham, Glosehester, March 1980. Newlander, C. K. and S. K. Kimura, "PDU Coal Gas Clean-Up System." presented at the A.LCh.E. 1981 Spring Meeting, Houston, Texas, April 1981. Oak Ridge National Laboratory, "Liquefaction Technology Assessment - Phase I: Indirect Liquefaction of Coal to Methanol and Gasoline Using Available Technology," ORNL-5664, prepared for the DOE, February 1981, 398 pages. Odoerfer, G. A., et al., "Chromatographic Separation of Functional Group Classes from Process Derived Recycle Solvents," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Oko, U. M., "Effect of Selected Catalysts on Hydropyrolysis of Utah Bituminous and Montana Rosebud Coals," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. O'Leary, J. R. and G. C. Rappe, "Scale-up of an SRC Deashing Process from a 6 TIn Pilot Plant to a 6000 T/D Demonstration Plant," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas. April 1981. Owen, J., "Conversion and Uses of Liquid Fuels From Coal," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on Tyne, England, April 1981. Page, Gordon, "Application of Lurgi 'Kosovo' Results to Pollution Control Process Design," presented at the IGT sy mposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Parker, J. W., "Coal-based Technologies,' presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, E.G., March 1981. Parker. J. %V., "Liquid Synfuels Via Pyrolysis of Coal in Association with Electric Power Generation," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Patel. J. G., "The U-Gas Process," in International Journal of Energy Research, April-June 1980 issue. Patel, S. S., "Foreign Coal Liquefaction Technology Survey and Assessment," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Pay. T. D.,"Sasol Synthetic Fuel Facilities," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981. Petrakis, L., "In Situ Observation of Free Radicals in Coal Liquefaction," presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy, Pittsburgh, March 1981. Pfeiffer, Heinz, "Utility Perspective of MUD Power Plants," 'presented at the 8th Energy Technology Conference, sponsored by the AGA, EPFII, GRI, and NCA, held in Washington, D.C. on March 9-I1, 1981. Pfeiffer, Roland, "The HUMBOLDT Coal Gasification Process," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA, held in Washington, D.C. on March 9-I1, 1981. Plumlee, K. IV., et al., "Exxon Donor Solvent Coal Liquefaction Process: Development Program Status," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Pollaert, T. J., "Outlook for Commercial Coal Conversion Synfuel Plants," presented at the Engineering News Record conference Making Synfuels Plant Business Your Business, Washington, D.C., March 1981. *Reviewed in this issue.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 497 RECENT PUBLICATIONS - COAL Pryor, J. A., "The SRC-I Demonstration Plant," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston. Texas, April 1981. Randieh, E., "Materials Selection for High Pressure Letdown Valves in Coal Liquefaction Systems," presented at the A.I.CI'LE. 1981 Spring Meeting, Houston, Texas, April 1981. Rector, Walter, Sr., "Solvent Refined Coal, SRC-I (Solids)." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA. held in Washington. D.C. on March 9-11, 1981. Releofsky, H. L. and H. Schultz. "Characterization of Coal-Derived Liquids—The Need for Standardization." presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Retafliek, F. D., "Industry Perspective of MIlD Power Plants." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR!. and NCA, held in Washington, D.C. on March 9-11, 1981.

Romey, I., at al., "Production of Distillate Oils from German Coals," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Ross, D. S. and Q . C. Nguyen, "Coal Conversion in CO/H 20 Systems," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Rousseau, R. W. and R. U. Kelly, "Evaluation of Methanol as a Solvent for Acid Gas Removal in Coal Gasification Processes," oresented at the A.I.CILE. 1981 Spring Meeting, Houston, Texas, April 1981. Ruberto, R. G., at al., "Composition of Coal Liquid Fractions Separated from SRC-11 Heavy Distillate Material," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Rudins, George. "A Status Report of the U.S. National Program for MUD Power Generation," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, GRI, and NCA. held in Washington, D.C. on March 9-11, 1981.

Samuel, William, "SASOL Two Plant in South Africa," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, OR!, and NCA, held in Washington, D.C. on March 9-11, 198!. Santos, L. S., "Modelagem e Simulaeao de Gaseificador de Carvao," presented at the II Congress Brasileiro de Energin, sponsored by the Clube de Engenhara, Au. Rio Branco, 124, Rio de Janeiro. April 1981. Sehlinger, W. 0., "Coal Gasification Development and Commercialization of the Texaco Coal Gasification Process," in International Journal of Energy Research, April-June 1980 issue. Sehmal, M. and J. L. Monteiro, "Gaseificaeao de Carvao," presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco, 124, Rio de Janeiro, April 1981.

Schma!, M., I. P. Silva. and J. L. Monteiro, 'Liquefaeao de Carvao," presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco. 124, Rio de Janeiro, April 1981. Schmid, B. K., "Economic and Market Potential for SRC-11 Products," in International Journal of Energy Research, April- June 1980 issue. Schmid, B. K. and D. M. Jackson. "The SRC-1I Demonstration Program—A Status Report," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas, April 1981. Schuster, E., "The Pressurized CGT Combi Gasifier." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981. Schwartz, Alan, "Solvent Refined Coal, SRC-2 (Liquids)," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR!, and NCA, held in Washington, D.C. on March 9-11, 1981. Seder, A. R., Jr., "Coal Gasification," presented at Synthetic Fuels. Prospects Under the Reagan Administration. sponsored by U.S. National Committee of the World Energy Conference, Washington, D.C., April 1981. Sherwin, M. B., "Chemicals From Methanol," in Hydrocarbon Processing, March 1981 issue, pages 79-84. Shires, M. J., "Fuel Gas From Coal," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on Tyne, England, April 1981.

4-98 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 RECENT PUBLICATIONS - COAL Simbeek, Dale, 'Coal Preparation for Optimum Coal Gasification & Liquefaction," presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI, CR1, and NCA, held in Washington, D.C. on March 9-11, 1981. Skowronski, R. P. and J. J. Ratio. "An Isotopic Investigation of the Chemistry of Coal Hydroliquefaction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Spencer. D. F.. "The Coolwater Coal Gasification Combined Cycle Plant." presented at the 43rd Annual Meeting of the American Power Conference, at the Palmer House, Chicago. April 1981. Srinivas, B. and N. H. Amundson, "Intraporticle Effects of Char Combustion," presented at the A. I.Ck a 1981 Spring Meeting, Houston, Texas, April 1981.

Struck, H. T. and C. W. Zielke, "Hydroeracking of Coal to Light Distillates With Molten Zinc Chloride," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on Tyne, England, April 1981. Sullivan, J. A. and R. J. Jensen, "Laser-Based Spectroscopic Techniques for Measurement of Contaminant Species in Coal Gasification Product Streams," presented at the A.I.Cft E. 1981 Spring Meeting, Houston, Texas, April 1981. Supp , E., "Improved Methanol Process," in H ydrocarbon Processing, March 1981 issue, pages 71-75. Tang, J. I. S. and F. K. Kawahara, "The Use of Microreticular Resin for Separation of Coal Conversion Process Wastewater," presented at the 181st ACS National Meeting, Atlanta. Georgia, March 1981. Taunton, J. W., et al., "Coal Feed Flexibility in the Exxon Donor Solvent Coal Liquefaction Process," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry. University of Newcastle on Tyne, England. April 1981.

"Test and Evaluation of Methanol in a Gas Turbine S ystem." EPRI Report No. AP-1712. prepared by the Southern California Edison Company for the Electric Power Research Institute. 1981. Thomas, M. G., "Catalysts in Coal Liquefaction." presented at the 8th Energy Technology Conference, sponsored by the AGA, EPRI. CR1, and NCA, held in Washington, D.C. on March 9-I1, 1981. Thomas, M. G., "Characterization and Deactivation Studies of Coal Conversion Catalysts." presented at the ACS Pittsburgh Conference on Analytical Chemistry and Applied Spectroscopy. Pittsburgh, March 1981. Thomas, M. G. and T. C. Bickel, "The Effects of Catalysts on SCT Liquefaction," presented at the 181st ACS National Meeting. Atlanta, Georgia, March 1981.

Thompson, G. J. and A. C. Vickers. "Mathematicall y Modelled Comparison of Fischer-Tropseh Reactor Systems," presented at the A.I.CftE. 1981 Spring Meeting, Houston, Texas, April 1981.

Thorsness, C. B., "Data Analysis From Recent United States Underground Coal Gasification Experiments," presented at the A.l.CItE. 1981 Spring Meeting, Houston, Texas, April 1981. 'l'horsness, C. B., "Steam Tracer Experiment at the [toe Creek No. 3 Underground Coal Gasification Field Test," Lawrence Livermore Laboratory Report Number UCRL-53082, November 1980. Thring, M. W., "Mining Coal Without Men Going Underground," presented at the It Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco, 124, Rio de ,Janeiro, April 1981. - Tiller, F. M. and R. Chow, "Analysis of Wilsonville Constant-Pressure Filtration Data," presented at the A.l.Ch. E 1981 Spring Meeting, Houston, Texas, April 1981.

Toscani, H. and R. Rech, "Obteneao de Gas de Medio Poder Calorifico a Partir da Gaseifieaeao de Carvao em Leito Fluidizado Pressurizado," presented at the II Congress Brasileiro de Energia, sponsored by the Clube de Engenhara, Au. Rio Branco, 124, Rio de Janeiro, April 1981. Ubhayakar, S. K., "Dynamic Computer Simulation of Entrained Flow and Fluidized-Bed Gasifiers," presented at the IGT symposium on Advances in Coal Utilization Technology IV. held in Denver, April 22-24, 1981. *U.S. Regulatory Council, "Cooperation and Conflict; Regulating Coal Production," 198i. Reviewed in this issue

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-99 RECENT PUBLICATIONS - COAL

U.S. Energy Information Administration, The Substitution of Coat for Oil and Natural Gus in the Industrial Sector," report NTIS number DOE/EIAITR-0253, 1981. Utz, B. II., et al., "Coal-Derived Product Analysis: Pressure Filtration vs. Soxhlet Extraction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Vernon, L. W., et al., "Hydrogenolysis of Dilute Solutions of Dibenzyl in Toluene at Coal Liquefaction Conditions," presented at the 181st ACS National Meeting, Atlanta. Georgia, March 1981.

Virk, P. S., et al., Model Pathways for Hydrogen Transfer in Coat Liquefaction," presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981.

Vorres, Karl, 'Overview of Coal Conversion to Gases and Liquids." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Vorres. K. S., "Status of Coal Gasification Processes," in International Journal of Energy Research, April-June 1980 issue.

Voss, George, U., "Performance Characteristics of the Solid Fuels (TM) Gasification Type Burner." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24. 1981.

Walker, P. L., "Structure of Coals and Their Conversion. to Gaseous Fuels," presented at the Centenary Celebrations Conference of the British Society of Chemical Industr y, University of Newcastle on Tyne. England, April 1981. p Watanasiri, S., "Correlation of Coal Conversion System Phase Se aration Data,' presented at the A.I.Ch. E 1981 Spring Meeting, Houston, Texas. April 1981.

Watkiron. A. P., "Gasification of Coal in a Spouted Bed," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24. 1981.

Wellman. Paul. "The H-Coal Technology, Progress Towards Commercialization," presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver, April 22-24, 1981.

Whitehurst, U. D., "Effects of Mineral Components on Coal Liquefaction," presented at the A.I.Ch.E. 1981 Spring Meeting, Houston, Texas. April 1981.

Wilson, J., "Active Carbons From Coal," presented at the Centenary Celebrations Conference of the British Society of Chemical Industry, University of Newcastle on T yne, England, April 1981. Winsor, Lloyd, "Technical Considerations in Burning Coal Derived Gas in a Utility Power Plant Boiler." presented at the IGT symposium on Advances in Coal Utilization Technology IV, held in Denver. April 22-24, 1q81.

Witmer, F. E., "Environmental Concerns for Coat Synfuel Commercialization," in International Journal of Energy Research, April-June 1980 issue.

Welk, R., "Evolutionary Changes in the Preception of the Role of the Recycle Solvent in the Direct Hydroliquefaction of Coal," presented at the A.l.Ch.E. 1981 Spring Meeting, Houston, Texas. April 1981.

"Workshop on Critical Coal Conversion Equipment," a record of four workshop sessions sponsored by the Engineering Societies Commission on Energy, Inc., held in Huntington, West Virginia on October 1-3, 1980, published by the U.S. Department of Energy as NTIS Document Number FE-2468-88. 1981.

Wragg, J. G., "1 MW ARC-Coal Acetylene Test Results and Commercial Economies," presented at the A.I.CttE. 1981 Spring Meeting. Houston, Texas. April 1981.

Yesavage, V. F., et al., "The Measurement and Correlation of the Enthalpy of Coal Derived Liquids." presented at the A.I.Ch.E 1981 Spring Meeting, Houston. Texas, April 1981.

Young, E. S. and M. J. Sepaniak, "Coal Classification by HPLC and Three-Dimensional Detection." presented at the 181st ACS National Meeting, Atlanta, Georgia, March 1981. Reviewed in this issue.

4-100 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 COAL - PATENTS

ComCo, Joseph W. Cochran - Inventor, U.S. Patent 4239,496, Dec. 16, 1980, "Gas C ycle Fluid Energy Process for Forming Coal-In-Oil Mixtures." The patent describes a process for forming coal-in-oil fuel mixtures where coal is pulverized in a fluid energy pulverizer by use of a noncombustible carrier gas. The pulverized coal is separated and the spent gas cleaned to remove moisture and residual coal.The cleaned gas is compressed, reheated and returned to the pulverizer for re-use as carrier gas therein.

Exxon Research & Engineering Company, R.B. Long - Inventor, U.S. Patent 4.250,014, February 10, 1981, "Coal Liquefaction Process.' Particulate coal is contacted with a vanor phase hydrogen donor solvent to swell the coal particles and, thereafter, the swollen coal particles are subjected to coal liquefaction conditions in the presence of a liquid phase solvent.

Exxon Research & Engineering Company, W.J. Metrailer - Inventor, U.S. Patent 4,244,305, Januar y 13, 1981, "Liquid Yield From Pyrolysis of Coal Liquefaction Products." This patent teaches that the quantity and quality fo liquids produced from solid coal can be enhanced by a process comprising a liquefaction zone and a pyrolysis reactor, preferably a fluid coking zone, wherein the heavy liquids obtained in the p yrolysis reactor, e.g., 1000° F+ materials having a Conradson Carbon content of at least 15 wt. percent are recycled to the liquefaction zone, rather than to the pyrolysis reactor, for further treatment under hydrogenation conditions and, consequently, conversion of the heavy liquids to lower boiling liquids which may be removed from the pyrolysis reactor feed by distillation is achieved.

Exxon Research & Engineering Co., Richard H. Sehlosberg and Charles C. Scouten - Inventors, U.S. Patent 4,256,568, March 17, 1981, "Removal of Phenols From Phenol-Containing Streams." The patent describes a process for removing phenols from phenol-containing streams such as coal liquids by contacting the stream with a multivalent metal composition selected from the group consisting of oxides and/or hydroxides of one or more multivalent metals capable of forming a hydroxy metal phenate with the phenols of the stream. The hydroxy metal phenate is separated from the treated stream and the hydroxy metal phenate is heated to its decomposition temperature, thereby forming phenols and oxides of the multivalent metal.

Firma Carl Still GmbH & Company, H. Weber - Inventor, U.S. Patent 4,247,365, January 27, 1981, "Method for Cooling and Dedusting Degasifieation Gases Escapin g From Coal Degasification Chambers." A method of cooling and dedusting degasification gases which escape from coal degasification chambers, particularly gases which are obtained in high temperature or low temperature carbonization of bituminous and subbituminous coals and which pass from degasification chambers through risers and bends into collection mains and in the bends or in the collecting mains themselves which comprises directing crude tar having a temperature in excess of 50° C and lower than 170° C into the bends and collecting mains either alone or with water added which has a temperature and is of a quantity such that it completely evaporates in the collecting main. An apparatus for carr ying out the method includes means for spraying either the tar or the tar plus water into the collecting main containing the degasification gases and passing the gases and the liquids from the main into a cooler to separate the gases and a liquid condensate and the tar oil from the condensate and which includes means for directing the crude tar through a separator for separating the heavy tar from a remaining portion of the tar and further directing the remaining portion through a supply tank and a centrifuge for removing solid matter therefrom. g croppin , A.W.J. - Inventor, U.S. Patent 4,243,101, January 6, 1981, "Coal Gasification Method." A method for underground gasification of coal is described in which a substantially uniform gasification or combustion front is maintained by filling the cavity generated by gasification of coal with a filler so as to drive said front in an upward direction through the coal layer, the gases for maintaining the gasification being introduced through a first borehole and the combustion gases being discharged through a second borehole, one of these boreholes being used for introducing the filler, said boreholcs extending at an inclination corresponding to the general inclination of the coal layer, and preferably coverging towards one another.

Kerr-McGee Chemical Corporation, A.H. Knebel - Inventor, U.S. Patent 4.248,692, February 3, 1981. "Process for the Discharge of Ash Concentrate From a Coal Deashing System." A process is described for removing an agglomerate of accumulated materials including ash concentrate which collects within the first heavy phase withdrawal conduit of a coal deashing system employing solvent at elevated temperatures and pressures near the critical temperature of the solvent. A carrier fluid is introduced into the first heavy phase withdrawal conduit simultaneously with or after pressure reduction of the heavy phase under conditions such that a turbulent flow profile is developed within the withdrawal conduit which results in the removal of at least a substantial portion of any accumulated materials within the withdrawal conduit.

Kerr-McGee Corporation, R.A. Baldwin and R.E. Davis - Inventors. U.S. Patent 4,244,812, January 13, 1981, "System for Producing a Powdery Composition Comprising Coal Products in a Deashing Process." A system for deashing coal liquefaction products is described wherein a feed mixture (including a deashing solvent, soluble coal products and insoluble coal products) is separated in a first separation zone into a first light fraction and a first heavy fraction (including insoluble coal products and some deashing solvent). The first heavy fraction is withdrawn from the first separation zone and the pressure level of the first heavy fraction is reduced at least 100 psig for vaporizing the deashing solvent and for yielding a composition substantially comprising coal products. The composition is essentially a powdery, solid material and is capable of being transferred via a slurry or mechanical means.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-101 COAL - PATENTS L. & C. Steinmuller GmbU, Ernst Schuster - Inventor, U.S. Patent 4,256.539, March 17, 1981, "Method of Generating Gas and Coke Dust By Rapid Degasification and Rapid Vaporization." A method of generating gas and coke dust by means of rapid degasifieation and rapid vaporization, with simultaneous extensive desulfurization, of coal ground into dust is described in the patent. In a first step, one portion of coal is subjected to complete or partial vaporization. In a second step, another portion of coal is subjected to degasification in the same or in associated reaction chambers. Metallgeseilsehaft Aktiengesellschaft, Alfred Garber and Paul Weisner - Inventors, U.S. Patent 4,240,808, December 23, 1980, "Processing Aqueous Effluent Liquors From Degassification or Gasification of Coal." The aqueous effluent liquors from gasification of degasifieation of coal are extracted with water-insoluble solvent and the extract is processed to recover the solvent. The aqueous residue is treated to remove N in a driving-off column. The invention adds the steps of (a) removing part of the overhead product of the driving-off columnil as uncondensed vapors; (b) transferring the vapors from (a) to a scrubbing column, in steps condensing water, small amounts of ammonia and all acid gases in the upper part of said scrubbing column, and withdrawing pure ammonia overhead; (c) withdrawing the condensate which contains all acid gases from the upper portion of the scrubbing column, transferring the condensate to a separate reboiler. and heating the transferred condensate in said reboiler; (d) feeding cold water at a low rate to the top of the scrubbing column; (e) withdrawing the sump product of the scrubbing column, transferring it into a pressurized dc-acidification column, and withdrawing therefrom overhead under pressure the acid gases 11 2S and CO9 ; and (f) recycling to the stripping column the sump product of the pressurized dc-acidification column consisting of a solJtion high in ammonia content. Mobil Oil Corporation, N.Y. Chen - Inventor, U.S. Patent 4,247,384, January 27, 1981, "Liquefaction of Carbonaceous Materials." This claims an improved method_for solubilizing solid carbonaceous materials, e.g. ,. wood, and/or coal, in an aromatic petroleum or coal-derived solvent in the presence of alkali and hydrogen transfer agent at elevated temperatures. The liquid products can be used as fuels or further processed into desirable products. Resew ch-Cottroll, Inc., Asian B. Ray - Inventor, "Process for Desulfurization of Coal." The patent describes a process in which coal is oxidized by NO in the presence of a liquid in which NO is soluble. Oxidized sulfur species are removed by washing with water and dilute sulfurie acid. NO x is not consumed in the process and is recycled More than 70 percent of sulfur in coal is removed. Rockwell International Corporation, J.E. Sinor - Inventor, U.S. Patent 4,243,509, January 6, 1981. "Coal Hydrogenation." Disclosure is made of a method and apparatus for reacting carbonaceous material such as pulverized coal with heated hydrogen to form hydrocarbon gases and liquids suitable for conversion to fuels wherein the reaction involves injection of oulverized coal entrained in a minimum amount of gas and mixing the entrained coal at ambient temperature with a separate source of heated hydrogen. The heated hydrogen and entrained coal are injected through a rocket engine type injector device. The coal particles are reacted with hydrogen in a reaction chamber downstream of the injector. The products of reaction are rapidly quenched as they exit the reaction chamber and are subsequently collected. Steag Aktiengesellschaft, Artur Richter - Inventor. U.S. Patent 4,238,200, December 9, 1980. "Process for the Production of Fuel From Fine Coal for Coal Pressure Gasification in a Fixed Bed Reactor." The patent describes a process for the production of fuel from coal for the pressure gasification of coal in a fixed bed reactor. The coal is segregated in steps into oversize and undersize fractions. The undersize fraction is mixed with sulfite liquor to form an agglomerate which is formed into pellets. The pellets are then hardened in a low temperature furnace and subsequently fed through a charging valve into the reactor, together with the oversize fraction. Steag, A.G., Wolfgang Ratzeburg - Inventor, U.S. Patent 4.239,500. December 16, 1980, "Process for the Utilization of Waste Product Tar-Dust in Gasification of Granular Fuel Under Pressure, Especially of Bituminous Coal." The patent describes a process for the utilization of tar-dust which is separated from the gases derived from gasification of granular fuel under pressure. expecially of bituminous coal. The tar-dust is separated from the gases and is fed back into the pressure gasification cycle of the fuel. The tar-dust is added as a binder in the pelletization of the of the fine grained protions of the fuel and is fed in pellet form into the generator. Apparatus for carrying out the process comprises a pressure genertor having a feed device for granular fuel, a tar-dust separator, and a pelletizing device connected by a tar- dust conveying pipe to the tar-dust separator, for the pelletizing of tine grains of fuel with tar-dust as a binder, the pelletizing device conveying the green pellets produced thereby into the feed device. The granular fuel is screened to pass only that portion below a predetermined grain size to the pelictizer, the remaining portion being fed directly to the generator.

4-102 CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 COAL - PATENTS

Texaco Inc., P.N. Woldy, H.C. Kaufman, and J.F. Beau - Inventors, U.S Patent 4,247,302, January 27, 1981. "Process for Gasification of Coal and Production of B y-Product Superheated Steam." Coal or other high ash containing carbonaceous solid fuel is reacted with a free-oxygen containing gas, with or without a temperature moderator, in a down-flow partial oxidation gas generator to produce a stream of raw synthesis gas, fuel gas, or reducing gas. A large portion of the combustion residue, i.e., molten slag and/or particulate solids that is entrained in the down-flowing generated gas stream is removed by gravity when the gas stream is passed through a diversion chamber. The main gas stream leaving the diversion chamber through the side outlet passes upward through a solids separation zone, optionally including gas-gas quench cooling, cyclones, filters, impingement separators, or combinations thereof. Next, most of the sensible heat in the gas stream is recovered by indirect heat exchange with boiler feed water and steam. Saturated and superheated steam are produced. In the main gas cooling zone, the hot gas stream with a substantially reduced solids content is passed serially through the tubes of two or more communicating shell-and-straight fire tube gas coolers. Saturated steam, which is produced in one. or more of said gas coolers, is superheated in another of said gas coolers. The U.S.A. as represented by the DOE. R.T. Yang - Inventor, U.S. Patent 4,250,015, February 10, 1981, "Mechanochemical H ydrogenation of Coal." Hydrogenation of coal is improved through the use of a mechanical force to reduce the size of the particulate coal simultaneously with the introduction of gaseous hydrogen, or other hydrogen donor composition. Such hydrogen in the presence of elemental tin during this one-step size reduction-hydrogenation further improves the yield of the liquid hydrocarbon product.

CAMERON SYNTHETIC FUELS REPORT, JUNE 1981 4-103 LJjp lip) erkll1 APPENDIX

Extensions to Diligent Development Requirement for Federal Coal Leases ...... 5-I EXTENSIONS TO DILIGENT DEVELOPMENT REQUIREMENT FOR FEDERAL COAL LEASES

(ISSUED BY THE DEPARTMENT OF THE INTERIOR ON JANUARY 6, 1981)

I. Extension Under Specific Provisions of 43 CFR 3475.4(b)(2)

a. Extension to Allow Development of Advanced technology (43 CFR 3475.4(b) (2) (i)

Proof of the lessee's substantial legal and financial commitment to build, underwrite, or otherwise participate in a project involving coal from the lease and directly utilizing coal-based technologies (including processes that may have been in existence for some time but have yet to achieve mature commercial development), or evidence that the coal will be utilized by such a facility, will be required. "Advanced technologies" would normally be directly related to production of coal-based synfuela. This requirement allows time needed to develop projects such as coal gasification or liquefaction that are dependent on federally-leased coal. In the case of sale of the coal to be used in such a project off-site, the applicant for an extension to the diligent development period would need to provide evidence such as a contract tying the leased coal to its use in such a facility. other types of advanced technology relating to mining or coal transport would also be considered.

b. Magnitude of Project (43 CFR 3475.4(b)(2)(ii))

A mine plan deemed complete by OSM (this occurs 9 to 12 months before plan approval) would be required, substantiating that production from the LMU of which the candidate lease is a part would reach commercial quantities between June 1, 1986 (or other appropriate date if the lease had been suspended or an extension under 43 CFR 3475.4(b)(I) had previously been granted), and June 1, 1991. On leases for which mine plan completeness determinations have not been made by OSM, the lessee could optionally submit evidence attesting to e substantial commitment in on-the- ground development, such as equipment orders. Since the regulations state that magnitude of the project "ordinarily" means S million tons per year if a surface nine and 2 million tons per year for an underground mine, some discretion would be permissible for mines whose production might fall slightly below these levels in the first year of full production after the end of the extended term.

c. Firm Commitment to Sell or Use 2 1/2 Percent of LMU Reserves (43 CFR 3475.4(b)(2)(iii))

To qualify for an extension under this subpart, the lessee must submit to the Department a contract for the sale or use of 2 1/2 percent of the LMU reserves for delivery prior to the end of the extended period for diligent development. The contract must be an arm's length agreement signed by both parties and binding on both parties. As the terms "arm's length" and, to a lesser degree, "binding on both parties," are not applicable to coal "use' contracts between a coal company or utility and a subsidiary,

5-1 typically in a captive nine situation, the extension applicant would be required to document how the leased coal is committed to a specific project to the satisfaction of the Department. Evidence of such commitment might be equipment orders or contracts to transport the coal.

Although the regulations require a firm commitment for the sale or use of 2 1/2 percent of the LMU reserves, the holder of a small Federal coal reserve could elect not to include his lease within a much larger LMU, thus lessening considerably the number of tons needed to fulfill the contractual requirement. If the lessee, subsequent to receiving an extension, applied for and received approval to form an tMU, he would, however, be required to produce commercial quantities amounting to 2 1/2 percent of the LMU reserves before the end of the extended term. (The proposed coal operating regulations (30 CFR Part 211) would require that the end of the ID lease year period on an LMU consisting of pre- and post-FCLAA leases be tied to the date at which commercial quantities must be produced from the pre-FCLAA lease(s) in the LMU.)

2. Extension for Full 5 Year Term

Any application approved by the Secretary to extend the diligence requirement on a Federal coal lease beyond June I, 1986, shall be for 5 years. As a condition of granting an extension, 2 years before expiration of the extended term, the lessee must have constructed on the LMtJ a mine capable of producing the appropriate commercial quantities of coal by the end of the extended term. Although extensions will normally begin after June 1, 1986, the 5 year clock could start later if the lease had been suspended, or the diligent development period had been extended under section 43 CFR 3475.4(b)(I). Comments from industry strongly urged the Secretary to recognize uncertainties and risks in coal development by awarding 5 years in all cases. Such a decision also would lessen the administrative burden on the Department to decide what portion of the permissible 5 years should be granted. Clearly, the drawback to this policy is that it would allow a number of mines time beyond that which is truly needed to achieve diligent development. Given the fact that only one extension is permitted, however, the granting of a full S year term remains preferable.

3. Application Deadline

A persuasive case can be made to require that applications for diligence extensions be submitted a year before the end of the 10 lease-year period or June I, 1985. With a potential for up to 440 Federal coal leases needing for an extension, the Department must allow itself sufficient administrative time to act in a timely manner. If the processing period extends beyond June 1, 1986, the Department would automatically offer an extension under 43 CFR 3475.4(b)(1) to applicants who had submitted requests by June 1, 1985, to cover that period of time. The June I, 1985, deadline could be waived in cases of extraordinary or unusual circumstances.

4. Lease Acquisition Costs

Expenditures for Federal coal lease acquisition will not provide sufficient reason in and of themselves for granting an extension. The exclusion of lease acquisition costs reflects the view that these expenditures do not directly enhance coal development and may be entirely speculative in nature. Many commenters from the coal industry argued, however, that when such costs are considerable--as they have been for recent lease transfer agreements in the Powder River coal region--the lessee has a vested interest in developing the property. We would agree that the new owner or

5-2 assignee has an incentive to develop the lease, but stress that the kinds of investment most directly applicable to making coal available are commitments to on-the-ground capital construction and mine development costs after lands for a mining unit have been purchased.

5. Transfer of Extensions

Extensions will not automatically transfer with the lease at assignment. In line with the settlement reached with Mobil Oil Corporation on April 23, 1980, the transferor would have to have committed substantial expenditures (such as one-third of the total mine development costs) in order for the extended term to be transferable. Although mine development costs would normally accrue only after the mine plan has received final approval, payment for equipment purchases or orders preceding plan approval may be accepted in the discretionary judgment of the District Mining Supervisor, USGS, if such purchases or orders are for equipment clearly intended for use in developing the mine. Also, the transferee may utilize the transferors quali- fications (such as a coal sales contract) to the extent the transferee acquires them as a condition of lease assignment.

While not restricting assignments, this requirement ensures that the Secretary grant extensions only to lessees with a good faith intent to develop and market Federal coal on the candidate lease, and that subsequent assignments require a commitment that the assignee also qualify for the extension. This option in no way retricts assignment of the lease prior to the extension period beyond the existing strictures in the regulations.

6. Environmental Review

Compliance with the National Environmental Policy Act (NEPA) will require the Secretary to consider the environmental implications of issuing an extension. Ordinarily, the Department addresses NEPA compliance for leases issued before August 4, 1976, through an environmental assessment or impact statement on the mine plan. In the case of diligent development extensions, submission of an approved mine plan will satisfy the environmental review requirement. For lessees that wish to apply for an extension, but have no approved mine plan. ELM would determine whether development of the lease would conflict with the unsuitability determinations in an existing land use plan for the area. No extension would be approved, unless an exemption or exception applied, for lands found unsuitable.

If the unsuitability criteria have not been applied to the lease in question, the applicant would provide ELM with all necessary data to screen the lands for unsuitability under 43 CFR 3461. Final approval of the extension would be granted only for lands not in conflict with the unsuitability criteria after exemptions or exceptions have been applied.

7. Authority to Grant Extension

Review and adjudication of applications for extensions to the diligent development period for Federal coal leases logically requires the input of the Geological survey and the land management agency (ELM and/or FS). The CS, through the Office of the District Mining Supervisor, is in the best position to rule on the technical merits of an extension application as regards the timing to produce commercial quantities of coal, magnitude of mining project, dedication of coal to a project utilizing advanced technology, extent of

* As stated by 43 CFR 3461.3-I(b)(1), submission of data to support the alluvial valley floor determination in criterion 19 may be waived at this stage.

5-3 financial commitment to develop the mine, and validity of contracts to sell or use the coal under lease. the ELM can best judge the land use and environmental implications in awarding an extension insofar as approval would lead to development on the lease.

Authority to grant extensions could be delegated to the Assistant Secretarial or Bureau level, but we recommend that the Secretary postpone a decision on this issue to evaluate the number of applications likely to be filed and the controversy surrounding the determination of their validity. Applications should be filed initially with the appropriate CS District Mining Supervisor, with copies to ELM and the Office of the Secretary. The filing requirement is consistent with the proposed 30 CFR 211 regulations. Recommendations from CS and BLM will be sent concurrently to the Secretary for approval or rejection of the application.

S. Failure to Obtain a Market for Coal Under Lease

No extension to the diligent development period will be awarded because of a failure to find a market or financing for the coal under lease. This conclusion derives from language in 43 CFR 3475.4(b)(1) of the coal management regulations, ruling out an extension for "inability to obtain sufficient sales' under that section. - - -

Many industry commenters urged that the Secretary's extension policy recognize problems in marketing coal. A 'soft" market is thought to exist now for western coal, and it was argued that by ignoring this reality not enough leases would qualify for an extension beyond 1986 to provide a base for needed coal production in the 1990's. It should be kept in mind, however, that the intent of Congress was expressly to prevent companies from holding Federal coal leases speculatively while waiting for prices to rise or coal markets to develop. Furthermore, a vast majority of pre-FCLAA leases will have enjoyed a period of 15 or more years in which to produce 2 1/2 percent of the lease reserves by the June 1, 1986, deadline for diligent development, or 20 years by the end of the extended term (1991) if given an extension.

9. Small Business Exemptions

The Federal coal management regulations as currently written favor large companies in the award of extensions to the diligent development period. Subparts 3475.4(b)(2)(i) (advanced technology), and 3475.4(b) (2) (ii) (magnitude of project), clearly would not help a small spot-market operator with modest Federal coal reserves who needs more time beyond June 1, 1986, to produce commercial quantities of coal. Small coal companies that have the flexibility to operate and sell coal on the spot market would not qualify for an extension under subpart 3475.4(b) (2) (iii) (possession of long-term delivery contracts) since they seldom--if ever--enter into long-term contractual agreements. To permit small businesses the same opportunity in seeking extensions would require new rulemaking. The Secretary should explore the subject of new rules with the Secretary, Department of Energy, who has the regulatory authority on diligent development. Of the 311 Federal coal leases without submitted nine plans. 39 appear to belong to interests or individuals that may qualify as small businesses.

5-4 United States Department of the Interior

OFFICE OF THE SECRETARY WASHINGTON D.C. 20240

January 6, 1981

MEMORANDUM

To: Secretary Solicitor Assistant Secretaries Secretary's Immediate Office

From: Under Secretary .o._,r..-.) & -

Subject: Extensions to Diligent Development Requirement for Federal Coal Leases

I have reviewed the Secretarial issue Document on extensions to the diligent development requirement for Federal coal leases issued prior to the enactment of the Federal Coal Leasing Amendments Act of 1976, and public comments submitted pursuant to the February 1, 1980, Federal Register notice (45 Fed. Reg. 7318-7319), and have reached the following decisions:

I have concurred in the preferred approach (Options 1.3. II. l.a.-c., and 11.2. through 9.) with the following changes and comments:

Under Option II.l.a. concerning the advanced technology extension provision of 43 CFR 3475.4(b)(2), technology other than synthetic fuels technology may be considered, including experimental technology for coal mining or transportation (e.g. slurry pipelines which do not employ water as the slurry medium). In Option 11.2. • the mid-extension review should determine whether the lessee has accomplished those actions necessary at the review time to achieve the appropriate level of production by the end of the extension period. In order to encourage lessees to apply for extensions early and to alleviate pressure on field personnel from lessees demanding immediate attention to their particular applications, the application deadline policy (Option 11.3) should include the additional direction that all applications shall be processed in the order they are received.

Finally, options II 6. and 11.7. must be altered to reflect the following guidance.

(I) All extension applications on which action will be taken prior to initiation of the mine plan approval process will be reviewed and acted on under this extension policy, but the extension will stipulate that the grant of the extension is conditioned on approval of the mine plan for the lease. By this stipulation, environmental review of the mine plan will in addition function as environmental review of the extension application. If the mine plan is then approved, that condition on the prior grant of the extension will be satisfied.

(2) 1 will defer the decision on application of the unsuitability criteria to areas covered by leases for which extensions have been requested but mine permit applications have not been processed. I will reconsider this decision when the report on the current experience with the unsuitability criteria, now under preparation in the Department, is completed. It is my understanding that the report will address a full range of issues involving application of the criteria to existing leases, and is therefore, the more appropriate vehicle for consideration of this one issue of application of those criteria in one circumstance to a single class of existing leases.

5,5