PACE Synthetic Fuels Report V. 23 No. 3

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VOLUME 23 - NUMBER 3 - SEPTEMBER 1986

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®THE PACE CONSULTANTS INC.

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

THE PACE CONSULTANTS INC. SYNTHETIC FUELS ANALYSIS

Project Manager Ronald L. Gist

Contributing Consultants Todd M. Coady Connie M. Gianikas Linda J. Loop Jerry E. Sinor

Washington Associate Rip G. Rice Production Staff Jeannette G. Stone Timothy R. Wolf Jackie A. Robinson Mary H. Stuart

Post Office Box 53473 Houston, Texas 77052 713/669-8800 Telex: 77-4350 CONTENTS

HIGHLIGHTS A-i

I. GENERAL

CORPORATIONS

Decline in Synthetic Fuels Interest Apparent in Annual Reports 1- 1 GOVERNMENT

DOE Selects Projects and Solicits R&D Proposals from Small Businesses 1- 9 DOE Reorganizes to Administer Clean Coal Program i_la ENERGY POLICY AND FORECASTS

Pace Finds Synfuels Future Holds Promise, But Improvements Needed 1-13 Chevron Forecasts Adequate Energy Through 2000 1-21 ECONOMICS

Sygmal Process is Attractive for Production of Cosolvent Alcohols from Syngas 1-26 TECHNOLOGY

Co-Processing Studied for Upgrading Low Grade Feedstocks 1-30 INTERNATIONAL

New Zealand Synthetic Gasoline Plant Started Up, But Economics Questionable 1-33 Australia Discounts Synfuels Until Well After 2000 1-35 Canadian Energy R&D Activities Outlined 1-39 United States and Spain Sign Energy R&D Agreement 1-41 ENVIRONMENT

EPA Approves Utah's Visibility Protection Plan 1-42 RECENT GENERAL PUBLICATIONS/PATENTS 1-44 COMING EVENTS 1-45 II. OIL SHALE

PROJECT ACTIVITIES

Unocal Makes Progress on Start-Up--But Faces Lawsuit 2- 1 Research Continues on Julia Creek Shale Oil Project 2- 1 Rundle Project Sees 1,000 Hour Run in Exxon Pilot Plant 2- 3

n CORPORATIONS Central Pacific Minerals and Southern Pacific Petroleum Detail Oil Shale Activities 2- 5 Gary Refining Company Emerges from Chapter 11 Bankruptcy 2- 7 GOVERNMENT Workshop Held on Oil Shale Test Center—DOE Report Due 2- 8 ECONOMICS Favorable Conditions Notes for Australia Shale Oil 2- 9 TECHNOLOGY lOT Patents Free Fall Retorting Process 2-12 Solvent Dedusting of Shale Oil Developed by Amoco 2-13 Difficulties of Arsenic Management in Shale Oil Refining Revealed 2-15 Texaco Patents Borehole Reaming Method for Radio Frequency Extraction 2-17 Oil Shale Combustor Model Developed by Greek Researchers 2-18 Full Scale Blast Measurements Reveal No Dust Hazards 2-20 INTERNATIONAL Taciuk Processor Proposed for Australia Oil Shale 2-25 Energy Efficiency Analysis Carried Out for Petrosix Process 2-26 Fluidized Bed Combustion Tested for Turkish Oil Shales 2-28 Canada Oil Shale Potential Limited to New Brunswick 2-29 ENVIRONMENT EIS Issued for Unocal Phase II Expansion 2-31 Spent Shale Proves Effective Absorbent for Sulfur Emissions 2-37 Los Alamos Characterizes Oil Shale Industry Hazards 2-42 Toxicity of Shale-Derived Diesel Fuel Judged Similar to Petroleum 2-46 WATER Water Application Related to Oil Shale Listed 2-48 RESOURCE Interior Agrees to Settle Oil Shale Claims—Strong Reaction Results 2-49 Kansas Oil Shale Potential Evaluated 2-50 RECENT OIL SHALE PUBLICATIONS/PATENTS 2-52 STATUS OF OIL SHALE PROJECTS 2-58

III. OIL SANDS

PROJECT ACTIVITIES ERCB Conditionally Approves Phases 7-10 of the Ease Cold Lake Project 3- 1 PanCanadian's Lindbergh Steam Project May Continue on Reduced Schedule 3_ 4 Dome Petroleum Puts Lindbergh and Primrose Projects on Hold 3- 4 Devran/Shell Project Receives Government Aid 3- 5 New Tech Oil Reports Favorable Progress with Oil Mining Project 3- 6 Phase 2 Design of Wolf Lake Set at 13,000 BPD 3- 6 Suncor Achieves New Monthly Production Records 3- 7 ERCB Publishes Statistical History of Oil Sands Production 3- 7 Diatomaceous Earth Project Put on Standby by Texaco 3 7 CORPORATIONS

Universal Energy/OHS Corporation Test Electromagnetic Stimulation 3_ 9 GOVERNMENT -

Bauer Likens $10 Oil to Trojan Horse for Enhanced Oil Recovery 3-10 Increased Alberta Bitumen Production Results in Prorationing of Light Oil Production 3-11 ENERGY POLICY & FORECASTS

Canadian Oil Market Review Shows Growing Influence of Heavy Oil and Bitumen 3-13 ECONOMICS

Economics of Beaver-Herter Extraction Process Revealed 3-16 RTR DAP Process Exhibits Low Operating Costs 3-18 TECHNOLOGY

Air Force Program Tests Production of Aviation Turbine Fuels from Utah and Kentucky Bitumens 3-21 Hydrogen from UCG Proposed for Heavy Oil and Tar Sands Extraction 3-24 Alabama Tar Sands Upgraded by Physical Beneficiation 3-26 Synthetic Crude Oil Processing Residues Used in Asphalt Blends 3-30 INTERNATIONAL

Startup Due for Multi-National Gulf DRB Demonstration 3_34 ENVIRONMENT

Fish and Wildlife to Determine Endangered Status of San Rafael Cactus 3-36 WATER

Water Quality in Alberta Oil Sands Area Noted 3_37 Industry Use of Saline Water Not Expected in Tar Sand Triangle 3_39 RESOURCE

Complexity of Sunnyside Tar Sands May Inhibit Recovery 3-40 ERCB Updates Estimated Reserves of Crude Bitumen and Synthetic Crude Oil 3-42 RECENT OIL SANDS PUBLICATIONS/PATENTS 3-45 STATUS OF OIL SANDS PROJECTS 349

IV. COAL

PROJECT ACTIVITIES

DOE Receives Title to Great Plains Plant 4- 1 Rocky Mountain I Test to Evaluate CRIP Technology 4- 3 Pyrolysis Demonstration Unit Started Up by United Coal 4- 4

II' CORPORATIONS GRI Describes 1987-1991 R&D Plan and 1987 Program 4- 7 GOVERNMENT Nine Clean Coal Projects Chosen by DOE 4-10 Ohio Makes Awards to 24 Clean Coal Projects 4-15 DOE Submits Clean Coal Report to Congress 4-17 ENERGY POLICY & FORECASTS Utilities Enthusiastic About Coal Gasification Technology 4-19 ECONOMICS UCG Economics Affected by Gas Quality 4-21 Steam-injected Gas Turbines Uneconomical with Coal Gasification Equipment 4-22 TECHNOLOGY KEW Pilot Plant Successfully Demonstrates In-Bed Desulfurization 4-24 High Quality Liquids Produced by Mild Pyrolysis of Coal-Lime Mixtures 4-27 New UCG Method for Large Blocks at Great Depths Proposed 4-30 TIGAS Process Converts Coal to Gasoline In One Synthesis Loop 4-35 INTERNATIONAL PYROSOL Process Offers Attractive Two-Stage Liquefaction Options 4-40 KOHLEOL Process May Favor High Operating Pressure 4-42 DOE and Japan Sign Coal Research Agreement 443 Joint Research Agreement Signed by British Gas and Osaka Gas Company 4-44 Erection of Gasifier in Poland to Begin in 1987 444 ENVIRONMENT Experimental Studies on Toxicity of Coal Liquids and Petroleum Products Completed 4-45 RESOURCE Charter Proposed for Fort Union Regional Coal Team 4-46 Alabama Sub-Region May be Decertified as Federal Coal Leasing Area 4-46

DOE Assists in Meeting Social Impacts of Great Plains Plant 4-48 RECENT COAL PUBLICATIONS/PATENTS 4-49 STATUS OF COAL PROJECTS 455

V. APPENDIX

Description of Clean Coal Projects Proposed to DOE s- 1

IV HIGHLIGHTS Capsule Summaries of the More Significant Articles in this Issue

Six Synfuels-Related Projects Selected for SBIR Awards The United States Department of Energy (DOE) has selected six synfuels- related projects described on page 1-9 for funding in the Small Business Innovation Research (SBIR) program. DOE has also solicited proposals for new projects in its FY1987 program. Pace Finds that Synfuels Have a Future in the United States Due to the recent dramatic decline in the interest in synthetic fuels, Pace has analyzed the events of the past 15 years to assess the future of the industry in the United States. Commercial projects that were assisted by the United States Synthetic Fuels Corporation received price supports of $40 to $60 per barrel. Pace forecasts that the price of crude oil is not expected to again reach these levels until 2000. However, potential improvements listed on page 1-13 could reduce synthetic fuels production costs to $25 to $35 per barrel. Experience with large scale plants, possibly located in other countries, is needed to achieve these cost savings. Chevron Forecasts Adequate Energy Supplies Through 2000 The article on page 1-21 summarizes Chevron's forecast of worldwide energy supply/demand to 2000. Chevron estimates that there will be sufficient supplies of conventional crude oil and natural gas liquids to meet world demand through 2000.

Sygmal Process may be Attractive for Mixed Alcohols Production The Sygmal (Syngas to Mixed Alcohols) Process has been developed by the Dow Chemical Company and Union Carbide. A recent study by Fluor indicates that the process may be economically attractive for retrofitting an existing methanol plant to produce mixed alcohols for use as an automotive fuel. See page 1-26. LCI Co-Processing Tested for Coal, Shale, and Biomass Lummus Crest Inc. (LCI) has tested its two-stage co-processing technology on several types of low-grade feedstocks. Results of tests using bituminous coal, Kentucky oil shale, wood chips, and municipal solid wastes are sumarized on page 1-30. New Zealand Synthetic Gasoline Plant Started Up The natural gas-to-gasoline plant located at Motunui, New Zealand was completed in June 1985, ahead of schedule and 17 percent under budget. Although the plant successfully started up in October 1985, the economics of the plant have been debated in New Zealand. See page 1-33.

A-1 Australia Discounts Near-Term Viability of Synfuels The Australia Department of Resources & Energy recently conducted an analysis of the country's energy future until 2000. As described in the article on page 1-35, the Department concluded that synthetic fuels will not be cost competitive until well after 2000. However, the government will continue support of research and development projects that may reduce costs. Canadian Efforts at Energy R&D Described The Canadian federal government's inter-departmental Panel on Energy Research and Development coordinates efforts aimed at oil self-sufficiency, energy diversity, and reduced dependance on non-renewable resources. A description of its $96 million annual program begins on page 1-39. United States and Spain to Cooperate in Energy R&D In June the United States and Spain signed a Memorandum of Understanding to mutually conduct energy research and development programs. As described on page 1-41, the initial agreement covers coal gasification and geothermal technologies, but may be expanded to other fields of mutual interest at a later date.

Unocal Makes Progress on Startup But Faces Lawsuit Unocal's Parachute Creek oil shale facility successfully completed a 6 day run in July at about one-half design capacity (page 2-1). Meanwhile a lawsuit has been filed by several members of Congress challenging the loan guarantee awarded to Unocal by the United States Synthetic Fuels Corporation before it went out of business. Research Continues on Julia Creek Shale Oil Project CSR Limited and the CSIRO Division of Mineral Engineering in Australia have been developing a retorting process for the Julia Creek oil shale deposit. Project status, discussed on page 2-1, has reached the point where a small pilot plant should be the next phase of work. Rundle Project Progress Includes 1,000-Hour Run in Exxon Pilot Plant Progress of the Rundle Shale Oil Project under the new Joint Venture Agreement of 1985 is reviewed on page 2-3. Key activities have included a 1,000-hour run on Rundle shale in Exxon's S ton per day pilot plant in Baytown, Texas.

CPM/SPP Annual Report Details Oil Shale Activities Highlights of the 1985 Annual Report (issued May 1986) for Central Pacific Minerals N.L; and Southern Pacific Petroleum N.L. are found starting on page 2-5. The companies continue to be active in oil shale projects in Australia, the United States, Luxembourg, France, and the Federal Republic of Germany.

A-2 Workshop Held on Oil Shale Test Center—DOE Report Due On June 26 the Associated Governments of Northwest Colorado sponsored a workshop in Meeker on the subject of a western oil shale R&D center. A report on the workshop is given on page 2-8. It was intended to influence an upcoming United States Department of Energy report on the feasibility of a "generic" oil shale R&D facility. Favorable Conditions Noted for Australia Oil Shale Cost data for several Australian shale oil projects were updated to 1985 conditions by CPP/SPM. Results, found on page 2-9, suggest that Australian oil shale deposits can economically replace any new oil which is likely to be found within Australia. lOT Patents Free Fall Retorting Process A 1986 patent assigned to the Institute of Gas Technology reveals a method of retorting oil shale by allowing fine particles to free fall counter-current to a hot gas stream. Advantages of the method, outlined on page 2-12, include extremely rapid heatup rates and the ability to select conditions for either liquid or gaseous products. Amoco Develops Solvent Dedusting Process for Shale Oil A new pthcess developed by Amoco for Rio Blanco Oil Shale Company uses a 2-phase mixture of shale oil with an alkane and an alcohol to achieve a rapid separation of dust from the shale oil. This method of overcoming a key shale oil processing difficulty is explained on page 2-13. Full Scale Blast Measurements Reveal No Hazards In 1985, the United States Bureau of Mines instrumented three full-scale blasts at two oil shale mines in Colorado. Detailed measurements of the oil shale dust concentration during the blasts showed that the concentration of dust was an order of magnitude below the lean limit for explosions of fine oil shale dust. See page 2-20 for details. Taciuk Processor Proposed for Australia Oil Shale The Taciuk Processor, which has been under development for processing Athabasca oil sands, has been proposed for retorting oil shale. Some very preliminary results on retorting United States and Australia oil shales are quoted on page 2-25. Energy Efficiency Analysis Carried Out for Petrosix Process A second law of thermodynamics lost work analysis has been carried out for the Petrosix retort. Results, summarized on page 2-26, point the way to a fine- tuning of the retort heat balance for greater efficiency. Canada Oil Shale Potential Limited to New Brunswick A recent review of Canadian oil shale deposits confirms that the Albert Mines deposit in New Brunswick is the only one having near-term development

A-3 potential. As noted on page 2-29, the others are too thin, too low grade, or too environmentally sensitive to provide a reasonable development target. EIS Issued for Unocal Phase U Expansion The United States Army Corps of Engineers has issued the draft Environmental Impact Statement for the proposed Phase II expansion of Unocal's Parachute Creek Shale Oil Project. Although the demise of the Synthetic Fuels Corpora- tion and other factors have made it impossible to proceed with the project, the EIS will be available when conditions change in the future. An overview of the proposed action and estimated impacts begins on page 2-31. Spent Shale Proves Effective Absorbent for Sulfur Emissions The absorption of sulfur oxides on combusted oil shale has been tested by 3 & A Associates in a 6 ton per day pilot plant. After burning the carbonaceous residue on spent shale in a fluidized bed combustor, the level of sulfur oxides in the flue gas was found to be very small (page 2-37). This result indicates an appreciable cost savings for emission control if a combustion stage is utilized. Los Alamos Characterizes Oil Shale Industry Hazards Los Alamos National Laboratory has issued a report "Health Hazard Evaluation and Recommended Industrial Hygiene Practices for Aboveground Oil Shale Processing." An extensive abstract, starting on page 2-42, outlines their findings and recommendations. Interior Agrees to Oil Shale Claims—Provokes Public Reaction In a settlement announced August 4, the United States Department of the Interior agreed to abide by a District Court ruling of last year and issue titles to 82,000 acres of oil shale lands in Colorado to Exxon, Tosco, Unocal, and others. The announcement caused a storm of protest in public and Congress over the "giveaway" of public lands. A summary of the agreement is presented on page 2-49. ERCB Approves Esso's Cold Lake Phases 7 - 10 The Alberta Energy Resources Conservation Board approved Esso's development plans for Phases 7 through 10 of its Cold Lake in situ oil sands project. The decision, summarized on page 3-1, requires Esso to begin development of the expansion phases by the end of 1989 or the approval will expire. Dome Petroleum Puts Two Oil Sands Projects on Hold As summarized on page 3-4, Dome Petroleum Limited has put its Lindbergh Commercial Project and its Primrose Lake Project on hold. Dome attributed their decision to the dramatic decline in oil prices that has occurred since the beginning of the year. Both projects may be re-activated when oil prices recover. PanCanadian's Lindbergh Project May Continue on Reduced Schedule PanCanadian Petroleum Ltd. applied early this year for a 3-phase commercial bitumen recovery project in the Elk Point, Frog Lake area of the Lindbergh

A-4 field in Alberta. Details of the project, which is expected to continue in spite of the oil price drop, are outlined on page 3-4. Devran/SheIl Project Receives Government Aid Devran Petroleum Ltd. and Shell Canada Limited are proceeding with a $6.3 million mining assisted oil recovery project in Ontario, Canada. An update on the project history and status is given on page 3-5. Favorable Progress Reported With Oil Mining Project New Tech Oil Company of Kaycee, Wyoming reports that lower drilling costs achieved at its North Tisdale mining assisted oil recovery project should make it possible to develop new reserves for as little as $2 per barrel. An update on the North Tisdale project is given on page 3-6. Universal Energy (ORS Corporation) Tests Electromagnetic Stimulation Universal Energy Corporation, now Oil Recovery Systems Corporation, is field testing an electromagnetic stimulation technique for heavy oil production. As described on page 3-9, tests are underway in Texas, Oklahoma, and Alberta, with other tests planned in Canada, Brazil, and California. Lifting costs using the technology could be as low as $3 per barrel. Bauer Likens $10 Oil to Trojan Horse Remarks by D. L. Bauer, Acting Assistant Secretary for Fossil Energy, United States Department of Energy at an EOR conference focused on the need for continued technology development in enhanced oil recovery. An extract of his remarks on page 3-10 emphasizes that the United States must not be lured by the Trojan horse of low oil prices into abandoning EOR development efforts. Increased Alberta Bitumen Production Causes Light Oil Prorationing. Total oil production in Alberta, Canada is being limited by pipeline capacity. Because bitumen production is given priority in the pipeline system, in April 1986, 164,000 barrels per day of conventional light oil production was shut in under the prorationing plan. This plan is explained on page 3-11. Canadian Oil Market Shows Growing Influence of Heavy Oil and Bitumen The 1985 Canadian oil market, summarized on page 3-13, shows an increasing dependence on heavy, crude oil. Heavy crude oil producibility rose almost 18 percent in 1985. Economics of Beaver-Herter Extraction Process Revealed Diversified Petroleum Recovery, Inc. hopes to build a 700 ton per thy demonstration plant to extract bitumen from tar sands in southern Oklahoma. A description of the process and its economics, page 3-16, suggests that a world oil price of $20 per barrel would create marginally profitable conditions for the process.

A-S RTR DAP Process Exhibits Low Operating Costs The DAP oil sands extraction process developed by RTR S.A. and described on page 3-18 has been demonstrated in a 1 ton per day pilot. According to RTR, the operating costs, exclusive of mining costs and of capital recovery costs would be $2.69 per barrel. Air Force Tests Production of Aviation Fuels from Utah and Kentucky Bitumens Work sponsored by Wright-Patterson Air Force Base has been carried out by Ashland Petroleum and Sun Oil to produce specification jet fuels from Kentucky and Utah bitumens. A summary of the work is presented on page 3-21. Although most specifications were met, the freeze point was not met with fuel produced from Utah bitumen. Hydrogen from UCG Proposed for Tar Sands Extraction A multi-resource extraction scheme has been proposed for areas where coal occurs in conjunction with heavy oil or tar sands. In this scheme, described on page 3-24, gases from the underground gasification of coal are injected into a hydrocarbon reservoir, providing thermal, solubility, and chemical reaction effects to increase oil producibility. Startup Due for Multi-National Gulf DRB Demonstration A 450 barrels per day demonstration plant for the Gulf Donor Refined Bitumen process on Athabasca bitumen is due to start up near Lyon, France. A description of the process and the project begin on page 3-34. Water Quality in Alberta Oil Sands Area Noted A report from Alberta Environment summarizes water quality constituents in the Athabasca River drainage area. A brief abstract of the report (page 3-37) notes a major conclusion that elevated levels of nickel and vanadium in surface waters are associated with the erosion of bitumen deposits in the river bank and valley wall rather than with industrial effluents. Complexity of Sunnyside Tar Sands May Inhibit Recovery A study of bitumen-bearing sandstones from Sunnyside, Utah by the United States Geological Survey has revealed a complexity of mineralogy which may create problems for either above ground or in situ extraction processes (see page 3-40). DOE Receives Title to Great Plain Plant At a foreclosure sale on June 30, 1986 DOE was the only bidder for the Great Plains coal gasification plant. DOE received title to the plant on July 14, 1986. Recent operating experience, and possible future modifications that were proposed by nine companies interested in acquiring the plant are described on page 4-1.

A-6 Rocky Mountain 1 Test to Evaluate CRIP Technology The Rocky Mountain 1 test project described on page 4-3 has been initiated by DOE and a four-member industry consortium. Two underground coal gasification techniques will be evaluated—"conventional" UCG using vertical injection wells, and the Controlled Retracting Injection Point (CRIP) method. The test near Hanna, Wyoming will begin in late summer 1987 and last 100 days. Pyrolysis Demonstration Unit Started Up By United Coal United Coal Company has started up a 1 ton per day pyrolysis demonstration unit in Bristol, Virginia. Details of the unit operation, which UCC terms "mild gasification," are summarized on page 4-4. Nine Clean Coal Projects Selected by DOE The DOE has selected nine projects to be funded by the Clean Coal Technology Program. If negotiations with the participants are successful, DOE will provide $360 million and the participants will provide $600 million. The nine projects are described in the article beginning on page 4-10. Also as part of the Clean Coal program, DOE submitted a report to Congress describing all 51 proposals that were received. DOE's analyses of the proposed technologies are summarized on page 4-17. Ohio Makes Awards to 24 Clean Coal Projects In September, the Ohio Coal Development Office announced awards totalling $41.6 million to 8 demonstration projects and 16 research projects. These 24 projects and the proposed awards are summarized on page 4-15. UCG Economics Affected by Gas Quality Energy International Inc. has studied the economics of underground coal gasification for a Wyoming location. They find that deteriorating gas quality during a module lifetime may make it more economical to abandon the module at a certain point rather than strive for total resource recovery (page 4-21). STIG Turbines Found Uneconomical for Slagging Lurgi System A study described on page 4-22 evaluated a steam-injected gas turbine (STIG) for use with a slagging Lurgi coal gasifier in an integrated gasification combined cycle system. The STIG was found to offer no economic incentive over conventional gas turbines when used with a slagging Lurgi gasifier. KRW Gasifier Successfully Tests In-Bed Desulfurization The concept of using limestone or dolomite in the bed of a gasifier to absorb sulfur compounds liberated from the coal has been tested in the KRW pilot gasifier at Waltz Mill, Pennsylvania. Results summarized on page 4-24 indicate steady state desulfurization of approximately 90 percent can be achieved.

A-? Mild Gasification with Limestone Produces Good Quality Liquids Tests conducted by DOE indicate that good quality liquids can be produced from coal by mild gasification (pyrolysis) in the presence of limestone. As summarized on page 4-27, smaller quantities of liquids are obtained in this "skimming" process that produces higher value liquids and char.

New UCO Method for Large Blocks at Great Depths Proposed A new method for the underground gasification of large blocks of coal at great depths has been proposed. The method, described in some detail starting on page 4-30, uses the CRIP technique to outline a large underground block, which is then completely consumed in a reverse combustion mode.

Pyrosol Process Offers Attractive Coal Liquefaction Option Gf K Gesellschaft fur Kohleverflussigung mbH of West Germany is developing the PYROSOL two-stage coal liquefaction process. The process, briefly described on page 4-40, can be used in the coal-only mode and in a coal/oil coprocessing mode. Less severe operating conditions and a direct-contact coal slurry heating scheme give the process some unique capabilities. KOHLEOL Process May Favor High Pressure Conditions Researchers at Bergbau-Forschung GmbH have been studying the effects of operating conditions on their direct liquefaction technology, the KOHLEOL process. The effects of catalysts and pressures are summarized on page 4-42. From these test results, the researchers concluded that efforts to lower the operating pressure of the process are not warranted.

Joint Research Agreement Signed by British Gas and Osaka Gas The British Gas Corporation and the Osaka Gas Company Ltd. have signed a joint research agreement. As described on page 4-44, the two companies will study short residence time gasification of coal to co-produce aromatic liquids with substitute natural gas.

Fort Union Regional Coal Team Charter Proposed As the first step in conducting federal coal leasing in the Fort Union region, the Bureau of Land Management has released for public comment a draft charter for the Regional Coal Team. As described on page 4-46, the draft charter establishes the duties of the RCT in either a competitive leasing mode or a leasing by application mode.

DOE Provides Impact Assistance to Local Governments Near Great Plains DOE has initiated payments of $100,000 per month to local governments near the Great Plains coal-to-SNG plant in Beulah, North Dakota. The payments are intended to help mitigate impacts caused by the large population increase caused by the plant. Originally, assistance funds were to come from a state coal conversion tax, but the tax cannot be imposed on the federal government which now owns the plant. (See page 4-48).-

A-8 II CORPORATIONS

DECLINE IN SYNTHETIC FUELS INTEREST Under the terms of the lease, as amended, USLMC is to APPARENT IN ANNUAL REPORTS receive annual Advance roy alties of $100.000 for years one and two; $50,000 for the third year; $175,000 for The decline in industry support of commercial synthetic the fourth year; $225,000 for the fifth year; $250,000 fuels projects that began in 1982 continued during 1985. for years six through ten; and $450,000 thereafter or Many projects were slowed, deferred, or cancelled 6 percent royalty of all production, whichever is the primarily due to economic considerations. Several greater. During the primary term of the lease, the forces contributed to the downturn in the synthetic lessee is entitled to a credit, against annual advance fuels industry. First, the drop in conventional energy royalties other than the advance royalty received for prices reduced the near-term prices that could be the first year, for all expenditures for direct expenses realistically expected for synthetic fuels. Second, slow which the lessee makes in connection with oil shale economic growth plus low energy prices reduced many operations conducted on USLMC's land. Such credit companies' revenues, thus reducing their capability to cannot reduce any annual advance royalty payable to fund major capital expenditures. Third, lack of long- USLMC to less than $50,000 annually, which was the term energy policy by the United States federal govern- amount received in 1978 through 1985, inclusive. ment (which eventually led to the demise of the United States Synthetic Fuels Corporation) removed the pro- During 1980, Geokinetics was awarded a $1.9 million spects of needed government assistance. On an inter- grant from the Department of Energy to perform a national scale, government support for synthetic fuels technical and economic feasibility study of a commer- remained strong in South Africa and Canada, with cial oil shale production facility on USLMC's property. moderate support in countries such as Japan, Australia, As part of this study Geokinetics has conducted a West Germany, the United Kingdom, the Soviet Union, drilling program on USLMC's property. Israel, and others.

Pace has acquired 1985 annual reports from an inter- AIR PRODUCTS AND CHEMICALS, INC. national group of diverse companies involved in synthetic fuels. The following excerpts from these annual We have been a world leader in cryogenic air separation reports indicate continued industry interest in synthetic technology. Our goal is to ensure technical leadership fuels technology development. However, most United whether it be in cryogenics or through new non-cryo- States companies have "gone back to the drawing genic processes. We are developing and commercializ- board" and have resorted to laboratory or pilot plant ing processes based on several non-cryogenic techno- studies rather than commercial-scale projects. This logies, including adsorption, membranes, and chemical trend is not reflected in annual reports from Canadian reactions. We view these new processes as innovative companies. additions to our range of technologies tied into market niches. The excerpts are direct quotations from 1985 annual reports. Additional annual reports were reviewed in the Our Moltox chemical process, now in the development June 1986 issue of the Pace Synthetic Fuels Report. phase is designed to produce tonnage oxygen. We believe this process will require less energy than existing technology and has the potential of meeting large ADVANCE ROSS CORPORATION oxygen requirements for several applications.

Utah Shale Land & Minerals Corporation (USLMC), approximately 25 percent owned by the Company, owns ALBERTA RESEARCH COUNCIL approximately 19,200 acres of land in the Uinta Basin in Utah. Oil Sands

USLMC has granted a shale oil lease on its property to Bitumen from Cold Lake oil sand is likely to contain Geokinetics Inc. The primary term of the lease is for a dissolved gas and is referred to as "live," whereas period of ten years from April 1, 1977 unless sooner bitumen that contains no dissolved gases is referred to terminated in accordance with further provisions of the as "dead." Researchers conducted three tests on dead lease, and so long thereafter as oil shale products are oil—one process with steam only and the other two being produced. To keep the lease in effect, Geokine- with steam and carbon dioxide. They also conducted tics was to commence construction of facilities for the four tests on live oil pre-saturated with methane—one production of oil shale by no later than the end of the with steam only, two with steam and carbon dioxide, fifth year (March 31, 1982). Since Geokinetics was and one with steam and methane. moving forward with diligence and in good faith, USLMC decided that waiving the March 31, 1982 date Now, at the end of five years, a computer model is would be in the best interest of both parties. In return, complete for processes using steam and three additives. Geokinetics agreed to prepay all of the minimum annual advance royalties due USLMC between 1983 and 1986. Recovery processes using steam with or without addi- This prepayment is being amortized over a four-year tives can cause geochemical reactions with the min- period commencing in 1983. erals in the formation. Under a joint program with the

1-1 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Alberta 311 Sands Technology and Research Authority coke. The coke produced also appears to be suitable for (AOSTRA), the Alberta Research Council has been electrode manufacturing. developing an understanding of these reactions in order to predict and control them in the field. The Alberta Research Council developed the capability for evaluating catalysts for their effectiveness in hitu- The Alberta Research Council has identified the neces- men upgrading and demonstrated that super acidic sary flow conditions for creating in situ foams in porous catalysts were more effective in cracking bitumen than media that can be used to block off certain areas of the existing commercial catalysts. formation. Experiments during the year were successful in measur- Energy Resources Geology ing quantitative values for the relative permeability of bitumen, water and gases in core samples. Experiments The Alberta Research Council documents and evaluates were also conducted to develop quantitative relation- the geology of regions in Alberta containing major oil ships to predict the volumes of bitumen/additive sys- sands and heavy oil resources. In a joint program with tem, under in situ conditions. Finally, this research has AOSTRA, a series of studies was completed on oil sand resulted in a method for predicting bitumen viscosities, deposits in the northern Cold Lake, Wabasca, Peace an important and sensitive parameter for reservoir River, Athabasca, and Grosmont Carbonate Trend re- models. gions, and on the heavy oil belt in the Lloydminster area. The Alberta Research Council conducted a study on the properties and aging characteristics of residues follow- In a project jointly funded by Alberta Energy and ing bitumen upgrading. Natural Resources and the Alberta Research Council, a coal resource inventory of the plains region to a depth of 400 metres was conducted. Coal

Research on coprocessing of coal and bitumen has the AMERICAN PETROLEUM INSTITUTE objective of evaluating whether the process is economically more attractive than heavy oil and bitumen up- Production of liquid and gaseous fuels from this nation's grading. With funding from the Office of Coal Re- abundant resources of coal, oil shale, and tar sands search Technology and the Canadian Coal Liquefaction remains a stated national objective and the objective of Corporation, an improvement was evaluated in the a number of API member companies. However, market technology for liquefaction coprocessing of coal and conditions and recent congressional action curtailing bitumen/heavy oil, developed by the Alberta Research the federal synthetic fuels program have discouraged Council. This improvement involves carbon monoxide investment by industry and greatly lengthened the ex- and steam as a partial replacement for hydrogen. The pected time before significant synfuels production will results of the economic study indicated that this pro- occur. Nevertheless, some API members are retaining cess was competitive with other new technologies, but or acquiring rights to synthetic fuels resources, plan- was less attractive than a new German process—Pyro- ning projects, meeting regulatory requirements, and sol. Work is continuing under contract to study the performing limited construction to bring projects closer suitability of the Pyrosol process to Alberta coals and to commercial development for completion when favor- bitumen. able conditions prevail. A number of government- assisted synfuels projects are in operation, under con- The Alberta Research Council successfully demon- struction, or being positioned for development. Pro-- strated that low-rank coals from Alberta and the jects in or close to operation include the Cool Water United States, as well as lignites, can be beneficiated combined-cycle coal gasification project and the Union using agglomeration. Parachute Creek oil shale project. With the slowdown in synfuels activity, API's Synthetic Hydrocarbon Upgrading Fuels Unit has reduced its staff and the number of committee meetings. The current staff is working to The use of calcium hydroxide in the coking process has ensure that the industry can contribute to synthetic been studied for its effectiveness in controlling the fuels production when such production is timely. In the release of sulfur dioxide on combustion and increasing past year, the unit: the yield of distillates. In 1985, experiments on a larger scale, in a 1,000 gram coker, confirmed earlier • Participated in a review of API policy on gov- experiments at a smaller scale. Research has been ernment financial incentives for synthetic directed toward upgrading pitch, the solid by-product of fuels. hydrotreating. • Sought resolution of problems created by Sec- tion 3 of the Federal Coal Leasing Amendments The Alberta Research Council has been conducting Act of 1976, including developing a statement research on the removal of asphaltenes from bitumen to a congressional committee and comments on prior to upgrading. Results of tests on the deasphalted Department of the Interior (Dot) guidelines bitumen, using the small cokcr (50 grams), have indi- implementing Section 3. cated the potential for producing 10 percent more liquid products during cokng and one-half the amount of • Monitored and reported on government synfuel

1-2 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 activities conducted by the United States Syn- members, or approximately a 13 percent rate increase thetic Fuels Corporation, the Department of over and above Basin Electric's 1986 wholesale rate. Energy, Environmental Protection Agency, and DO!). In the event of an abandonment of the Gasification • Supported API environmental and health re- Plant, Basin Electric would pursue any legal remedies search to establish baseline acid precipitation available to it, although no assurances can be made measurements in northwestern Colorado and to concerning the amount recoverable through the exer- determine the health effects of shale oil. cise of such remedies. • Obtained Department of Labor clarification of the jurisdiction of OSHA and the Mine Safety BRITISH GAS CORPORATION and Health Administration over tar sands facilities. British Gas methanation catalyst has been used success- • Produced a glossary of synthetic fuels terms. fully in the methanation stage of the first commercial coal-to-SNG plant at Great Plains in the United States. • Developed and conducted three synthetic fuels New catalysts have been developed and tested for technical sessions at the API Mid-Year Refining upgrading purified slagging gasifier gas at higher pres- meeting. sures. Novel dual amine activators for acid gas • Developed a recommendation for creating a removal have been tested successfully. data base on refining synthetic fuels and mixtures of synthetic fuels and conventional feed- Agreement has been reached with the Osaka Gas Com- stocks. pany to collaborate on a three year research pro- gramme into the hydrogenation of coal.

ASHLAND OIL, INC. CANADIAN PETROLEUM ASSOCIATION Ashland Development continued to operate a coal- water mixture fuel demonstration plant at an Ashland The rapid expansion of export markets for both light facility in South Point, Ohio. Test quantities have been and heavy crude oil have place continued demands on supplied to potential users, and the company expects to the major liquid carriers despite expansion plans al- undertake a major test program with steel producers in ready initiated. The high levels of capacity utilization 1986. were due to increased productive capacity for oil in western Canada; the changing production mix toward heavier gravity oils together with market deregulation, BASIN ELECTRIC POWER COOPERATIVE which has eliminated restrictions on exports. ANG Coal Gasification Company, the operating agent Industry expertise assisted in studies of the impact of for the nearby Great Plains gasification plant, supplies heavy oil development on various sectors of the pro-- lignite for the Antelope Valley Station. This lignite is vince. The transfer of control of the heavy oil labora- in turn supplied to ANG from the adjacent Freedom tory in Regional to the Petroleum Division of the Mine, which is operated by The Conteau Properties Saskatchewan Research Council was endorsed by Company, a wholly-owned subsidiary of The North industry. The applied research by the laboratory and American Coal Corporation. the specialized services which the facility will offer, are important to the future of heavy oil production and Arrangements ensure fuel supply for the Antelope Val- development of enhanced oil recovery in Saskatchewan. ley Station irrespective of future operations of the gasification plant. The United States Department of The BP/Petro-Canada Wolf Lake oil sands project, the Energy (DOE) assumed control of the gasification pro- first commercial in situ project in Canada, was com- ject in August 1985. The five private sponsors aban- missioned during 1985. This was followed by Esso's doned the project when the DOE rejected a price Cold Lake project. Several other projects at Cold Lake support package for the plant's synthetic natural gas are in the construction or injection phases. In addition, output. Shell Canada commenced construction on the first commercial project in the Peace River oil sands deposit In the event that the Gasification Plant is abandoned, during the year. the currently quantifiable effect on the operations of Basin Electric would be the increased need for revenues Although crude oil prices held up well during 1985, at from Basin Electric's members and patrons to make up the beginning of 1986 international spot market prices for the payments Basin Electric is presently receiving began to decline rapidly. While the outlook for prices is from ANG. If Basin Electric were unable to recover unclear even for the near term, the immediate impact any of its costs with respect to the Gasification Plant, of these prices on industry cash flow suggests that Management estimates that abandonment of the Gasifi- industry activity may decline from last year's high cation Plant would require approximately $42 million levels. If 1985 was the year in which government's new annually in increased revenues from Basin Electric's energy policies returned the Canadian oil and gas members and patrons to make up for the revenues Basin industry to the marketplace, 1986 appears to be the Electric would not be receiving from ANG. If absorbed year which will seriously test industry's resilience in solely by the members, this would require a six to seven turbulent markets. mill increase in the amounts Basin Electric charges its

1-3 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 CANTERRA ENERGY LTD. Recently completed for New Zealand Synthetic Fuels Corporation is a methanol facility at Taranaki, North Production from Canterra's two heavy oil recovery pilot Island. Davy McKee Landland were responsible for the projects increased significantly from 1984. basic process design, detail engineering, and procurement for the two 2,209 tonnes per day methanol plants, Total bitumen production from the Athabasca pilot with construction undertaken by Davy McKee London. plant, approximately 110 kilometers northeast of Fort McMurray in northeastern Alberta, exceeded In South Africa a demonstration fluidized bed coal 21,000 cubic metres, an increase of 155 percent. The gasifier has been built at Witbank in the Eastern operation, which is on a 19,779 hectare lease, is testing Transvaal as part of a development project which is a proprietary modified steam-drive process. Results being undertaken jointly by Iiighveld Steel, the Indust- from the new B pattern implemented in 1985 have been rial Development Corporation, JCI, and Davy. encouraging.

Canterra holds a 51 percent interest in the lease on DOME PETROLEUM LIMITED which the pilot project is located. The Alberta Oil Sands Technology and Research Authority is financing Total crude oil production was essentially level with the 25 percent of the pilot project's expenditures. previous year, as an increase in synthetic crude oil volumes balanced a small decline in conventional crude The North Battleford pilot project, on joint-interest oil production. lands near North Battleford, Saskatchewan, is testing a cyclic stream stimulation process followed by steam Two major projects which Dome had underway and drive. In 1985, following completion of the cyclic which are now on hold are our 15,000 barrel per day steam phase, the operation, in which Canterra holds a enhanced heavy oil recovery project at Lindbergh, near 33.3 percent interest, was converted to steam drive Lloydminister, in east-central Alberta and our which resulted in a 15 percent increase in oil production 25,000 barrel per day oil sands project at Primrose in to 37,300 cubic metres. the Cold Lake region of Alberta. The pace of development at Lindbergh and the start up of commercial The optimism resulting from the Western Accord and production at Primrose will depend primarily on the positive royalty regimes has been tempered by declining level of oil prices, since enhanced oil recovery costs are oil and natural gas prices. Nevertheless, these regimes substantially higher than costs for primary methods of continue to contribute to favorable economics for new recovery. In June 1985 Dome reduced its interests in exploration projects. Canterra anticipates that capital the Primrose area through the sale of its rights to earn spending in 1986 will be below 1985 levels due to an interest in 48 sections of the original 360 section uncertainty about product prices. block for $79 million. Until price stability returns, the company will be highly selective in investment projects. Development pro- FLUOR CORPORATION jects, which are characterized by high rates of return and provide immediate cash flow, are unlikely to be The 300 megawatt Kern County, California cogenera- severely affected. tion facility engineered and built by Fluor began operations in the Kern River oil field during 1985. The project, a pioneering effort among California enhanced CLEVELAND-CLIFFS INC. oil recovery operators, has led to a major second-phase contract to Fluor. The new facilities will generate Cliffs, with several energy-based activities conducted electricity for a California utility, as well as steam for through an office in Rifle, Colorado has been recog- the recovery of highly viscous crude oil. Fluor has also nized as a pioneer in oil shale mining research and won large cogeneration awards from two other oil pro- - development for nearly two decades. During 1985, oil ducers and a number of smaller contracts for feasibility shale development activities included environmental studies and reviews. and permitting work for the Pacific Oil Shale Property. Our Pacific Oil Shale Property is jointly owned with The Standard Oil Company (Ohio) and The Mobil Cor- IMPERIAL OIL LIMITED poration, and our Mineral Oil Shale Property in Color- ado is jointly owned with Mobil. Our Skyline Property The start-up, in early summer, of commercial bitumen in Utah is jointly owned with Sohio. Energy surpluses production from the Cold Lake oil-sands project marked and declining oil prices, however, continue to adversely the culmination of more than two decades of experi- affect interest in commercial oil shale development. mentation by Imperial into techniques for producing heavy oil from the oil sands through steam injection. The successful introduction of commercial production DAVY CORPORATION at Cold Lake highlights the valuable asset the company has in its Cold Lake leases. Work progressed well on contracts in hand, especially the $350,000 brown coal hydrogenation pilot plant at Cold Lake is being developed in stages, each stage MorwelL being capable of producing approximately 1,500 cubic metres of bitumen per day. Four stages are now in

1-4 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 production, and by the end of 1985 these, plus the pilot PETItO-CANADA plants, were producing about 8,000 cubic metres per day. Most of the bitumen produced is sold to refineries Petro-Canada's oil sands interests are currently making in the northern United States that are equipped to appreciable contributions to the Corporation's business. process heavy crude of this nature; some is processed at In 1985, Petro-Canada registered its first commercial Esso refineries in Canada. production from in situ oil sands, produced with other companies record volumes of synthetic crude oil from Work on two more stages at Cold Lake began in mid- the Syncrude plant, and continued to study possibilities 1985, with completion expected by mid-1986. The for major additions to its oil sands mining capability. development of additional stages is under consideration. Commercial production began in April 1985 at the Wolf Each pair of stages of Cold Lake development gener- Lake in situ oil sands project in northeastern Alberta. ates between 600 and 800 jobs during the peak con- This partner-operated project, in which Petro-Canada struction period and on-going operating and contract has a 50 percent interest, uses steam injection techno- positions for approximately 150 people. logy to recover approximately 1,100 cubic metres per day of bitumen. Over tOO permanent jobs have been The Syncrude oil-sands mining plant had an excellent created by Phase I of the project. Over the long term, year, surpassing all previous production records with a the Wolf Lake project could be expanded in phases to daily output of about 20,000 cubic metres of synthetic meet future energy demands. crude. Work is currently under way to increase Syn- crude's production capacity. The company has a 25 per- The Syncrude oil sands mining project achieved record cent interest in this operation. production in 1985. The plant, 17 percent owned by Petro-Canada, is located near Fort McMurray, Alberta. Petro-Canada's production share of fully upgraded syn- MAGIC CIRCLE ENERGY CORPORATION thetic crude totalled 1.27 million cubic metres, 15 percent over the previous record established in 1983. Work In January 1986 the price of crude oil dropped to levels proceeded in 1985 on expanding plant capacity to not seen since 1978. The $15 price per barrel of oil 22,000 cubic metres per thy. This Capacity Addition does not make the Company's Cottonwood Wash project Project will cost an estimated $720 million, of which currently attractive for sale to outside investors. Petro-Canada's share is about $122 million. Magic Circle has always considered oil shale to be a long-term investment and intends to maintain its oil During 1985, Petro-Canada continued to study the fea- shale leases into the foreseeable future. sibility of an oil sands mining project to be located on the Daphne oil sands leases about 65 kilometres north The United States Synthetic Fuels Corporation was of Fort McMurray, Alberta. established by Congress in 1980 to support the development of a synthetic fuels industry. Congress has now Construction of the CANMET demonstration plant at decided to ignore the future. Therefore, the Cotton- the Montreal refinery was completed and testing began wood Wash project will have to be mothballed to await in late 1985. When fully operational, the plant will the next energy crisis. The Company released several convert fuel oil into gasoline and distillates. oil shale leases in 1984 and maintains rentals on the Cottonwood Wash property and the prime oil shale lands The Corporation's share of expenditures on the Syn- outside the Cottonwood Wash project totalling crude oil sands mining plant and the Wolf Lake in situ 45,849 acres. The Company added 3,885 acres to the oil sand project were $59 million and $13 million, re- Cottonwood Wash block through an exchange of lands spectively. between the State of Utah and the United States in 1985. RAYMOND INTERNATIONAL INC. The Company owns 77 state oil shale leases covering 45,849 acres in Duchesne and Unitah counties, Utah. Mid-1984, high BTU gas made from coal began flowing into the United States' pipeline network from Great Plains coal gasification project, marking a synfuels first METALLGESELLSCUAFT AG for North America. On the North American market, Lurgi Is collaborating exclusively with Combustion Engineering, the largest STANDARD OIL COMPANY, THE boiler manufacturer. In Canada, a demonstration power plant, which will burn highly sulfurous coal and high-ash After the company assessed the current economic en- shale, is under construction. A Lurgi process for the vironment for energy, its programs for producing oil recovery of oil from oil shale and tar sands was the from shale or tar sands were cut back to maintenance subject of a know-how agreement with a major oil levels. However, Standard Oil will continue its efforts company. in the development of new fuel alternatives and innovative processes if it makes sense at lower energy prices.

1-5 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TENNECO INC. following geological review and primary production testing to determine if additional wells and/or steam In August 1985, Tenneco announced its decision to write stimulations tests are warranted. The program is off substantially all of its investments in the Great evaluating the potential for commercial recovery oper- Plains coal gasification project and the Cathedral ations. A decision is not expected until after the Bluffs shale oil project. The write-off resulted in a loss completion of any steam stimulation testing. from discontinued operations of $240 million (net of income tax benefit of $79 million which includes tax Texaco Canada has phased out operations in the first credit recapture). The synfuels operations had no two patterns of wells drilled at its Fort McMurray Pilot operating revenues in 1985, 1984, and 1983. Net Project in the Athabasca oil sands area of northeastern income associated with these discontinued operations Alberta. Production and data gathering are continuing was $1 million, $14 million, and $29 million, respective- in a third pattern which includes three long, parallel, ly (net of income tax benefit of $2 million, $17 million, horizontal wells drilled in 1980/1981 to test recovery and $30 million, respectively). from horizontal drain holes. Research is concentrated on the development and application of in situ recovery Tenneco's decision was based primarily on the decision techniques to make bitumen flow while leaving the sand of the Department of Energy (DOE) on July 29, 1985 in place. not to support a proposed arrangement with the United States Synthetic Fuels Corporation (SFC) for price The Fort McMurray Pilot Project has provided Texaco guarantee assistance and debt restructuring for the Canada with information and techniques for application Great Plains project. The DOE's action led to a on other properties where the depths of the overburden determination by the partners of the Great Plains above the oil sands deposits do not allow economic Gasification Associates, in which Tenneco holds a bitumen recovery by open pit mining procedures. At 30 percent interest, to terminate the project. the 10,400 hectare Hangingstone lease, south of Fort McMurray, for instance, the company has initiated a It also appeared unlikely that sufficient assistance 25 well drilling program scheduled for completion in the could be provided to make the Cathedral Bluffs shale first quarter 1986 as a first step in assessing the oil project economically viable, and consequently, in potential for a pilot project. August 1985 Tenneco wrote off substantially all of its investment in this project. Subsequently, Congress No reserves have been attributed to the company's oil passed an omnibus appropriations bill at the end of the sands deposits because no portion of the bitumen has 1985 session that stripped the SFC of its remaining yet been shown to be economically recoverable. funding and provided for the shutdown of the SFC within 120 days. The bill was signed into law on December 19, 1985. Tenneco is a 50 percent partner in TRANS CANADA PIPELINE the Cathedral Bluffs shale oil project. Earnings in 1985 increased 5 percent to $278.1 million, before deduction of investment and asset provisions TEXACO CANADA INC. which the company announced in December. These provisions, which reduced 1985 earnings by $115.6 mil- Texaco Canada intends to achieve a significant heavy lion after tax, result primarily from a change in the oil and oil sand presence through a two-fold strategy: method of accounting for oil and gas properties and a first, intensive exploration of existing land holdings to writedown of the company's investments in Cyprus delineate potential reserves and to evaluate recovery Anvil Mining Corporation and is undeveloped oil sands processes for identified resources; second, active pur- properties. suit of farm-ins or acquisitions. The company has given high priority to its goal of participating in a commer- In 1985, TransCanada Pipeline Resources' daily sales in cial oil sands project. Canada, before royalties, averaged about 15,000 barrels of oil and natural gas liquids, an increase of almost The purchase of Canadian Reserve Oil and Gas Ltd. in 8 percent over 1984. The increase reflects the first full 1985 provided Texaco Canada with a heavy oil produc- year of operation of the West Pembina gas cycling tion base, interests in heavy oil properties and technical plant. Also contributing to the increase were record expertise in the production of heavy oil. Production volumes from the Syncrude synthetic oil sands opera- from the wholly-owned Lone Rock heavy oil steam pilot tion. project near Ltoydminster, Saskatchewan began during 1985. Initial results of 100 cubic metres per day have been encouraging, and the potential for expanding the UHDE GmbH project is under review. The company's total heavy oil production in 1985 amounted to 730 cubic metres per The plant nearest completion, and for which start-up day. operations have already begun, is the lignite gasification plant for Rheinische Braunkohlenwerke AG (Rhein- On Texaco Canada's Frog Lake lease in the Cold Lake braun) in Berrenrath. This complex is based on the area of east-central Alberta, four corehole wells were Rhcinbraun high-temperature Winkler process and will drilled early in 1985 and a seismic program was con- produce 1 million cubic meters of synthesis gas from ducted. A further seven-well evaluation program was 700 tons of lignite per day. This synthesis gas, in turn, completed early in 1986. Results will be evaluated will be utilized in the production of 110,000 tons of methanol per year.

1-6 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The second commercial plant, using hard coal and based After treatment of the gas in the existing units and on the Texaco process, is being engineered by Uhde for admixture of nitrogen, 280 tons of ammonia will be Ruhrkohle Get und Gas GmbH and Ruhrchemle AG in produced daily. The high-temperature Winkler process Oberhausen. This plant, which converts 700 tons of is a fluidized bed process conducted at high tempera- hard coal to 1.2 million cubic meters of synthesis gas ture and pressure below the melting point of ash. The per day, is now in the final stages of erection and is process is particularly flexible with respect to different expected to be commissioned in spring 1986. In this feedstocks. Reactive raw materials, such as lignite, case, the synthesis gas will be used as the feedstock in peat, timber, and biomass have already been gasified the production of hydrogen and intermediate chemical successfully in the pilot plant. products (oxo-alcohols). The technology applied in these plants is in line with UMA GROUP today's high standards where environmental pollution control is concerned. For both plants, Uhde in coopera- During 1985, UMATAC Industrial Processes under fund- tion with its partners, Rheinbraun and Rhurkohle/Ruhr- ing agreements with the Alberta Oil Sands Technology chemie, has devoted ten years to development projects, and Research Authority (AOSTRA) continued with de- from the construction of a pilot plant to the final sign and development of the Taciuk Processor. In early operational phase. 1985, the Oil Sands Demonstration Centre (OSDC) concept for a demonstration plant location was abandoned The South Australian Government plans to cover its and UMATAC prepared capital and operating cost esti- increased energy demand in the 1990s by the gasifica- mates for an integrated demonstration project. tion of local lignite resources using a combined cycle power plant, for which Uhde has received the contract A capital and operating cost estimate for a single to carry out a comprehensive feasibility study, provid- commercial processor unit plant was completed in Nov- ing for the Rheinbraun high-temperature Winkler gasifi- ember. It would produce a pumpable, unhydrotreated cation process. A consortium under the overall control oil product which would be pipelined directly to of Uhde and comprising Rheinbraun AG, Cologne, Steag remotely located refineries. Results of the economic AG, Essen, and Kraftwerkunion, Erlangen, has been analysis for this plant were encouraging. formed to handle the project. This new type of power plant is characterized by its high efficiency and im- AOSTRA continued discussion with potential partici- proved environmental pollution control. pants in the proposed 90 tonne per hour demonstration project and a decision Is anticipated in early 1986. New methods of manufacturing ammonia from raw materials other than natural gas or crude oil distillates UMATAC continued with test work on other candidate are at present being explored in Scandinavia. feedstocks including batch test work completed on Australian oil shales, United States oil shales and oil The Swedish Company, Nynashamns Combinatet, has and acid bearing waste dump materials. These tests plans to construct an ammonia plant based on hard coal confirmed the potential for the use of the Taciuk gasification and Uhde has been awarded the contract Processor in these areas. for the engineering. The complex will be used to gasify 657,000 tons of coal per year using the Texaco process, Syncrude Canada Ltd. retained UMA to provide multi- producing 455,000 tons of ammonia, 530,000 megawatts disciplinary engineering services for their Mine Mobile fuel gas, and 40 million Nm 3 hydrogen. Equipment Shop expansion and Mine Electrical Shop Expansion. The Mine Mobile Equipment expansion in- The process heat obtained at a low temperature level cluded a three storey, 3,700 square meter Mine Services will be utilized to produce 1.55 megawatts of hot Building containing lunchroom, locker room for 400 em- water, which will be supplied to homes in Stockholm via ployees, washroom facility and warehouse, offices, the district heating system. In addition to its pollution- boiler room, mechanical and electric equipment and an free operating mode, this scheme achieves a working eight bay, 2,045 square meter Heavy Duty Shop and a efficiency in the region of 80 percent through the separate double heavy truck wash bay. The Mine combination of chemical production and district heat Electric Shop expansion included a 1,120 square meter supply. It Is a pointer to future operating methods for addition to accommodate a crane repair area, a motor sites with similar conditions. test area, a cable shop, a switch house repair area, lunchroom, locker room, utility room, compressor room Northern Finland may have neither crude oil nor natural and shop area. gas to provide cheap sources of energy, but what it does possess is an abundant supply of peat, which can be Suncor Inc. retained UMA to prepare a mine facilities exploited both cheaply and on a large scale. plan to Identify facility requirements in their Fort McMurray, Alberta mine until lease end in 2005. The Kemira Oy, Oulu has therefore given Uhde the contract study involved analyzing all aspects of Suncor's current for engineering the replacement of a former heavy oil tar sand mining activities to identify optimum alloca- gasification plant by another based on the gasification tion of resources for future facility improvements and of peat. Following detailed pilot plant tests, Kemira expansion. The operating departments which came Oy decided In favor of the Rheinbraun high-tempera- under analysis in the study included mine operations, ture Winkler process (HTW), which will entail the mobile equipment maintenance, mine maintenance, gasification of 650 tons of peat per day at a pressure of overburden operations and dyke operations. A detailed approximately 15 bar.

1-7 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 review of options concluded that the greatest benefit oil to C$10.50 per barrel. (This compares to C$29.34 from capital expenditures could be obtained by provid- received in December 1985). Heavy oil operating ing facilities for work crews closer to the mining expense increased from C$4.8 million in 1983 to activities. C$6.6 million in 1984 and declined to C$6.1 million in 1985 as Fort Kent reached a more mature stage of Esso Resources Canada Limited engaged UMA for the development. Because of successful drilling efforts in design, construction supervision, and pump testing of a 1985, conventional oil sales in Canada increased to new groundwater supply for their heavy oil facilities at C$2.9 million in 1985 from C$1.3 million in 1984 and Cold Lake, Alberta. Each of six new wells has a C$1.4 million in 1983. Due to recent price declines the 300 millimeter ID casing and will have total depth of operator of the Fort Kent heavy oil project is presently between 90 and 180 meters. Screens were designed implementing cost reduction measures including the during drilling operations on the basis of aquifer sample shutting in of marginally productive wells. Operations analysis. Screen development was carried out followed at the project will continue to be monitored in light of by draw down tests to evaluate well efficiency and the depressed prices currently being received for heavy potential capacity. Twenty-four hour pump tests were oil. performed on each well and several wells for each site were pump tested simultaneously for five days. The data from these tests was used to support Esso's application to license the water supply. Because the client had installed a number of wells in the area and had extensive geological data available from exploration drilling operations, the information available proved invaluable in designing the new system. UMA reviewed all available geological and hydrogeological data, developed preliminary well designs and prepared specifications for tendering well construction and pump supply.

WORLDWIDE ENERGY CORPORATION

Through Canadian Worldwide, the Company has interests in substantial heavy oil, conventional oil and natural gas reserves in Western Canada. Canadian Worldwide holds interests in three heavy oil properties located in the Cold Lake Area, approximately 150 miles northeast of Edmonton, Alberta. Heavy oil in this area cannot be extracted using traditional primary recovery methods. The most common way to produce heavy oil involves the use of cyclic steam stimulation to heat the oil to a more mobile state. Canadian Worldwide has been using this technology, called "huff-and-puff," to produce heavy oil in the Cold Lake area since 1974. All of Canadian Worldwide's reported heavy oil reserves are attributable to its Fort Kent property. Canadian Worldwide owns a 50 percent working interest in this project, which covers a 4,960 acre lease, and is operated by Suncor Inc. (75 percent owned by Sun Oil Company and 25 percent by the Province of Ontario) which owns the remaining working interest. Revenues from the Company's Fort Kent heavy oil project increased from C$11.4 million in 1983 to C$16.8 million in 1984 and to C$16.9 million in 1985. The revenue increase from 1983 was a direct result of the Phase Ill expansion which was essentially completed by March 1983. The average annual production rate increased from 1,032 barrels oil per day in 1983 to 1,461 in 1984 and decreased to 1,435 barrels oil per day in 1985. The average price has not varied significantly during this three year period. The declining world price for oil, as noted above, has also had a dramatic effect on the price received for heavy oil. (The price for oil in Canada was deregulated on June 1, 1985.) In February 1986, Husky Oil Ltd., due to a loss on its January purchases, reduced its buying price of all Alberta heavy

1-8 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 GOVERNMENT

DOE SELECTS PROJECTS AND SOLICITS According to the developer, the REP holds promise as a R&D PROPOSALS FROM SMALL BUSINESSES HTHP particulate control device, thus advancing the commercialization of pressurized fluid bed combustion In August 1986, the United States Department of and gasification-combined cycle plants. The REP is a Energy (DOE) invited small business firms (500 employ- combination of electrostatic precipitator and fabric ees or less) to submit proposals under its fifth annual filter technologies that provides a significant improve- solicitation for the Small Business Innovation Research ment in particle collection capability at greatly re- (SBIR) program. The SBIR program's objective is to duced capital and operating costs. The potential mar- strengthen the role of small, innovative firms in areas ket for this device is the entire new precipitator of research and development (R&D) that are federally market and also the precipitator retrofit market. The funded. It is also intended to use federal R&D as a base United States precipitator market should average for technological innovation, to meet agency needs, and $200 million per year over the next 5 years. One to contribute to the growth and strength of the nation's variation on the REP appears suitable for application to economy. The program implements the Small Business "clean rooms." Innovation Development Act of 1982. Successful proposals (approximately 100) may receive up to $50,000 to explore the feasibility of their ideas. Of the 28 topics A High-Performance Gas Separation included in the program, the following are of potential Membrane (Foster-Miller, Inc.) Interest to the synthetic fuels industry: Amount: $49,995 • Coal utilization and conversion The developer believes that membrane applications for • Fossil energy instrumentation gas cleanup and gas separation have been limited be- • Enhanced oil recovery and tar sands cause of their low flux, the chemical resistance of • Fossil energy materials. current materials, and their high temperature limits. Corrosive materials such as flue emissions, synthesis The closing date for receipt of proposals is November 3, gas, and hydrogen sulfide create difficult environments 1986. for current membrane materials. Elevated temperatures increase the problems associated with corrosive For the PY1986 SBIR program, out of 699 proposals environments. Most materials, when prepared as thin DOE recently selected 101 projects for Phase 1 funding. films, are difficult to handle and do not have the tensile The period of performance in this initial phase is strength desired for practical applications. A new typically about 6 months, and the awards are limited to material, polyparaphenylene benzobisthiazole (POT) $50,000. Phase II is the principal research and develop- overcomes many of these limitations. It appears to be ment effort, and the awards are as high as $500,000 for a good candidate for elevated temperature gas separa- work of up to 2 years. Phase Ill is the commercial tions in corrosive environments. This program will application of the research and development effort by develop the membrane properties needed for gas and small businesses with non-federal capital. Alternative- liquid separations. A process will be developed for ly, Phase III may involve non-SBIR federal contracts for producing microporous thin film membranes from PSI. products or services desired by the government.

The selected projects in the FY1986 program that are A Superior Method for Desulfurization of particular relevance to synthetic fuels are briefly of Low- and Medium-BTU Gases summarized as follows. (Gas Desulfurization Corporation) Amount $49,998 A Particulate Control Device for The project objective is to confirm the calculations and High-Temperature, High-Pressure limited laboratory data that indicate the superiority of (HTHP) Gas Clean-Up (ETS, Inc.) cerium oxide for desulfurization of fuel gases produced Amount: $49,801 from coal. Desulfurization trials will be run at temperatures up to 2,2000F, and regeneration back to cerium Thedevice, a Reduced Entrainment Precipitator (REP), oxide will be demonstrated. The proposer believes that will potentially have improved collection efficiency for oxides of the common metals (iron, zinc, etc.) which dusts having either high or low electrical resistivities. represent present technology, are deficient as desulfur- This objective is accomplished by drawing a small izers because they cannot operate at temperatures over portion of the dirty gas through the collected dust cake 1,200°F and are unable to process fuel gases high in and a porous collecting plate by a separate fan. This carbon monoxide and hydrogen. Calculations indicate small flow through the dust provides an aerodynamic that the thermal efficiency of coal gasifiers increases force to reduce re-entrainment of the dust. The REP by 36 percent when the operating temperature in- should have the following advantages over fabric filters creases from 1,2000 to 1,6000F. Cerium oxide could and electrostatic precipitators for HTHP application: readily desulfurize such fuel gases at 1,600°F. Labora- (1) no metal collecting plates or metal rapping mecha- tory trials have obtained 99.96 percent sulfur reduction nisms, (2) approximately 80 percent less expensive fil- from gases that contained 1.0 percent hydrogen sulfide. ter fabric used in the REP than in baghouses, (3) smaller overall size.

1-9 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Phase I will define the sulfur-capture efficiency of wells. Thus, it is desirable to develop a surface cerium oxide and will confirm the validity of the mapping method to track the location of the flood front predicted regneration process. Phase II will provide the without drilling additional wells. One promising method necessary kinetic data for the design, construction, and is passive seismic monitoring. Previous observations operation of a Phase Ill pilot plant and the eventual using down-hole sensors at a fireflood in Eastern construction of a commercial desulfurization unit. Alberta, Canada detected both seismic noise emissions High temperature, desulfurized fuel gases from coal and discrete seismic events being generated from the can be used with increased thermal efficiency for flood front. Phase I intends to demonstrate that these combined-cycle power plants, fuel cells, and boilers. seismic events can be detected by surface or near- surface seismometers and used to map the location of the flood front. Phase II will consist of a longer field A System to Avoid Tailings Ponds monitoring period to show that the velocity and migra- When Processing Utah Tar Sands tion pattern of the flood front can be mapped. During (Applied Utility Systems, Inc.) Phase II it also would be desirable to build a real-time Amount: $49,850 processor for on-site program execution in the field.

A proprietary process for the recovery of bitumen from Successful results of this study would provide an econo- Utah tar sands will be investigated. The process is mical method of mapping fire or steamflood fronts in based on the use of solvent, followed by the addition of EOR projects. This method would also provide higher small amounts of electrolyte and surfactant to produce spatial resolution because the mapping does not require an effluent with a neutral pH suitable for disposal. The the need for observation wells. Results may also be process offers a promising technology for the recovery applicable to mapping hydraulic fractures in geothermal of bitumen from tar sands in an environmentally ac- and tight gas sands stimulation projects. ceptable manner.

A High-Efficiency Technique for Steamflooding Deep, Heavy Oil Reservoirs (Carbotek, Inc.) Amount: $50,000

A steam flooding/steam generation system is proposed DOE REORGANIZES TO ADMINISTER for deep, heavy oil reservoirs. Carbotek believes that CLEAN COAL PROGRAM this concept minimizes the downhole heat losses, improves reliability, and reduces the cost of steam generation. Its features may make steaming of very deep On June 23, 1986 the United States Department of Energy (DOE) announced that it had realigned its head- wells (below 7,500 feet) technically and economically quarters fossil energy organization. The reorganization feasible. The concept supplies heat to the reservoir primarily affected the research programs associated with a downhole unit augmented by heated feedwater. with coal, petroleum, and natural gas. The new organi- The system uses a gas turbine to supply heat and zation of DOE's Office of Fossil Energy is depicted in cogenerated electrical power. Phase I laboratory test- Figure 1, with the functions of each group described in ing will address the key corrosion and operability issues Table 1. of the downhole unit. Phase II would consist of prototype construction and testing, detailed design of down- A new office to administer the Clean Coal Technology hole assembly procedures, and longer term performance testing. demonstration program was established as part of the reorganization. Mr. C. Lowell Miller was named as the Acting Director of the Office of Clean Coal Techno- According to Carbotek, successful development of this logy. (Recent activities regarding the Clean Coal technology could make over 5 billion barrels of United program are described in this issue of the Pace Synthe- States deep, heavy oil reserves physically and economi- tic Fuels Report in the Government portion of the Coal cally accessible to recovery by steamflooding or "huff section.) and puff." It could also improve economics of shallower steamflood projects by adding cash flow from cogenerated peaking power sales.

Passive Seismic Mapping of Thermal Flood Fronts (Utah Geophysical, Inc.) Amount: $50,000

Fireflood or steamflood enhanced oil recovery (EOR) processes are commonly used for heavy oils or tar sands. To optimize the use of these processes, the operator needs to know the velocity, location, and direction of movement of the thermal flood front. Current technology uses sparsely spaced observation

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1-11 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1

GROUP FUNCTIONS WITHIN DOE'S OFFICE OF FOSSIL ENERGY

Under the Deputy Assistant Secretary for Clean Coal, Combustion and Conversion Systems • The Office of Clean Coal Technology will administer the $400 million Clean Coal Technology program approved by Congress last fall • Two additional offices will oversee companion mid- term technologies for clean coal: - Combustion Systems: fluidized bed combustion, retrofit combustion systems including in-boiler environmental control technology - Conversion Systems; Surface coal gasification and heat engine systems including hot gas cleanup Under the Deputy Assistant Secretary for Advanced Fuels Technology, Extraction, and Environmental Control • The Office of Advanced Technology and Environ- mental Controls will manage high technology work in fuel cells, magnetohydrodynamics and flue gas cleanup • The Office of Coal Preparation and New Fuels will manage: coal preparation, coal pyrolysis, coal-oil coproeessing, coal liquefaction and related waste management activities • The Office of Oil, Gas and Shale Technology will manage extraction technology programs including enhanced oil recovery, unconventional gas recovery and underground coal gasification, oil shale, and tar sands Under the Deputy Assistant Secretary for Management, Planning and Technical Coordination • A new Office of Business Operations will oversee the Fossil Energy participation in projects to be funded under the proposed cooperative R&D venture pool and will examine methods for the transfer of business-oriented fossil energy projects to the private sector • The Office of technical Coordination will consolidate the coal-based advanced research and technology development program and the oil- and gas-based advanced process technology program The Office of the Deputy Assistant Secretary for Petroleum Reserves was Unaffected by the Reorganization

1-12 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENERGY POLICY & FORECASTS

As shown in Figure 2, investment in synthetic fuels PACE FINDS SYNFUELS FUTURE HOLDS PROMISE, BUT IMPROVEMENTS NEEDED research and development (R&D) is closely related to the price of conventional oil in the United States. The events of the last few years have been extremely discouraging for the United States synthetic fuels in- When the cost of crude oil reached its all-time peak in dustry. At its peak, several hundred commercial syn- 1981, the R&D expenditures by the federal government thetic fuels projects were under consideration in the and industry peaked in the same year. Since that time, United States. This number has now been reduced to a as the price of crude oil has fallen, so has the interest mere handful of projects. Therefore, Pace believes in synthetic fuels R&D. (Recent data for industry R&D that a review of recent events in the industry and the expenditures are not currently available. However, current status of synthetic fuels is now warranted. these expenditures have been reduced to a mere frac- Moreover, an analysis and forecast of the future of the tion of the expenditures of the early 1980s.) industry are needed. The relationship between synthetic fuels interest and For our analysis, we limited the scope to oil shale, oil the price of crude oil is also shown in Figure 3. In this sands, coal gasification, and coal liquefaction. Ex- figure the price of crude oil has been adjusted for cluded from our analysis were other methods of produc- inflation to constant 1986 dollars. As shown in the ing energy such as enhanced oil recovery, biomass figure, the real price of crude oil rapidly increased conversion into products such as ethanol, refuse-derived during the 1970s with a concurrent interest in synthetic fuels, hydrogen, solar, geothermal, and others. fuels. Important events that occurred during this peak of interest are shown on the figure.

History It is interesting to note, by comparing Figures 1 and 3, that the cycles of interest in shale oil production do not Since the early 1800s activity in synthetic fuels in the coincide with the real price of crude oil. Rather, the United States has been extremely cyclical. Figure 1 interest in shale oil was sparked each time by expected demonstrates the cyclicality of the oil shale industry shortfalls in energy, and, hence, increases in price. since 1800. Each cycle in the industry can be related to Pace, therefore, concludes that expectations of price events that occurred in the conventional oil market. increases have been more important to the development The first cycle of oil shale activity collapsed after the of synthetic fuels than the actual prices that eventually first oil well was drilled in Pennsylvania and began to were experienced. produce oil in 1860. Interest began to again build during World War I but, new sources of conventional oil In addition to the price of conventional energy supplies, were discovered in California, Texas, and Oklahoma, the energy policy of the federal government greatly which resulted in a 50 percent drop in the price of affects the interest in synthetic fuels in the United crude oil from 1920 to 1924. During World War II States. Before 1973, the main function of energy petroleum shortages sparked the third major cycle of planners in the United States was to manage and oil shale activity which soon declined with the discov- distribute adequate energy supplies for the population. ery of oil reserves, this time the huge deposits in the Between 1973 and 1980 a new policy emerged: that of Middle East during the 1950s. During the 1973 Arab Oil establishing a mechanism to manage crises and to Embargo a sharp spike of interest in the oil shale reduce imported energy. In 1981 a new era in federal industry was short-lived due to rapidly escalating cost energy policy began with the Reagan administration. estimates for oil shale facilities. The fifth and last The philosophy of the Reagan administration is to shift peak in oil shale interest developed due to the Iranian control of energy supply to the private sector. Control crisis in the late 1970s. However, in 1981 this interest of the massive federal deficit far outweighs any con- again began to decline due to the incoming Reagan cerns for energy policy. administration's policy towards oil shale development, and the gradual downturn in conventional oil prices. The new attitude of the federal government is illustrated by the struggles of the Synthetic Fuels Corpora- The cycles shown in Figure 1 have two interesting tion. The SFC did not became fully operational until features. First, the time between peaks of interest has February 1982—over 1.5 years after it was established. been progressively decreasing. The first cycles were The first SFC Board of Directors struggled with select- sixty years apart, and the last only six years apart. ing synthetic fuels projects which they believed war- Secondly, the amount of shale oil that was produced ranted federal assistance. In the first two years, only during each cycle has been progressively larger. Only a two projects received awards. Additionally, several few months of operation of the Union oil shale project members of the SFC Board were accused of improprie- will produce more oil than the cumulative production in ties and conflicts of interest. In April 1984, the SFC all previous cycles. A series of plants, such as the was rendered inoperative by the resignation of several Union plant, will provide a base load of shale oil members of the Board. Funding of the SFC was then production that will eventually eliminate the industry reduced by Congress from $15.3 billion to $7.9 billion cyclicality. on October 11, 1984.

1-13 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

FIGURE I

U.S. OIL SHALE ACTIVITY CYCLES 400

300 55 04 200 04 03S 100 nanJ 1800 1880 1900 1950 2000 L 40 YEARS ______SOYSASj 10 YEARS S YEARS

FIGURE 2

TOTAL U.S. SYNTHETIC FUELS R&D FUNDING 1979-1986

500 745 ESTIMATED PRIVATE ftSECTOR SPENDING FEDERAL APPROPRIA 144 Z 0 800 n SE. a 200

1070 1080 1951 1982 1053 1014 '985 1Q56 SOURCE; SYNTHETIC FUELS RESEARCH INSTITUTE U.S. DEPARTMENT OF ENERGY

COMPOSITE REFINER ACQUISITION COST OF CRUDE OIL 40 r 35.24 m 11.17 a 301- 28.90 2563 IS II IS I I I I -I I I I I I U a I I I I .1 o I I I I 20L17.721I I I I I I I

1970 1980 1Q81 1982 1963 1284 1965 111th 5,86

SOURCE; U.S. DEPARTMENT OF ENERGY

1-14 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 3

34° API CRUDE OIL CONSTANT 1986 DOLLARS 40 - -

TENNESSEE 35 - IA TUAN - COOL WATER IN GREAT 3° PLAINS DOE EA SFCI : : PARACHUTE CREEK 16 - FOREST NItL

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5 p I II 11111,1 1941 52 51 82 81 12 77 1982

The SFC Board was eventually reconstituted by the Next, the Dow Syngas Project received a price guar- addition of new members in November 1984. The new antee of $620 million in April 1984. The guaranteed Board members, who were much more familiar with the price is $12.50 per million BTUs for the first eleven synthetic fuels industry, established a new business plan trillion BTUs, and $11.00 per million BTUs thereafter. for the SEC. The new business plan was designed to These support prices, when converted to a crude oil demonstrate various synthetic fuels production techno- equivalent basis, are approximately $72 per barrel and logies. This new philosophy was different from the $64 per barrel. previous goal of producing Congressionally mandated quantities of synthetic fuels products. Although the Near the end of its existence, the SEC awarded a new Board was making progress towards their new $60 million loan and price guarantee to the Forest Mill goals, on December 19, 1985 Congress rescinded all heavy oil project in Texas. The guaranteed price for funding for the Synthetic Fuels Corporation. By April the heavy oil from the project initially begins at $40 1986, the SFC had been disbanded, and monitoring per barrel for the first 500,000 barrels. Thereafter the functions had been transferred to the Department of guaranteed price is $37.50 per barrel. the Treasury. Lastly, the SFC awarded a $500 million loan and price guarantee to the Union oil shale project at Parachute, Current Status Colorado. This award was in addition to the $400 million award provided to the project by DOE. The During its stormy five-year history, the SEC issued guaranteed price for the oil produced by Unishale "B" twelve solicitations for synthetic fuels projects. From process is $37.87 per barrel. However, if Union modi- these solicitations, the SEC received 211 proposals for fies the plant to utilize the Unishale "C" process, the 132 discrete projects. The SEC awarded funding to only price guarantee increases to $67.87 per barrel. four projects out of this slate of potential synthetic fuels projects. Awards to these projects totaled In addition to the four projects receiving SEC assist- $1.3 billion from the SFC, plus the $400 million that ance, two other commercial synthetic fuels projects had been awarded to the Union oil shale project by the were also built and started up during the last five years. DOE. A brief summary of these four projects is These projects, which are also listed in Table 1, are the presented in Table 1. Great Plains plant and the Tennessee Eastman Project. The Cool Water project, an integrated gasification The Great Plains Project received a loan guarantee combined cycle (IGCC) project, received a price guar- from DOE for $2.02 billion in August 1981. The award antee from the SFC for $120 million. The guaranteed from DOE included a price limitation of $6.75 per price is $12.50 per million BTUs for the first nine million BTUs with price caps related to the prices of trillion BTUs and $9.75 per million BTUs for the next natural gas and No. 2 heating oil. Due to these price eleven trillion BTUs. These guaranteed prices are caps the amount of assistance the project received roughly $72 per barrel and $56 per barrel when con- during 1984 was roughly $5.90 per million BTUs, and verted to an equivalent crude oil price. this price support had declined to only approximately $5

1-15 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 per million BTUs in 1986. These financial problems caused the five partners of the project to default on the • The KRW pilot plant demonstrating a fluidized DOE loan, and DOE acquired title to the plant on bed coal gasification process at Waltz Mill, June 30, 1986. Pennsylvania • The General Electric fixed bed coal gasifier at Lastly, the coal-to-chemicals plant by Tennessee East- Schnectady, New York man has been successfully operating since 1983. This plant is notable in that it was completely, privately • The Shell coal gasification plant currently financed by Tennessee Eastman. under construction at the Deer Park, Texas facility In additon to these four commercial projects, several • The TVA Texaco gasifier for ammonia produc- pilot plants are also currently in operation or standby in tion at Muscle Shoals, Alabama the United States. These include the following: • The Solv-Ex solvent extraction tar sands plant • The Wilsonville direct coal liquefaction plant at Albuquerque, New Mexico demonstrating the integrated two-stage lique- • The diatomaceous earth Lurgi pilot plant at faction process Bakersfield, Calfiornia. • The KILnGAS low-BTU coal gasification plant at Wood River, Illinois

TABLE I

COMMERCIAL UNITED STATES SYNTHETIC FUELS PROJECTS

Government Assistance Start-Up Support Project Name Type Capacity Date Total Price Cool Water Coal 1,000 tons May 1984 $120 Million $12.50-$9.75/MMBTU Gasification of Coal/Day Price ($72-.$56/Bbl) Dow Syngas Coal 2,300 tons 2Q:1987 $620 Million $12.50-$11.00/MMBTIJ Gasification of Coal/Day Price ($72-$64/Bbl) Forest Hill Heavy Oil 1,750 Barrels In Progress $60 Million $40-$37.50/BbI Fireflood Per Day Loan & Price

Parachute Creek Oil 10,400 Barrels In Progress $400 Million $42.50/Bbl Shale Per Day Price $500 Million $37.87-$67.87/Bbl Loan & Price

Great Plains Coal to 14,000 tons July 1984 $2,020 Million $6.75/MMBTU SNG of Coal/Day Loan ($39/Bbl) Tennessee Eastman Coal to 900 tons October 1983 Privately Financed Chemicals of Coal/Day

1-16 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 A relatively new aspect to the synthetic fuels effort in Briefly, the current status of United States synthetic the United States is the Clean Coal Technology Pro- fuels is as follows: gram which was recently established by Congress. When Congress rescinded a portion of the SFC funding • Six commercial scale projects are in operation in October 1984, $750 million was transferred to a fund or startup for the Clean Coal Technology Program. In December 1985 nearly $400 million was appropriated by Congress • Several pilot plants are demonstrating new for the first round of project awards. The purpose of technologies or expanding and improving cur- the clean coal program is to demonstrate technologies rent technologies that will enable the use of coal in an environmentally • Through the Clean Coal Technology Program, acceptable manner. Primary motivation for this pro- DOE is planning to provide assistance to at gram is the concern on an international basis with acid least nine future projects. rain. The program allows the Department of Energy to share up to 50 percent of the cost of a project with private industry. In February of this year, DOE requested that potential project sponsors submit proposals to the Clean Coal Technology Program. In April DOE received 51 proposals in response to their request. DOE selected nine projects on July 25, 1986 for potential support from the program. These projects are summarized in Table 2.

TABLE 2

PROJECTS SELECTED FOR ASSISTANCE IN THE FIRST ROUND OF DOE'S CLEAN COAL TECHNOLOGY PROGRAM

Sponsor Technology Project Location American Electric Pressurized Fluidized Bed Brilliant, Ohio Power Service Corpor- Combustion Combined Cycle tion-Columbus, Ohio Utility Retrofit Babcock & Wilcox Extended Tests of Limestone Lorain, Ohio Alliance, Ohio Injection Multi-Stage Burner Plus Sorbent Duct Injection Coal Tech Corpor- Slagging Combustor With Williamsport, tion-Marion, Penn- Sorbent Injection Into Pennsylvania sylvania Combustor Energy & Environ- Gas Reburning & Sorbent Springfield, Illinois Research Corporation Injection Retrofit Into Hennepin, Illinois Irvine, California 3 Utility Boilers Bartonville, lllinios Energy International, Steeply Dipping Bed Under- Rawlings, Wyoming Inc. ground Coal Gasification Cheswick, Pennsylvania Integrated with Indirect Liquefaction General Electric Integrated Coal Gasification Evendale, Ohio Company Steam Injection Gas Turbine Dunkirk, New York Cincinnati, Ohio Demonstration Plants (2) With Hot Gas Cleanup Ohio Ontario Clean Coal-Oil Coprocessing Warren, Ohio Fuels, Inc. Liquefaction The M.W. Kellogg Com- Fluidized Bed Gasification Cairnbrook, pany With Hot Gas Cleanup Pennsylvania Houston, Texas Integrated Combined Cycle Demonstration Plant Weirton Steel Cor- Direct Iron Ore Reduction Weirton, West Virginia poration to Replace Coke Oven/Blast Weirton, West Virginia Furnace for Steelmaking

1-17 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Future increase the use of both coal and oil shale resources within their borders. Lastly, California has had very Many questions can be asked regarding the future of the aggressive programs to provide security of energy sup- synthetic fuels industry in the United States. These ply within the state. questions include where, who, why, what, how, and, Energy research groups will also be an important factor most importantly, when? in the synthetic fuels industry. Two groups that are most actively pursuing synthetic fuels development Where? currently are the Electric Power Research Institute (EPRI) and the Gas Research Institute (GRI). Perhaps the easiest question to answer is where synthetic fuel projects will be located in the United States. In reviewing the many synthetic fuels program projects Lastly, synthetic fuels development in the United that have been proposed over the years, Pace has States must rely on private industry participation. Pri- determined that all projects are located close to the vate companies that will most likely be involved with resource base. Figure 4 shows the location of the synthetic fuels development are companies that have a projects that were proposed to the United States Syn- technology they wish to develop and market, or re- thetic Fuels Corporation. Although the projects were sources that they desire to utilize. The diversity of located nearly all over the United States, all projects these companies spans the gamut of size and back- were located close to the appropriate resource base. ground. Small companies such as Solv-Ex and Geokine- Who? tics are developing their resources and technologies. On the other end of the spectrum the largest companies in the United States are also active participants in the The next question that can be asked is who will synthetic fuels development. Despite this activity, the participate in the development of synthetic fuels in the amount of support from industry is drastically reduced United States. First, the federal government will be an from that of a few years ago. active participant in synthetic fuels development. Agencies within the federal government include the Department of Energy (DOE), the Environmental Pro- tection Agency (EPA), and the Bureau of Mines. Addi- tionally, the Bureau of Land Management will be in- Next, the question of why will these various organiza- volved in providing sufficient resources for the synthe- tions be involved in synthetic fuels development needs tic fuels industry. to be addressed. Perhaps surprisingly to some, Pace believes that environmental considerations will be a Other organizations that will be closely associated with large factor in the development of synthetic fuels in synthetic fuels development are state governments. the United States. In the past, environmental consider- This shift to involvement of state governments is fairly ations have been perceived to be a severe restriction on recent in United States history. State governments synthetic fuels development. However, concern over such as Ohio and Illinois have recently established acid rain is now a primary driving force to the Clean Programs to foster the use of coal within their borders. Coal Technology Program that is being administered by Kentucky and Indiana have had active programs to the Department of Energy.

1-18 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Another reason for organizations to be involved in TABLE 3 synthetic fuels is for security and diversification of energy supply. A third, reason for participating in synthetic fuels development is to control and provide METHODS TO ACHIEVE TECHNOLOGICAL some stability to energy prices. It has been long AND ECONOMIC ADVANCES recognized that the capability to produce synthetic fuels can act as a "cap" on energy prices.

The fourth motivation for synthetic fuels development S Research and Development is concern over the economy. This concern can be a factor at both the federal and state government level. - Catalysts Particularly state governments have recognized that - Environmental Control Systems synthetic fuels projects provide increased employment - In Situ Processing and increased tax revenues. On a federal level, synthe- - High Capacity Retorting tic fuels not only improve employment and taxes, but - Co-Processing also improve the balance of trade deficit that is currently a significant problem for the United States. S Demonstration Projects

A fifth reason for participating in synthetic fuels - On-Stream Factor development is to obtain a technological leadership - Efficiency (Equipment and Manpower) within the industry. This goal is the primary reason for - Design and Construction private industry participation in synthetic fuels. A - Mining and Materials Handling good example of this motivation is demonstrated by - Improved Financing Texaco which has been developing its coal gasification process for many years. Just recently Texaco has S International Technology Transfer successfully marketed its technology to several organizations, both in the United States and overseas. • Market Development The final reason for participation in the synthetic fuels industry is profit. Profit is the ultimate motivation for all potential synthetic fuels participants. However, this motivation is listed last by Pace because we believe that the sale of synthetic fuels products will not be profitable for several years. The downturn in prices for conventional oil and gas will certainly adversely affect With regard to coal, processing of coal with conven- the economics of synthetic fuels production in the near- tional oil or tar sands bitumen may provide cost reduc- term. tions for direct liquefaction processes. Also, methods that produce smaller quantities of oil from coal may reduce costs significantly. Such processes, which What? "skim" the easiest oil from the coal and then market the remaining char, are on the threshold of commercial If synthetic fuels are not now profitable, another ques- development. tion that should be addressed is what technological and economic advances can be achieved. A partial list is summarized in Table 3. Pace believes that research How? and development will certainly contribute to the development of synthetic fuels. Catalyst improvements may How can these advances be achieved? The development decrease the cost of producing coal liquids, and may of synthetic fuels requires several stages after the R&D also reduce the cost of refining synthetic fuel products level. These stages normally involve pilot plant con- into finished products. Environmental control systems struction and operation, testing of prototype or demon- also may be improved through R&D efforts. stration units, operation of first-of-a-kind pioneer commercial plants, and finally design and construction of Tests aimed at in situ processing of oil shale and oil standardized commercial plants. If any of the steps in sands will likely be conducted only at the R&D level for this technological development sequence are bypassed, the next few years. These processes may significantly risks in technology and economic viability may occur. reduce the east of producing shale oil and bitumen by reducing the quantity of ore and wastes that must be Currently, most efforts in the United States are at the handled. Several improvements in oil shale processing R&D and the pilot plant scale. Very few efforts are at may be achieved at the R&D level. These methods the demonstration and pioneer plant scale. However, include non-pyrolysis techniques using solvent extrac- demonstration plants and pioneer commercial projects tion, high capacity retorting methods using fluidized provide information on certain aspects of synthetic bed techniques, rapid heat-up processes, and hydrogen fuels production that cannot be acquired at smaller processing of Eastern oil shales. Attempts to concen- scales. This information includes equipment onstream trate the organic matter (referred to as beneficiation) operating factors, equipment and manpower efficiency, in oil shale and oil sands may also improve the cost of design and construction improvements, and materials synthetic fuels production. handling advances.

1-19 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The Synthetic Fuels Corporation conducted an analysis of production cost improvements that can be obtained by successful operation of commercial plants. They analyzed three industries to determine the production FIGURE 5 cost improvements: alumina manufacture, ammonia production, and low density polyethylene production. These three industries were selected by the SFC be- SFC'S ANALYSIS OF cause they have certain characteristics similar to the synthetic fuels industry. As shown in Figure 5, all LEVELIZED PRODUCTION three industries evidenced substantial improvements in cost. In general, per unit production costs declined 20 COSTS FOR THREE INDUSTRIES percent for each doubling of cumulative output. LIVELIZID LOPE pRoDuCTIot COSTS Iii. Lsrnin, Ran The SFC concluded that these cost savings are gener- Imo ated by three inter-related and inter-dependent sources. First, industry learns to build better plants, build them more efficiently, and operate them more Ar economically. Secondly, capacity performance and other factors are confirmed with each successful plant that is built. Third, uncertainties regarding perform- IN ance and economics are reduced thus allowing future projects to be financed at lower cost. Also, as industry builds and operates demonstration and pioneer plants, the optimUm size of the plants may become more apparent. Previously, industry believed 10 IN TWO 10.000 100.000 that large plants were necessary to achieve economies Acojnnujns boa.mc P..duct,on. .ndho., po.ma of scale. Plant capacities of approximately 50,000 to 100,000 barrels per day were perceived to be the most LEVELIZED ANIA POO4JCTION COSTS economical. However, experience showed that although 00.7% L.sn.n, Rat. smaller plants achieved less economy of scale, financ- t.000 ing costs were greatly reduced. Although experience with large-scale projects is US needed, with the downturn of interest in synthetic fuels in the United States, construction of first-of-a-kind pioneer plants becomes exceedingly difficult. There- fore, Pace believes that technology transfer from inter- To national projects will likely be necessary to provide this information. An excellent example of international technology transfer is the successful operation of the tO IN I.ow III'm IOO.WO Great Plains project. Technology for this plant was Accw,Sd Oomei,c Pmd.jct,on. the.aand wni viably transferred from the Sasot project in South Africa. Other examples that may occur include the construction and operation of an oil shale plant in LEVELIZEO ALUMINA PRODUCTION COSTS Australia. Oil shale in Australia has fewer difficulties with intrastructure, water supply, mining, and environ- Antn.Ltain.RM. mental impact mitigation than in the United States. 200 Thus, an oil shale plant in Australia will likely be economically viable sooner than in the United States. Another example could be the oil sands experience in Canada. The process for extracting bitumen from oil 100 sands may not be directly transferred to the United States, but mining and materials handling experience could certainly be beneficially transferred from Canad- 50 ian projects. IaWO WON Acew,.uIa:.d Doamnc Production International technology transfer will also likely con- ITho.n.ad T. of Ah.uaum) tinue to be a two-way street, with United States organizations providing expertise to overseas projects. Surface coal gasification projects are currently planned Lastly, an often overlooked aspect of how the synthetic using both Texaco and KRW technologies. Underground fuels industry must develop is the establishment of a coal gasification tests using the Controlled Retracting market for synthetic fuels. An example of this need for Injection Point (CRlF) technology are also progressing. market development is the efforts to increase the use of methanol as a motor fuel in the United States. Other examples include the use of raw shale oil as

1-20 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Conclusions boiler fuel rather than refining the shale oil to finished products. Also, the Air Force is actively pursuing the From this analysis Pace has concluded that a great deal use of synthetic fuels for high-density aviation fuels. of progress has been made in the United States synthetic fuels industry in the last 15 years. Several commercial plants have been built and are in operation that When? demonstrate different technologies for synthetic fuels production. However, further efforts are needed to Having analyzed the other factors in the development make the synthetic fuels industry economically viable. of a synthetic fuels industry in the United States, the A great deal of work remains to be done. In today's final question is when will the industry become estab- climate of federal government concern over the deficit, lished? Figure 8 shows Pace's forecast for crude oil and corporate concern over the balance sheet , a great price on the Gulf Coast. As shown in the figure, prices deal of commitment is needed from both government in the year 2000 could potentially vary between $20 and and industry. $40 per barrel. These prices are noticeably less than the subsidized prices ($40-$60 per barrel) for the syn- However, Pace believes synthetic fuels do have a future thetic fuels plants that were supported by the Synthetic in the United States. Fuels Corporation. However, if synthetic fuels production costs are reduced as determined by the SFC analysis, expected costs may be in the range of $25 to $35 per barrel. Hence, synthetic fuels in the United States may become viable as soon as the late 1990s. However, an equally plausible price scenario implies CHEVRON FORECASTS ADEQUATE ENERGY that synthetic fuels will not be economical until well THROUGH 2000 into the 21st century. Only time will tell which price forecasts shown in the figure will justify development In June 1986 the Economic Department of Chevron of synthetic fuels in the United States. Corporation released its latest energy forecasts in World Energy Outlook. This publication is the latest in a continuing series of annual forcasts to 2000 that Chevron has prepared. (Previous forecasts have been summarized in the Pace Synthetic Fuels Report on page 1-29 of the September 1984 issue and page 1-23 of the September 1985 issue.) Highlights of Chevron's 1986 forecast for the non- Communist countries are as follows, with 1985 forecasts shown in parenthesis: • Total energy consumption will grow at an average annual rate of 2.1 percent per year (versus 2.2 percent in last year's forecast). This rate is approximately two-thirds of the GNP rate of 3 percent per year. • Total oil consumption will grow at 1 percent per year, slightly less than one-half the rate for total energy (the same rate as in the 1985 forecast). • Oil production capability will exceed demand with OPEC share rising from 40 percent of total supply in 1985 to 55 percent in 2000. • Crude oil prices are expected to stabilize in 1987 in the $20 to $25 per barrel range. Prices One aspect of the synthetic fuels industry in the United are then expected to remain at this level until States that could affect the timing is the real cost of the 1990s when increased demand will place imported energy. The cost of imported energy is upward pressure on prices. Chevron expects actually much higher than the apparent cost. If energy prices in the $28 to $35 per barrel range by is produced domestically, benefits such as balance of 2000. trade and taxation and royalty revenues accrue to local, • Natural gas consumption will grow at an aver- state, and federal governments. Energy that is im- age rate of 2.2 percent per year. Prices paid by ported from outside the United States does not provide end-users are expected to be competitive with these incomes. Some experts estimate that the real fuel oil by 1990. cost of imported energy is actually up to three times its apparent cost when equitably compared to domestically • Coal consumption will grow at 3.0 percent per produced energy. Recognition of this factor by govern- year (3.2 percent per year growth was forecast ment could speed development of the synthetic fuels in 1985) with prices rising with inflation. industry.

1-21 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Chevron also included a "cycle" case, where price • Nuclear power will grow at a 4.5 percent annual cycles are caused by lagged adjustments in supply and rate mostly in Europe and Asia (the 1985 fore- demand to swings in the business cycle or from a cast called for 5.6 percent annual growth). political event which disrupts supply or demand. • Synthetic liquids are not expected to contribute Economic Growth and Energy Demand a significant volume by 2000 (in 1985 Chevron estimated I million barrels per year would be Chevron forecasts the world economy to grow 3 percent produced by 2000). per year from 1986 to 2000, energy demand will increase only slightly more than 2 percent per year due to lingering conservation, substitution, and efficiency Oil Price gains. Non-oil resources will supply three-quarters of the increase in energy use. Consequently, oil demand Chevron presented three different crude oil price scen- growth is expected to be one-half the rate of energy arios in their World Energy Outlook. The three differ- growth and one-third the rate of GNP growth. ent scenarios are shown in Figure ..!. It Is important to note that while Chevron presented three different out- looks the supply/demand balances that follow are based United States on the "high trend" case. Over the long run, the United States economy is fore- The "high trend" case assumes re-establishment by 1987 cast to grow 2 to 3 percent per year. Because conser- of prices in the $20 to $25 per barrel range. There- vation and efficiency improvements will continue to be after, prices firm moderately throughout the 15 year important, total energy growth is expected to average horizon to $28 to $35 per barrel in response to gradual only 1 percent per year. Oil consumption will increase improvement in economic growth. After the end of the at an average rate of only about 0.5 percent per year to century, prices would continue to rise, reflecting the the end of the century. Most of the growth in oil will higher cost of developing less accessible deposits, until result from rising highway diesel fuel consumption and they are limited by the cost of producing synthetic greater use of residual fuel oil. Natural gas consump- fuels such as oil from coal or shale. tion is forecast to remain flat for the rest of the century. Increases in coal consumption, principally for In the "low trend" case, OPEC producers try to regain -power generation, will account for more than one-half lost market share and maintain it. Prices in this case of the increase in United States energy consumption. start in a range of $10 to $15 per barrel in 1987 and rise Nuclear electric generating capacity will expand by to $18 to $22 per barrel by 2000. one-third during 1986 and 1987 but will increase only slowly after 1987 because additional new facilities have not been planned. United States energy consumption by type of fuel is shown in Figure 2.

FIGURE I

CHEVRON'S FORECAST S ARABIAN LIGHTCRUDE

60 r-

so-

to 30

'LOW TREND I 1970 •1 Ll75 85 90 95 2000

1-22 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 2 CHEVRON'S FORECAST OF U.S. ENERGY CONSUMPTION

60 - 'U -J 'C > 50 — - S SOLAR/BIOMASS HYDRC 40- a 0 00

o 3 COAL

0 20 — ___ GAS -

10 — OIL - I I I I I 1970 75 80 85 90 95 2000

Canada faster than energy in general at, 2.2 and 2.5 percent per Canadian oil consumption will grow at only 0.6 percent year, respectively. per year while total energy growth will average about 1.5 percent per year for the remainder of the century. Most of the growth will be provided by electricity South and East Asia generated using non-oil sources, particularly hydro- electic, coal, and nuclear power. Chevron expects GNP growth averaging over 5 percent per year through 2000. Energy consumption will grow with the economy, averaging 5.1 percent per year. Oil Western Eunope consumption is expected to grow an average of 2.5 percent per year to 2000 even with an effort to reduce the GNP growth will average 2.5 percent per year while area's dependence on oil. energy growth is expected to average 1.7 percent per year. Oil consumption growth at 0.6 percent per year Coal will become the largest source, growing more than will not be sufficient to keep oil's share of total energy 6 percent per year to nearly 38 percent of total energy from declining from 45 to 38 percent by 2000. Oil demand in 2000. Natural gas demand will increase at consumption is expected to increase as a result of a an average rate of 8.4 percent per year supplying continued growth in transportation fuels and a gradual 16 percent of total energy in 2000. Nuclear power will stabilization of residual fuel oil in all sectors. increase 8.3 percent per year, reaching 5 percent of total energy by 2000.

Oceania GNP growth is expected to average 4 percent per year. Energy consumption growth will be at about one-halt Real GNP growth of about 3 percent per year through the GNP rate, 1.9 percent per year to 2000. Electricity 2000 is expected. Energy consumption will keep pace demand will increase 3.2 percent per year. Total oil with economic growth, increasing 2.8 percent per year. consumption will increase at an average rate of 0.5 per- Oil consumption, however, will grow at about one-half cent per year, with oil's share of total energy declining the rate of energy as a whole, declining to 33 percent from approximately 57 percent in 1985 to 47 percent in of total energy in 2000. 2000. Both coal and natural gas consumption will grow

1-23 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Along with Australia, New Zealand is also developing consumption is forecast to grow at 3.7 percent per coal for electric generation. Regional use will increase year, while coal will grow only 1.2 percent per year. an average 4.1 percent per year, providing 39 percent of total energy in 2000. Natural gas is growing at Eastern European energy consumption is expected to 3.9 percent per year, and will account for 20 percent of average just over 2 percent per year to 2000. Oil the total by 2000. consumption is forecast to decline about 0.5 percent per year; natural gas consumption will grow at 3 percent per year, and growth will be slightly less than Middle East 2 percent per year.

The fighting in Lebanon and the Iran/Iraq war will China continue to result in political instability in the region. Once these hostilities subside, these economies are expected to grow rapidly for a few years due to China's economy is expected to grow at 4 to 6 percent reconstruction activity. per year through 2000. Total energy consumption will increase about 4.4 percent per year until 2000, with oil Economic activity is expected to recover by the mid- growth at 3.5 percent per year. Coal use will grow an 1990s, when world oil demand increases. With over average 4.3 percent per year, with natural gas continu- one-half of the world's proven crude oil reserves ing to be of relatively minor importance. located in the Middle East, countries in this region have a major role as long term oil suppliers, according to Chevron. Energy Supply Total energy demand is expected to increase 3.7 per- Chevron estimates that under their "high trend" price cent per year over the forecast period. Oil will be the scenario there will be sufficient supplies of conven- dominant energy source growing 2.1 percent per year; tional crude oil and natural gas liquids to meet demand however, it will contribute only 58 percent of total through 2000. They project crude oil production to energy consumed by 2000 compared to 74 percent cur- grow 1.0 percent through 1990 and 1.5 percent in the rently. Natural gas, used in water desalination, power remainder of the 1990s. As Figure 3 shows, Chevron plants, and in the petrochemical industry, will be the expects non-OPEC production to decline steadiliy to fastest growing energy source (7.3 percent per year), 20.4 million barrels per day by 2000. OPEC production increasing to 39 percent of energy consumption in 2000 will rise over this time to 26.5 million barrels per day. from 23 percent. United States production will decline from 8.8 million Saudi Arabia is pressing ahead with development of the barrels per day to 6.2 million barrels per day over the non-associated gas reserves in the Khuff Zone. Natural forecast period. As Figure 4 shows, Chevron estimates gas consumption is expected to account for 38 percent the United States will be importing over 50 percent of of total consumption in 2000 compared to 16 percent in its oil requirements by 2000. Canadian crude oil 1985. production will decline slightly by 1990 then grow to 1.5 million barrels per day by 2000. Mexican crude oil Africa production is expected to reach 4.2 million barrels per day by 2000, while Western European production is Growth in energy consumption in Africa is expected to projected to remain flat through 1990 at 3.7 million average about 3 percent per year primarily in Algeria, barrels per day and then decline to 2.8 million barrels Egypt, Libya, Nigeria, and South Africa. South Africa per day by 2000. is the continent's largest energy consumer, accounting for nearly 40 percent of the region's total energy con- United States natural gas production is projected to sumption of which 80 percent is provided by coal, decline throughout the forecast period. The current including its Sasol synthetic liquids-from-coal program. natural gas "bubble" in the United States, now estimated at 2.5 trillion cubic feet per year, should dissi- Oil is the dominant fuel in Africa (1.4 percent per year pate near the end of this decade. Imports, by the turn growth), although natural gas (growing at 8 percent per of the century, will account for almost 20 percent of year) is expected to gain market share. United States supply. Canada will continue to supply the bulk of the imports with smaller amounts coming Latin America from Mexico and Algeria. GNP growth for the region will average about 4 percent Western Europe's natural gas production will grow at Per year, while energy growth will be about 3.5 percent about 0.5 percent per year over the forecast period. per year. Oil will be the slowest growing energy source The Netherlands will be the largest producer in 2000 (2.3 percent per year), but will still provide about but its production will decrease while production from 48 percent of the region's energy needs by 2000. the United Kingdom and Norway will increase. Natural gas production from the Middle East will in- Soviet Unio and Eastern Europe crease by almost 300 percent over the forecast period, with most of the gas consumed domestically. Energy consumption will increase 2.5 percent per year, slightly faster than economic growth. Oil consumption will increase only about 1 percent per year. Gas

1-24 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 3 CHEVRON'S FORECAST OF CRUDE OIL PRODUCTION NON—COMMUNIST WORLD 60 — -

co :30— OPEC - 0 20 — fl ICO MEXICO 10 79. 7EUR Op UNITED STATES 1970 80 90 2000

FIGURE 4 CHEVRON'S FORECAST OF U.S. OIL SUPPLY AND DEMAND

NET IMPORTS z lo

ONSHORE PRODUCTION - 5 -

MGI'S & OTHER PRODUCTIONS I I I I I 1970 75 80 85 90 95 2000

1-25 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ECONOMICS

alcohols processes yield a product containing at least SYGMAL PROCESS IS ATTRACTIVE FOR 50 percent methanol and in some cases significantly PRODUCTION OF COSOLVENT ALCOHOLS more. FROM SYNGAS The mandated reduction of lead in gasoline will create According to Fluor the importance of this low-methanol a need for additional and new sources of octane. Many feature of the Dow/UCC process is twofold. First, solutions exist to replace the lost lead octane and using (with today's oversupply of low cost methanol) it will be high octane, non-lead additives is one of the simplest. most economical to use as much externally produced In a paper presented at the "Carbon One Chemical methanol as possible in a blend with the cosolvent Technology" symposium, arranged by the Institute of mixed alcohols. Secondly, the Sygmal Process does not Chemical Engineers in London, Fluor Technology Inc. depend on outside methanol and has the flexibility to discussed "The Sygmal (Syngas to Mixed Alcohols) Pro- produce alcohol blends containing methanol and cosol- cess." The Sygmal process is a technology developed by vent higher alcohols at any ratio within the range of Dow Chemical Company and Union Carbide, which commercial interest for gasoline blending. yields a high value liquid product having excellent octane. The paper also explores the applications, markets, and economics of using mixed alcohols and The Sygmal Process methanol as an octane additive in gasoline blends. The Dow/UCC Sygmal Process converts synthesis gas to a liquid product containing methanol and a mixture of Potential Sources of Octane higher alcohols. The process' flow scheme, is similar to conventional methanol technology. Methanol with its research octane number (RON) of 130 to 135 has good potential as an octane enhancer but The process uses sulfide-based catalysts developed by methanol use in gasoline has certain problems. The Dow and Union Carbide. These catalysts have good major problem relates to the trace amounts of water selectivity to the production of alcohols, producing only contained in most gasoline storage tanks. The water a low amount of essentially gaseous by-products. The does not affect the water-insoluble hydrocarbon-based process is designed to be energy self-sufficient. The gasoline, but when methanol is present, the methanol natural gas provides not only the feed material but the migrates into its water phase and its octane and fuel energy necessary to operate the plant as well. values are lost from the gasoline. Fluor researchers state that a solution to the problem is to add small Fluor's researchers felt that another important feature amounts of other alcohols to act as a cosolvent to of this process is its simple product drying scheme. The inhibit the water phase of methanol. use of molecular sieves to remove the water produced in the synthesis reactor is relatively inexpensive and The price of the cosolvent and the ratio of methanol to avoids complex distillation drying techniques. the cosolvent alcohol have a major impact on the economics of using such blends. Because the cosolvents Figure 1 illustrates the primary processing steps of the are more expensive than methanol, it is desirable to Dow/UCC Sygmal Process. Natural gas is converted to minimize their use and maximize methanol in the synthesis gas, a mixture of carbon oxides (carbon mono- gasoline blend. The allowable methanol concentration xide and carbon dioxide) and hydrogen. The syngas Joins and the methanol-to-cosolvent ratio are usually con- the recycle gas and goes to the carbon diodde removal trolled by law and vary, ranging between 1:1 (used in section. A large part of the carbon dioxide removed is the United States for several years) and 2:1 (recently recycled to partial oxidation for control of the hydro- accepted by the United States Environmental Protec- gen/carbon monoxide ratio in the syngas. The tion Agency). Mixed alcohols have good potential as a remainder is purged. cosolvent because they arc competitively price and their supply is not limited because they are produced The syngas is fed to the mixed alcohols synthesis from abundant natural gas. reactor section where it is converted to methanol and higher alcohols. The alcohol products are condensed, and the unreacted syngas is recycled to the carbon Potential for Use of Externally dioxide recovery section. The liquid alcohols stream Is Produced Methanol sent to a stabilizer column for removal of light paraffins entrained or dissolved in the liquid. The stabilizer Mixed alcohols production technologies are offered by a bottoms product flows to the molecular sieve drying number of licensors in Europe and the United States. system where the small quantity of water remaining In Fluor's analysis indicates that the Sygmal Process the liquid product is removed. developed by Dow Chemical Company and Union Car- bide Corporation has a distinct advantage. Aside from the alcohols synthesis section, the processing operations in the plant—partial oxidation, oxygen The Sygmal Process is the only process with the ability production, carbon dioxide removal, molecular sieve to achieve a methanol content in the product as low as drying, etc. re conventional and well-proven techno- 20 or 30 percent. Virtually all of the other mixed logies.

1-26 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

FIGURE 1 DOW/UNION CARBIDE SYGMAL PROCESS

CO2 PURGE (IF NEEDED) SULFUR RECOVERY CO RECYCLE (IF NEEDED) SULFUR PRODUCT

MIXED SYNTHESIS SYN GAS CO2 GAS ALCOHOLS REMOVAL NATURAL GAS GENERATION SYNTHESIS OR HEAVY OIL OR COKE GAS RECYCLE

GAS PURGE UNREACTED GAS ALCOHOLS CONDENSA- TION

MOLECULAR SIEVE TABILIZATIO MIXED ALCOHOL PRODUCT DRYING

Unlike the methanol reaction, the fuel alcohols reaction There are a number of options in using the Sygmal Process. The feedstock can vary from natural gas to is not limited by equilibrium, so reactor temperature control becomes much more critical. If the original coke and coal. The heavier feedstocks can be used methanol reactor is of the quench-type, Hakki recom- without significant process adjustment, but the lighter mends replacement with an isothermal reactor. At the feedstocks are likely to be more economical. The Sygmal Process can provide significant quantities of same time, this replacement would allow the reactor to PUTS flycirogen when steam reforming is used as the operate at higher temperature and produce higher pres- source of synthesis gas, and it can be retrofitted to - sure steam. methanol or ammonia plants. If the original methanol reactor is of the isothermal In a related paper presented at the MChE 1986 Spring type, the decision to replace the reactor would be National Meeting, Adel Hakki of Union Carbide dis- heavily dependent on the design pressure and tempera- cussed the potential applications of the Sygmal Process ture. Higher pressures and temperatures increase the and emphasized the opportunities for retrofitting reaction rate and allow achievement of the desired methanol plants. conversion with a less active catalyst. The authors provide a more active catalyst, so that the desirable rate and selectivity can be achieved within the existing Retrofit Options temperature and pressure limits. Use of the existing reactor pressure allows the use of existing equipment According to Hakki, there is no single, "best" retrofit for synthesis gas compression, recycle compression, design. The optimal design will depend on the configur- heat exchange, and product condensation. ation and design operating conditions of the original methanol or ammonia plant, the cost of feedstock, and In his presentation Hakki discussed three methanol the owner's trade-off between retrofit investment and plant retrofit cases, all designed to produce a mixed operating cost. alcohol product containing 50 percent methanol by weight. The methanol plant can be completely converted into the production of mixed alcohols or the original methanol plant can remain intact and an adjunct faci- Case 1 can be used for either an invasive retrofit of a lity for producing mixed alcohol from diverted natural methanol plant or for providing the capability of pro- gas is provided. ducing mixed alcohols as an adjunct to a large existing methanol plant. Natural gas and steam are the feed- A fundamental choice must be made in a methanol stocks to produce fuel alcohols, hydrogen, and synthesis plant retrofit on whether to use the existing reactor. gas. This decision depends on the type of reactor and the design pressure and temperature limits.

1-27 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Case 2 uses an external source of carbon dioxide to lower the hydrogen/carbon monoxide ratio in the syngas TABLE 2 from the recycle. The feedstocks are natural gas, steam, and carbon dioxide, with carbon dioxide recycle to create fuel alcohols. TYPICAL GASOLINE BLENDING PROPERTIES OR PRODUCT FROM SYGMAL PROCESS Case 3 is similar to Case 2 except the carbon dioxide is created internally. Methanol/Higher Alcohol (By Volume) 70/30 50/50 Ammonia Plant Retrofit D RVP 44 33 The authors also discussed a scheme for retrofitting an ASTM D-86 (% Evaporation at): ammonia plant. There are a number of attractive 100°F 17 9 features about an ammonia plant retrofit: 158°F 154 150 212°F 104 112 • The ammonia plant's secondary reformer can be 356°F 50 102 converted into a partial oxidation reactor to Octane Numbers:(3) achieve the desired hydrogen/carbon monoxide In Regular Unleaded: ratio by replacing air with oxygen. RON 132 130 • The carbon dioxide removal facilities in the MON 94 94 ammonia plant can be used to remove carbon In Premium Unleaded: dioxide for recycle in the mixed alcohols facility. RON 132 129 MON 88 88 • The ammonia plant air compressor can be used for carbon dioxide recycle service. 1. Properties are for 7.14 volume percent of the alcohol in gasoline Product Characteristics 2. Properties are for 8.40 volume percent of the alcohol in gasoline A wide range in the methanol content of the product is 3. These blending octane numbers are for United possible by changes in the reactor operating conditions States grades of gasoline with the following and/or by methanol recycle. Table 1 shows typical octane numbers: compositions of the Sygmal product at different methanol contents. Table 2 shows typical gasoline blending Unleaded Unleaded properties for two different methanol concentrations. Regular Premium RON 94.8 TABLE 1 98.9 MON 83.1 84.4

TYPICAL COMPOSITION OF MIXED ALCOHOLS PRODUCT FROM SYGMAL PROCESS (Percent) Potential Markets

The authors cited a number of potential markets for the Methanol/Higher Alcohol 70/30 Jj (By Weight) Qfl Sygmal Process, including: the production of fuel alcohols in areas with cheap natural gas, the production of fuel alcohol at remote sources of natural gas, the Methanol 70 50 30 retrofit of existing methanol or ammonia plants to fuel Ethanol 25-30 25-30 30-45 Propanol (100% Normal) alcohol production as a gasoline and octane-enhancing 2-5 10-15 15-30 supplement, and the production of fuel alcohol from Butanols (80% Normal) 0-3 2-6 5-10 residual oil, refinery oils, coke, or coal. C5 and Alcohols 0-1 0-2 0-3 Total ioo 100 100 It is difficult to generalize about the viability of the retrofit market in the United States, Canada, and Western Europe. Table 3 shows some of the factors In addition to the above alcohols, the product will influencing the viability of the retrofit of methanol contain trace methyl acetate, about 0.25 percent plants. Table 4 shows the economics for the retrofit of ethyl acetate, and 0.4 percent water which can be a methanol plant in the United States using the Sygmal adjusted through design of the drying system. technology when crude price is $20 per barrel, and assuming that the evaporative index restriction in the DuPont Waiver is eliminated. The authors concluded that an attractive return is Possible —particularly if the configuration of the original methanol plant allows for an easy retrofit.

1-28 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 3 TABLE 4

FACTORS INFLUENCING THE ECONOMIC ECONOMICS OF RETROFIT OF 1,000 MTPD VIABILITY OF METHANOL PLANT RETROFITS METHANOL PLANT TO FUEL ALCOHOL USING SYGMAL TECHNOLOGY

• The configuration and operating conditions of the methanol plant Basis; • Crude oil at $20 per barrel (natural gas at an equilibrium value of $2.09 million BTU) • Natural gas (or other synthesis gas feedstock) price relative to crude oil price • Retrofitted plant produces Si million gallons per year of mixed alcohol containing • The value that can be assigned to co-produced 50 percent methanol which is diluted with hydrogen additional methanol to produce a 2/3 metha- • The extent of the octane shortage due to lead nol product as per the DuPont Waiver. phase down Retrofit Investment, MM$ 25-50 • The characteristics of the buyer who will blend the Variable Costs, 4!/Cal fuel alcohol into gasoline, e.g.: 24 Fixed and Overhead Costs, t/Gal 17 - A crude-rich or crude-short refiner Total Cash Costs, t/Gal 41 - Owning high- or low-complexity refineries Value of 50/50 Product, t/Gal - The ability of independent distributors to 56" blend specification gasoline using fuel alcohol (which In turn depends on the availabi- *Assumes chemical value for by-product purified lity of tailored base gasoline) hydrogen • In the United States, the final resolution of the EPA "Assumes DuPont Waiver blend (2/3 methanol) is volatility restrictions in the DuPont Waiver. worth 49 cents per gallon

•100

1-29 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TECHNOLOGY

CO-PROCESSING STUDIED FOR UPGRADING Currently, heavy petroleum residua characterized by LOW GRADE FEEDSTOCKS high metals content and high coking propensity can be processed by either carbon-rejection technology such as In the future refiners will have to consider processing delayed or fluid coking; by hydrogen-addition techno- bottom-of-the-barrel feedstocks to a much greater ex- logy such as fixed-bed or expanded-bed hydrogenation; tent. A serious decline in light oil production and light or by combinations thereof. LCI disclosed two co- oil "find" rates in the Western Hemisphere and in the processing applications based on hydrogen-addition North Sea, along with the politically-controlled avail- technology. ability of Middle East petroleum supplies indicate that there is a need for technology that will give the refiner Current commercial residuum hydroprocessing techno- greater flexibility in feedstock selection and process- logies limit conversion to 50 to 60 percent distillates. ability. At the American Chemical Society's Spring The unconverted residual from the hydrotreater is Conference in New York, Lummus Crest, Inc. (LCI) either processed further in a coker to recover addi- presented a paper on the co-processing of petroleum tional distillates and coke or blended off with available feedstocks with other more plentiful and less costly low sulfur fuels. The unconverted residuum from fuels, one route to satisfying the refiners' needs. catalytic hydrogenation has potentially good properties as a solvent for liquefaction of coal, biomass, and oil LCI has formulated a concept for co-processing shale. bottom-of-the-barrel oils with coal and other solid carbonaceous feedstocks to produce high quality distil- Figure 1 is a schematic flow diagram of a co-processing late fuels. The concept is based on a two-stage scheme for utilizing the unconverted residual from a approach in which the solid carbonaceous feedstocks residuum hydrotreater. The short contact time (SCT) are converted to liquids in a thermal reaction zone thermal reactor system has been demonstrated in LCPs without any externally-supplied catalysts followed by Integrated Two-Stage Liquefaction (ITSL) process catalytic hydroprocessing of the thermal stage products development unit as well as at the Wilsonville pilot together with petroleum in an expanded-bed hydro- plant, both on coal products only. The SCT concept is treater. The unconverted solids from the thermal based on the fact that the rate of activation of fossil- reactor can be removed by known solids separation derived oil precursors is relatively fast with respect to techniques, such as Anti-Solvent Deashing (ASDA), the rate of hydrocracking of these intermediate pro- prior to upgrading in the expanded-bed hydrotreater. A ducts to all distillate products. The ITSL process distillate fraction from the hydrotreater can be recy- "decouples" the primary fossil liquefaction step from cled to serve as the slurry vehicle for the solid carbon- the secondary hydrocracking step. aceous feedstock. LCI has projected that there will be capital cost savings in a commercial plant in which the primary liquefaction Coal step is carried out in a relatively low-cost, fired-coil reactor system as compared to a larger, high pressure Co-processing of heavy petroleum residua and coal has soaker-reactor system. Furthermore, the more capital- been the subject of a 33 month experimental program intensive catalytic step could then be optimized to currently being carried out at LCPs Engineering Devel- hydrocrack the extracts without being constrained by opment Center under joint funding with the United the need to simultaneously solubilize the solid carbona- States Department of Energy (DOE). LCI envisions a ceous feedstock. common reaction system that can co-process petroleum residua with other carbonaceous feedstocks, such as oil shale and biomass, in addition to coal.

FIGURE I

ALTERNATIVE CO-PROCESSING FLOWSCHEME FOR COAL AND HYDROTREATED RESIDUA

RECYCLE GAS OIL

COAL FIXED BE I I ______LOW 6(0 F - REACTION SEVERITY J, NY DR 0- SYSTEM CRACKING LC-FINING r..DISTILLATES

HYDROTREATED RESIOUUM tRESIDUE TO GASIFICATION

1-30 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

An alternative co-processing application is shown sche- LCI's previous efforts demonstrated that hydrogen addi- matically in Figure 2. LCI predicates this application tion or hydroretorting technologies can result in signifi- on the following (actors: cantly higher oil yields from Devonian shales than can be achieved by thermal retorting technologies, on the • The feedstock cost of liquid products from the order of 200 to 250 percent of Fischer Assay. LCI hydroliquefaction of coal, oil shale, and biomass conducted preliminary screening tests in the batch is significantly less than that of petroleum as autoclave reactor system at LCI's Engineering Develop- seen in Table 1. ment Center. The tests simulated the SCT reaction system in which the oil shale samples were first • A raw syncrude can probably be generated in a extracted under short contact time conditions. This thermal reaction system, at competitive costs step was followed by blending the SCT products with an with that of imported petroleum crude oil when Arabian Heavy vacuum residue and hydrotreatment in the conversion units are constructed and oper- an LC-Fining simulation test unit. ated adjacent to a large petroleum refinery. • Studies indicate that beneficial synergism oc- LCI also concluded that a commercial-scale application curs during catalytic hydrotreatment when co- of hydroretorting technologies has potentially favorable processing synfuels products from an SCT reac- economics. The LCI co-processing concept represents a tor with vacuum residua. The synergism may possibly near-term economic reality when applied in an be increased distillate yield and/or improved over-the-fence relationship with an interested refiner. desulfurization/demetallization at conventional By way of example, LCI assumed an existing hydro- hydrocarcking operating seventies. cracker is processing a virgin residual oil priced at $25 per barrel. For the case of a 54,000 barrels per thy • There should be no significant deterioration of unit, if 20 percent feed (10,800 barrels per day) is the hydrogen content-molecular weight rela- backed out and replaced by 10,800 barrels per day of tionship of the distillate products when the shale liquids, there should be no significant deteriora- syncrude content of the combined feed to the tion of the distillate product characteristics. The co- hydroeracker is less than about 20 percent. processing liquids should respond in downstream refinery processing units essentially similar to that of the straight run petroleum-derived liquids. Devonian Shale Resources With oil shale priced at $4 per ton and residual at $25 LCI feels that the Devonian oil shale resource of the per barrel, the differential cash flow available for (a) Kentucky-Ohio-Tennessee region of the United States amortizing the capital equipment associated with shale has the potential of providing a significant percentage preparation, spent shale disposal and the SCT reaction of our refinery feedstock needs. Until recently, eastern system and (b) operating costs is estimated to be about United States oil shales were considered unsatisfactory $64 million per year. Assuming 20 percent capital resources because of their relatively low oil yields in charges and operating costs of $5.75 per ton, this cash the Fischer Assay test and in conventional retorting. flow would correspond to an installed capital cost for Fischer Assay oil yields obtained with the Devonian the upstream shale processing equipment of about shales are less than one-half of those obtained from the $140 million. Eocene shales (Green River formation) of Colorado, Utah, and Wyoming.

FIGURE 2

ALTERNATIVE CO-PROCESSING FLOWSCIIEME FOR COAL AND VIRGIN RESIDUA

RECYCLE (GAS OIL/97S F..) I i ISEPARA- FIXED SEal 550 F - • a TORS p LOW HYDRO-'DISTILLATES COAL RE •I SEVERITY I CRACKING SY 14LC-FINING

U RESIDUE TO GASIFICATION p VIRGIN RESIDUUM

1-31 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

Biomass Resources LCI feels that it may be feasible to justify the economic tradeoff between the differential values of petro- Biomass materials, either virgin in nature such as trees, leum feedstocks and municipal solid waste (MSW) tip- crops, and vegetation, or as waste such as refuse- ping fees. However, because of the smaller capacities derived fuel (RDF) represent an energy source much associated with MSW collection and classification, co- like conventional fuels. They vary in composition, processing of petroleum residua and liquids derived density, heating value, and other properties. Recycling from MSW would probably be limited to refinery hydro- them as industrial fuel has the advantage of minimizing treaters having capacities below about 20,000 barrels the severe and continuing problems associated with per day. Furthermore, because the feedstock would solid waste disposal. The total estimated quantity of contain less synthetic fuel, the co-processed liquids organic wastes generated in 1980 in the United States would be more petroleum-like and thereby pose less was about 1,150 million tons. Approximately 15 per- potential problems to the refiner. A similar analysis cent is potentially recoverable and assuming a typical can be performed of the co-processing of petroleum heating value of 5,000 BTU per pound, this energy residua with wood chips derived from forest wastes, displacement might be equivalent to 1.2 by 1018 Joules according to LCI. per year or 1.1 quadrillion BTUs per year (500,000 barrels oil equivalent per day) when converted to useful Some preliminary screening tests were made in the fuels. batch autoclave reactor systems, utilizing two biomass feedstocks: pine wood flour and dust RDF. LCI lists two fundamental methods of biomass conversion to clean fuels: thermochemical and biochemical conversion. The thermochemical route has the following potential advantages over that of the biochemical route:

• Existing infrastructure for petroleum-like fuels • Higher thermal efficiency • Wider applicability to feeds containing lignins and contaminants (e.g., MSW) • Production of completely detoxified products • Access and similarity to the advanced state-of- the-art technologies utilized in the petroleum/petrochemical/coal industries.

TABLE!

FEESTOCK COSTS FOR LCI CO-PROCESSING

Feedstock Typical Typical Feedstock Cost of Feedstock Liquids Yields Transfer Price Raw Liquids Thousand $/MM m3/kg J/ $/Ton BTU $/M3 $/8bl Bituminous Coal 0.70 168 0.033 30 1.25 47 7.50 Kentucky Shale 0.10 24 0.004 4 0.68 44 7.00 Wood Chips 0.50 120 0.022 20 1.40 44 7.00 Municipal Solid Wastes 0.25 60 0.009* 8 0.85 (35) (5.60) * Denotes tipping fee paid by solid waste collector Denotes credit for MSW feedstock against product liquids

1-32 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 INTERNATIONAL

NEW ZEALAND SYNTHETIC GASOLINE PLANT The gas-to-gasoline project concepts were developed STARTED UP, BUT ECONOMICS QUESTIONABLE under the terms of a 1980 Government/Mobil Memoran- dum of Understanding. By this agreement a Joint The New Zealand natural gas-to-gasoline plant was Executive Committee prepared a report, completed in mechanically completed in June 1985, and the first July 1981, that concluded that the venture was techno- gasoline was produced on October 17, 1985. Nameplate logically feasible and commercially attractive. The capacity production was achieved in January 1986. Government and Mobil concluded the various contracts Despite these technical successes, the new administra- in February 1982. tion in the New Zealand federal government has recently begun attacking the previous administration's deci- It was agreed that the plant would be owned and sion to build the plant. operated by the New Zealand Synthetic Fuels Corpora- tion Ltd. (Synfuel) of which 75 percent is owned by the government and 25 percent by Mobil. Mobil contracted Project Description to provide technical and management services to the company. The New Zealand Synthetic Fuels Corporation Ltd. (NZSFC) was incorporated in September 1980 with the The company operates on a tolling basis, with the objective of designing, constructing, and operating a Crown supplying the natural gas to the plant for pro- plant to convert natural gas owned by the Crown into cessing into gasoline. Title to the hydrocarbons re- gasoline for a processing fee. Gasoline produced from mains with the Crown, which sells the gasoline to New the plant is owned by the Crown and subsequently sold Zealand petroleum marketing companies. Synfuel gaso- to oil marketing companies. The project has its origins line is priced competitively with gasoline produced in recommendations in 1979 from the Liquid Fuels Trust from the refinery at Marsden Point. Board (LFTB) which was formed with the objective of reducing the use of imported fuels for transport pur- Under the terms of the Processing Agreement, the poses in New Zealand. The second oil price shock tolling fee paid by the Crown covers all of NZSFC's caused by the Iranian revolution created immediate costs including tax and debt service. Also, at design pressure on the Board to determine how New Zealand's capacity, the fee provides the shareholders with a tax natural gas fields could be used to produce transport paid discounted cash flow rate of return of 16 percent fuels. adjusted for inflation.

New Zealand's two largest gas fields are the Kapuni and The Synfuel plant is located at Motunui, Taranaki. It is Maui fields. The on-shore Kapuni field has estimated designed to convert 52 to 55 petajoules per year of recoverable gas reserves of 419 petajoules (400 trillion natural gas into 570,000 tonnes per year (14,450 barrels BTU) whereas the Maui field with estimated recover- per stream day) of gasoline. The conversion of gas to able gas reserves of 5,193 petajoules (4,900 trillion gasoline takes place in two stages: first, gas-to- BTU) is off the coast of Taranaki. methanol and second, methanol-to-gasoline. The LFTB recommended that New Zealand proceed The gas-to-methanol plant consists of two 2,200 tonnes with two major projects: per day trains that employ the ICI low-pressure methanol process. Next, conversion of methanol-to- • A synthetic gasoline project to produce gasoline gasoline occurs in two stages using Mobil's proprietary from natural gas using a process developed by ZSM-5 zeolite catalyst. In the first stage, the crude the Mobil Oil Corporation methanol is partly dehydrated to an equilibrium mixture • A "stand-alone" methanol project, using natural of dimcthyl ether (DME), methanol, and water. The gas as the feedstock, with the majority of DME mixture is then combined with recycle gas and product dedicated to export as chemical grade passed to the gasoline conversion reactors where the methanol and the remainder for local use as a second stage reactions form approximately 44 percent fuel or as a chemical. hydrocarbons and 56 percent water. Small amounts of carbon monoxide, carbon dioxide, and coke are also Also, the LFTB recommended that the approved expan- formed. The overall design thermal efficiency of the sion of the refinery at Marsden Point in northern New plant is 53 percent. Zealand account for future production of synthetic gasoline. Construction The combined use of synthetic gasoline, indigenous condensate from Kapuni and Maui, and compressed In March 1982 on-site work commenced. Because natural gas (CNG) and liquefied petroleum gas (LPG) in sufficient skilled labor was not readily available in New vehicles was predicted to make New Zealand about Zealand, the plant was designed to incorporate large 50 percent self-sufficient in transport fuels in the mid- preassemblies to be build by Hitachi-Zosen Ltd. in dle 1980s. Savings of several hundred million dollars Ariake, Japan. per year in overseas funds were predicted.

1-33 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

Most elements of the project were commissioned during receives NZ$0.38 per liter when crude oil is priced at 1985, with Methanol 2 being left to Inst. Methanol 1 US$26 per barrel. At the current oil price of US$13 per startup commenced in late August and methanol was barrel, the selling price drops to NZ$0.18 per liter. synthesized on October 12, 1985. On October 17 the Thus, Douglas contends that the government will lose first gasoline was produced from the methanol-to- approximately Nz$350 million per year due to the gasoline plant. Only minor startup problems were operation of the Motunui.natural gas-to-gasoline plant. encountered. Since startup, Methanol 1 and two methanol-to-gasoline TABLE 1 reactors have been operating almost continuously at approximately 10 percent above nameplate capacity. The first 4,000 tonnes of blended gasoline was within NEW ZEALAND MTG PROJECT BUDGET specification, with the following characteristics: (Thousand United States Dollars)

Reid Vapor Pressure, mbar 846 Direct Costs Density, kg/m3 at 15°C 0.7420 Methanol Plants 169,100 Distillation Methanol-to-Gasoline Plant 91,300 • Evaporation 70°C 37.9 Offsites and Utilities 122,000 • Evaporation 100°C 55.8 • Evaporation !@ @ 190°C 97.7 Sub-Total Direct Costs 382,400 End Point, °C 199.4 Research Octane Number 93.7 Indirect Costs Field Distributables 149,800 Contractor Home Office 69,900 Sub-Total indirect Costs 219,700

Methanol 2 and the remaining methanol-to-gasoline Other Costs reactors were started up, and design capacity was Capitalized Engineering 35,500 achieved on January 2, 1986. The project sponsors Capitalized Spares 3,000 believe that the capacity of the plant could exceed its Venture Costs 24,500 nameplate capacity of 570,000 tonnes per year with New Zealand Development Levy 3,300 only minor plant and offsite additions. Wrap-Up Insurance 10,000 Land 4.000 Economics Sub-Total Other Costs 80,300 Sub-Total 882,400 The latest forecast of the project costs, including capitalized interest and working capital, is Contingency 84,600 US$1,218 million, about 17 percent less than the original budget of US$1,475 million shown in Table 1. Sav- Total Plant Cost( Joint Executive 767,000 ings have been made because of lower interest and Committee Report) inflation rates and higher workforce performance than forecast. Also, the very competitive bidding environ- Fees and Start-Up Costs 119,000 ment for offshore components of the plant contributed Total Project Costs in 1980 886,000 to below budget costs. United States Dollars

Recently, the economics of the project have been Inflation through July 1985 305,860 criticized by the current administration's Minister of Estimated Interest During Construction 283,140 Finance, Honorable R. 0. Douglas, as a "think slick" (Capitalized) project dreamed up by the previous government. First, the Minister estimates (based on forecasts of interest Total Cost in As Spent 1,475,000 rates and exchange rates) that the loan repayments United States Dollars from 1986 to 1995 will cost NZ$2.65 billion. These payments translate to costs of NZ$0.264 per liter for interest and NZ$0.149 per liter for principal. Douglas estimates operating costs to be NZ$0.135 per liter and tax on dividends of NZ$0.011 per liter. Lastly, accord- The project sponsors take exception to Douglas' figures ing to Douglas is the "shocking" part—a profit of on several points. First, they point out that the NZ$0.198 per liter based on the guaranteed 16 percent government, which owns 75 percent of the plant, bene- after tax rate of return. Thus, the total consumer cost fits from any profits made by the project. Secondly, is NZ$0.757 per liter (US$1.55 per gallon at US$1 = the government also recieves approximately NZ$50 NZ$1.85). million in revenues from gas condensate that is removed from the natural gas before it is processed. Because the synthetic gasoline is sold at the market Third, the processing fee includes loan payments which price of conventional gasoline, the government only will be completed in 1995. Lastly, Douglas' figures do

1-34 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 not account for future increases in crude oil prices. At ciency in transport fuels. With the commissioning of a recent conference, an official of the New Zealand the Synfuel project, New Zealand's self-sufficiency Synthetic Fuels Corporation referred to the current figure will be 54 percent as follows: 24 percent from administration's economic analysis as "sour grapes" condensate from the Kapuni and Maui gas fields, which are intended to discredit the previous administra- 16 percent from Synfuel gasoline, 2 percent from the tion. use of LPG in vehicles, and 12 percent from indigenous oil supplies. The advantage of this increased self- Moreover, the economic figures do not take into ac- sufficiency to New Zealand may be significant, parti- count the fact that in 1973 the government entered into cularly in the medium to long-term. a take-or-pay contract for natural gas from the Maui field until 2008. Demand for this natural gas for other 4f uses such as electricity generation are not considered to be adequate to utilize the quantities specified in the contract. AUSTRALIA DISCOUNTS SYNFUELS UNTIL WELL AFTER 2000 At an exchange rate of US$1 Nz$1.85, the sponsors' estimates of loan interest, capital repayment, operating The Australian Department of Resources and Energy expenses, and profit are shown in Table 2. has published its current outlook in a publication entitled Energy 2000. The Department concludes that while Australia has a large resource base of synfuels TABLE 2 feedstocks such as coal, oil shale, and natural gas, a substantial increase in crude oil prices is necessary to make Australian synfuels projects viable. The Depart- SYNFUEL GASOLINE COST ELEMENTS ment of Resources and Energy does not, however, AT NAMEPLATE CAPACITY expect any significant real rise in crude oil prices until (1986 Ni Cents Per Liter) well after 2000.

1987 1996 2000 Resources Operating Expenses/Fees 12 12 12 Australia has ample resources for the development of Loan Interest/Repayments 38 3 5 synfuels including natural gas, oil shale, and black and Return on Capital at Risk: brown coal. Natural gas reserves are currently esti- Mobil 4 4 4 mated at 689,000 million cubic meters located primar- Crown 11 11 11 ily in the Bass Strait, Cooper Basin, and North West Tax - 15 19 Shelf. Total = Gross Fee 65 45 51 Most of Australia's oil shale reserves are located in Queensland, where in situ reserves of around 24 billion barrels of shale oil have been demonstrated (Table 1).

The costs are in 1986 cents per liter of gasoline TABLE 1 produced, based on the assumption that the plant produces 570,000 tonnes per year at design levels of process efficiency. As shown in the table, 1987 will be the DEMONSTRATED IN SITU OIL SHALE first full year of commercial operation of the plant, RESOURCES IN AUSTRALIA with full loan repayments, whereas the year 2000 is representative of the situation after 1995 when all loans are repaid. Million Cubic Million In the sponsors' analysis, the cost of the synthetic Metres Barrels gasoline compares favorably with the cost of petroleum-derived gasoline. The wholesale price is esti- Condor 1,060 6,660 mated to be NZ$0.49 plus a levy of NZ$0.16 that was Duaringa 590 3,720 imposed to pay for the refinery expansion. Thus, the Julia Creek 270 1,700 petroleum-derived gasoline is estimated to cost Lowmead 120 740 NZ$0.65 per liter—the same cost as synthetic gasoline. Nagoorin 420 2,650 Nagoorin South 70 470 The sponsors believe that the Synfuel plant is a long- Rundle 420 2,650 term investment, i.e., until at least 2003. Its economic Stuart 400 2,510 benefits will depend primarily on the price of oil over Yaamba 440 2,780 the life of the project and, therefore, cannot be pre- Total 3,790 23,880 dicted with any certainty. In 1979 the view of the Liquid Fuels Trust Board was that it was desirable for New Zealand to move to about 50 percent self-suffi-

1-35 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 2

PROPERTIES OF SOME AUSTRALIAN OIL SHALES

Typical Content of Elements in Oil Oil Shale Kerogens Age Yield %C %H %O %N 965 (Liters/ Tonne)

Glen Davis Permian 420 86.1 11.0 0.9 1.0 1.0 Julia Creek Cretaceous 50-80 74.6 8.0 9.8 2.2 5.4 Rundle Tertiary 50-130 75.5 9.7 11.0 2.0 1.8 Torbanite Permian up to 150 82.3 11.0 2.0 0.7 4.0

As Table 2 shows, the oil shales appear to have com- quefaction technology developed in Japan by the Nippon mercial potential yield of more than 50 liters of oil per Brown Coal Liquefaction Company Ltd. (NBCL). tonne on a dry basis. Stage 1, which has been completed, comprises brown coal dewatering and primary hydrogenation to produce Black coal reserves, including coking and non-coking solvent refined coal (SRC). Stage 2, scheduled for coals, are estimated at slightly over 30 million tonnes completion in 1987, comprises SRC de-ashing and sec- and are located near the east coast of New South Wales ondary hydrogenation to produce liquid fuels. The pilot and Queensland. plant is scheduled to operate until 1989.

Most of Australia's brown coal reserves are located in Other important synfuels activities include feasibility the Latrobe Valley of Victoria, with smaller deposits in studies for the Condor and Rundle oil shale deposits. South Australia, Western Australia, and Tasmania. The Southern Pacific Petroleum ML and Central Pacific total in situ resource of brown coal is estimated at Minerals ML signed an agreement in 1981 with the 202 million tonnes, of which 31 million tonnes are re- Japan Australian Oil Shale Corporation for a joint garded as readily available reserves. Victorian brown feasibility study on the production of oil from shale. coal has a high moisture content (generally around 65 percent on a weight basis), a low ash content (typi- A 20,000 tonnes sample of screened and crjshed oil cally 1 to 4 percent on a dry basis) and a low sulfur shale has been shipped to Japan for testing in a content (typically less than 1 percent on a dry basis). proposed 300 tonne per day pilot plant retort. A detailed feasibility study of the Rundle oil shale project has indicated that, although some of the uncertainties Economics of Synfuels associated with mining and processing of Rundle oil shale have been reduced as well as reducing previous Using the International Energy Agency's report on "The development cost estimates, a decision to proceed to Cost of Liquid Fuels from Coal" as a base, the Depart- construction could not be made until crude oil markets ment has determined the breakeven price of crude oil and prices improved. to achieve viable synfuels projects for three different technologies: The Department made the following observations with respect to processing oil shale into synfuels: • Fischer-Tropsch process • Methanol-derived gasoline • Oil shale processing costs are likely to be lower • Direct liquefaction. than for coal-based projects, although feedstock costs per barrel could be higher Table 3 shows the results of their calculations. • As with coal-based synfuel projects, oil shale projects require a substantial increase in oil Australia has substantial reserves of natural gas, suffi- prices, or a significant reduction in costs, to cient to provide a base for methanol or gas-to--gasoline achieve viability. plant. However, the Department concludes that the process is not currently economically attractive. There is a 14,500 barrels per day demonstration plant based on Conclusions the Mobil technology in New Zealand. From its analyses, the Department concludes that all The brown coal liquefaction pilot plant project in synfuels technologies need a substantial increase in Victoria is the most significant synfuels activity in crude oil prices (which they believe seems unlikely until Australia. The project is based on two-stage hydroli- well after 2000) and/or a significant decrease in costs

1-36 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 3

COSTS OF COAL-BASED SYNFUELS PRODUCTION (Based on lEA Report, Transposed to Australian Conditions at September 1984)

Components of Production ($A/Bbl) Other Capi- Basis of Feed- Oper- tal Raw Material Plant Capital stock ating Ser- Cost & Capital Technology Capacity Cost Cost Cost vicing Total Servicing (Using Wandoan Coal) (Bbl/D) (Million $A)

HYDROLIQUEPACTION Coal $A40/ton; Exxon Donor Solvent 71,000 6,218 19 17 42 78 Equity to Debt is 1:3, Bottoms Recycle ($US65) ROR 15%, Interest, Mode 10%, Tax 46% INDIRECT LIQUEFACTION Fischer-Tropsch Lurgi Methane Re- 64,000 6,361 21 19 48 88 As Above forming ($U573) Texaco Gasifiers 55,000 6,690 22 22 59 103 As Above ($13586) MTG Lurgi Gasifiers 81,000 6,280 17 14 37 68 As Above ($US57) Texaco Gasifiers 65,000 6,517 18 18 49 85 As Above ($US7I)

Product costs based on volume, not energy equivalents. **Feedstock costs have been calculated on the basis of the ex-mine cost plus reasonable profit of lower grade coal from a new open cut mine some distance inland.

to achieve economic viability in Australia. Because the to create new indigenous sources of synfuels even time to commercial competitiveness greatly exceeds though there may be a premium on price. the time to build a demonstration plant, intervention by government is not recommended. Rather, the Depart- The Department cautions that errors in timing of entry ment believes that an appropriate role for the Com- into the synfuels industry could dearly cost both the monwealth Government is to support research and Australian government and the private sector. Mis- development, e.g., through the National Energy takes were made in the 1970s because decisions were Research, Development, and Demonstration (NERD&D) not deferred until market stabilization had taken place. Program, the recently-introduced 150 percent tax de- In the future, much more rational decisions will be duction, and facilitation of such projects as the Victor- possible in light of the work already done on synfuels, ian brown-coal liquefaction pilot plant project. they conclude. For example, natural gas and black coal synfuels technology have already been proved at the As Australia's self-sufficiency begins to decline signifi- pilot plant stage (200 to 250 tonnes per day). The cantly after 1990, the shortfall is likely to be made up brown coal liquefaction project at Morwell, Victoria from the world crude oil market. Because the cost of will be completed in 1989. Pilot plant work on Austra- production of syncrude is substantially higher than that lian oil shales still has to be undertaken on a large- of natural crude, the Department concludes that Aus- scale, although Japan plans to test in the late 1980s, tralian capital can be used more effectively by generat- and Esso is developing it own retorting technique. ing income with which to buy imports. However, with non-OPEC suppliers depleting their resources at an As shown in Figure 1, the Department's projections of appreciably greater rate than OPEC suppliers, the ques- the period before crude oil prices rise to match synfuels tion of security of supply might become an important costs is two or three times the lead time for a synfuels issue. The Government might then think it is desirable demonstration plant. In the 1990s it would be possible

1-37 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 AUSTRALIA DEPARTMENT OF RESOURCES AND ENERGY ESTIMATES OF DEVELOPMENT PROFILES FOR SYNTHETIC FUELS

Methanol 15000 lonnes'oay (or specific use. e . gasoline olenoingl C: LIQUID d I I FUELS Mobil (14 500 barlels/uay aemonstration plant being Commissioned ir. New Zealand: Methanol- 50000 barrels/day commercial plant( FROM to-Gasoline NATURAL op cp GAS C 10 d c 0 Fischer- 150 000 barrelsiday. SASOL lypel Tropsch L' 1982 84 86 88 90 92 94 96 9800 02 04 06 H-Coal (proven at about 200 l/d scale: to be demonstrated at 5 000-6 000 lId scale; Eon Donor 50000 l/d commercial plant( Solvent Modified d COAL Bergius d I c 0 d c o HYDROLIQUIFICATION Brown Coal 50 Vol pilot plant under construclion; to be demonstrated at 5 000-6 000 l/d Liquefaction scale; 50000 Ud commercial plantl PD op cp C to d c 1 0 0 c 0

1982 84 86 88 90 92 94 96 98 00 02 04 0608 tO

Union (10000 barrels/day first commissioned in mid 1983 but not yet operational; 50 000 barrels/day commercial plant

OIL do cp FROM o d' c I SHALE Tosco (800 barrels/day pilot plants in operation; to be demonstrated Petrosix day; 50 000 barrels/day commercial plant) at 10 000 barrels! do

JIJ C I odj C 1 Ecron (5 tonnes/day plant in operation; to be pilot planted and then demonstrated at the 10 000 barrels/day scale; 50 000 barrels/day commercial plant) cp LJdl cIoJdI

1982 84 86 88 90 92 94 96 98 00 02 04 06 os tO pp - pilot plant 0 - design/engineering dp - demonstration plant (a vain or moouie 01 a commercial piano c -construction op -commercial plant 0 - Operation 10 lull production

1-38 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 to move straight into the demonstration phase, which PERD's annual average $96 million budget, about has a lead time of "only" seven years. Demonstration 70 percent is contracted out by the twelve participating plants would provide the first stage of production capa- departments through Supply and Services Canada (SSC). city and would only need replicating to meet increased The private sector can access these funds either via demand, they believe. unsolicited proposals submitted to SSC, or through the Requests for Proposals awarded on behalf of the man- When security of supply becomes an important issue aging departments. Table I lists the twelve govern- with the government, private industry will need ade- mental departments/agencies which administer the Pro- quate offsets to the increased risk. Such incentives gram. could include: • Loans or loan guarantees TABLE 1 • Price guarantees • Market guarantees • Exemptions from excise and levies CANADIAN GOVERNMENT DEPARTMENTS/ • Production subsidies AGENCIES MANAGING THE FEDERAL • Special tax concessions ENERGY R&D PROGRAM • Forgone royalties. The Department is concerned that these measures could Agriculture Canada be extremely expensive. Thus, no decisions should be Atomic Energy of Canada Ltd. made before the need arises. In summary, they believe Canada Mortgage & Housing Corporation that "The time to a decision-making point is so far Energy Mines and Resources away that we cannot identify yet the signals which Environment Canada would indicate to the private sector or the government Fisheries and Oceans that entry into synfuels production was timely." Health and Welfare Indian and Northern Affairs (Editors Note: Pace is concerned with two major as- National Defense pects of the Department's analysis. First, significant National Research Council cost savings can be realized through the development Public Works Canada and demonstration of advanced technologies. For Transport Canada example, the article in the Oil Shale-Economics section in this issue describes an analysis by SPP/CPM that indicates shale oil can be produced in Australia for $US27 to $31. This cost is significantly less than the $US59 value used by the Department. Hence, synthetic fuels may be closer to economic viability than assumed The five-year (1986 to 1991) Program is divided into in the Department's analysis. seven tasks, each with a specified annual budget: Secondly, as shown in Figure 1, the Department be- Annual Budget lieves that from 12 to 24 years are required for a ($ Million Cn) synthetic fuels process to advance from a pilot plant to a fully operational commercial plant. Thus, Pace 1. Energy Conservation 16 concludes that a significant effort is needed now if the 2. Oil Sands, Heavy Oil, Coal 23 processes are to be available when needed, even if that 3. Nuclear Fusion 8 date is "well after 2000.11) 4. Renewable Energy 8 5. New Liquid Fuels 17 6. Oil, Gas, Electricity 22 7. Coordination 1 The Program's highest priority will be on R&D aimed at 1) increasing the efficiency of energy use, 2) taking advantage of Canada's abundant fossil fuels resources, CANADIAN ENERGY R&D and 3) addressing environmental, health, safety, and ACTIVITIES OUTLINED regulatory constraints to energy development. In its 1985 "Guide to the Federal Panel on Energy R&D Objectives of the Program are to provide, in conjunc- Activities," the Canadian government outlined a five- tion with efforts in the private sector and by the year plan for energy research and development to provinces, the technical basis for: support its priorities for economic growth. Major emphasis is on supporting the development of Canada's • Maintaining oil self-sufficiency over the short abundant fossil fuels resources, with a strong commit- term in light of dwindling conventional supplies ment to longer-term research, particularly in renew- • Developing a diversified energy economy less ables, fusion, and hydrogen. dependent on oil and gas in the mid-term The Federal Energy R&D Program is coordinated by an • Making Canada less reliant on non-renewable interdepartmental Panel on Energy R&D (PERD). Of energy sources in the long term.

1-39 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 According to PERD, the Program has been structured TABLE 2 to complement greater energy R&D initiatives in the private sector, and it will rely on extensive interaction with the provinces and industry. In addition, the TASK 2 AREAS OF INTEREST Program maintains Canada's ability to collaborate in IN CANADA'S ENERGY R&D PROGRAM R&D programs of the International Energy Agency. PERD stresses the advantages of the connection with the LEA, citing the accessability to its large body of Oil Sands/Heavy Oils technical information as well as the ability to "show- Contact: F. Ng 613/995-4295 case" Canadian technology for potential market oppor- Energy Mines and Resources tunities. • Mining and separation processes; in situ production Two of the Program's seven tasks are of particular techniques; oil/water emulsion breaking and treat- interest to synthetic fuels development: Task 2 (Oil ment of effluent water; Taciuk dry retorting pro- Sands, Heavy, Oil, and Coal) and Task S (New Liquid cess. Fuels). These tasks are reviewed briefly in the following subsections. • Process optimization at the 1 BPI) scale of the CANMET hydrocracking process and R&D support for the 5,000 BPD demonstration plant at Petro- Task 2: Oil Sands, Canada's Pointe-aux-Trembles refinery. Heavy Oil, and Coal Upgrading bitumen/heavy oil residues—esphaltene conversion for viscosity reduction; catalytic pitch PERD's objectives for this task are to reduce Canadian pyrolysis; catalytic hydrocracking and hydrotreat- dependence on imported crude oil by: ing.

Developing technologies for production of oil Coal Combustion from oil sands and heavy oil deposits Contact: C. Adams 613/995-4295 Expanding the use of coal in an environmentally Energy Mines and Resources acceptable manner. • Coal analysis—combustion performance characteri- Table 2 lists the specific areas of interest covered zation of low grade coal, flame characteristics, under this Task; also included are the key contact(s) and comminution properties, slagging, fouling ash indi- agency phone numbers of the particular lead depart- ces, and pollution emission characteristics. ment/agency. General contacts for this task are: B.D. • Metallurgical coal technology development—coking Cook and S. Wilson, Energy Mines and Resources conditions and properties; automated petrography; 613/995-9351. coal blending.

Task 5: New Liquid Fuels Environment Contact: W. Richardson 613/994-5166 Principal objectives in this area of the Program include: Environment Canada Provide practical and economic alternatives to • Oil sands/heavy oil—tmydrogeological aspects of re- petroleum through use of coal, bitumen, natural covery operations; oil sands tailings and water gas, gas liquids, and biomass treatment; treatment of water and sludge from in situ operations; abatement of acid gas emissions. Develop techniques to ensure environmental protection and health/safety during production and • Coal mining and combustion—environmental protec- use of new liquid fuels tion criteria for mining and preparation facilities; slurry transportation; waste management practices Lay the technical and regulatory foundation for a and other environmental studies on flue gas de- major transition to alternative fuels in the next sulfurization, fluidized bed combustion, and other century. advanced combustion technology applications. Table 3 lists the specific areas of interest covered • Toxicity studies and chemical identification of oil under this Task; also included are the key contact(s) and sands products; worker exposure to chemical phone numbers for the lead department/agency re- hazards in the oil sands/heavy oil industry. sponsible for particular subtasks. Key contacts for Task S are: J.F. Legg and L. Vancea, Energy Mines and Resources 613/995-9351.

1-40 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 3 The second memorandum, signed by the DOE and the Spanish Instituto Geologico y Minero, deals solely with coal gasification and geothermal energy technologies. TASK S AREAS OF INTEREST IN CANADA'S ENERGY R&D PROGRAM No specific projects or development efforts are discussed in the memoranda. Rather, the terms for exchanges of personnel, technology conferences, es- Direct Coal Liquefaction tablishment of projects, etc. are more to outline areas of possible future cooperation. In addition to specific • Coprocessing technology of coals with bitumen, sections dealing with the legal aspects of such under- heavy oils, and residuals undertaken by CANMET as standings, both memoranda cite the following as goals: an extension of its hydroeracking process now being demonstrated in Petro-Canada's Montreal refinery. Cooperation between the Parties shall be dir- (Contact: J.M. Denis, Energy Mines and Re- ected toward finding solutions to mutually sources - 613/992-4491) agreed problems associated with energy • Energy Conversion Program: a 50/50 cost shared research and development, and to exchanging contracting-out program dealing with coal liquefac- information developed during the resolution of tion, combustion, gasification, and bitumen recovery these problems. This cooperation may include and upgrading. (Contact: D.P. Fund, Energy Mines exchange of experience and results of theoreti- and Resources 613/995-6401) cal, experimental, conceptual design problems; and agreed research and development projects. Coal Gasification Cooperation between the Parties shall be on the basis of mutual benefit, equality, and recipro- • Establishment of gasification characteristics of city. Canadian coals and development of a process for the clean-up of gasification effluents at high tempera- Under these agreements, "cooperative projects" do not tures. (Contact: E. Furimsky, Energy Mines and Re- exclude other multilateral activities carried out by sources 613/996-4570) either the United States or Spain under the aegis of other agencies such as the lEA. Fuel Processing • Production of conventional and broad-specification fuels from conventional, heavy and synthetic crude oils and processing of coal-derived liquids. (Contact: Mr. Ternan, Energy Mines and Resources (613)995-4473)

UNITED STATES AND SPAIN SIGN ENERGY R&D AGREEMENT In two memoranda signed June 6, 1986, the United States Department of Energy and two Spanish governmental agencies have agreed to conduct cooperative energy research and development projects. These five- year bilateral agreements mark the first formal cooperative energy efforts between the two countries. Areas of cooperation in one memorandum between the DOE and the Spanish Junta de Energia Nuclear are as follows: • Nuclear energy (including nuclear safety technology) • Radioactive waste management • Renewable energy (including biomass) • Coal and gas technologies.

1-41 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENVIRONMENT

EPA APPROVES UTAH'S VISIBILITY where monitoring no longer occurs, the NPS believes PROTECTION PLAN sufficient background data (i.e., five to six years of monitoring data) exist. The FLM had an opportunity to In January 1986 the United States Environmental Pro- review the Utah Visibility SIP, and no impairment areas tection Agency (EPA) announced that 32 states had were identified during the development of this program. failed to comply with provisions that require long-term For those areas where monitoring is still being con- strategies for visibility protection and new source ducted, Utah is seeking a cooperative agreement with review. States that tailed to modify their State Im- the NPS to facilitate visibility monitoring and data plementation Plan (SIP) to provide for visibility protec- exchange. Currently, the NPS performs visibility moni- tion would have federal programs imposed on them by toring at the following sites: the EPA. (See pages 1-25 and 1-26 of the March 1986 PaceI, Synthetic Fuels Report.)p Since that announce- • Bryce Canyon National Park men EPA has approved Si s for several states. • Zion National Park • Capitol Reef National Park Of the four to five states that have resources specifi- • Canyonlands National Park. cally suited for synthetic fuels (i.e.: oil shale in Colorado, Indiana, Kentucky, and Utah; oil sands in The SIP also sets a goal of establishing a monitoring Kentucky, Texas, and Utah; and heavy oil in California), network by September 1987 to provide additional back- only Utah has received EPA approval for its state ground data. It will perform visual and photographic visibility protection plan. Pace believes that visibility monitoring until additional funding can be obtained to protection, whether by a state plan or a federally- begin installation of continuous visibility monitoring imposed plan, represents one more environmental equipment. hurdle that must be overcome before a synthetic fuels project can be built and operated. The Utah plan, as The Utah Visibility regulations and SIP require a visibil- described in the May 30, 1986 Federal Register, is as ity impact analysis of a proposed new or modified follows. source to determine the potential visibility impact of the proposed source. The regulation provides the The Clean Air Act requires visibility protection for mechanism for the permitting authority to require pre- mandatory Class I federal areas (certain national parks, construction as well as post-construction visibility mon- wilderness areas, and international parks) where EPA itoring in any mandatory Class I area to assess the has determined that visibility is an important value. source's impact on visibility. EPA believes that this The Act specifically directs EPA to promulgate regula- monitoring by proposed sources will assist in determin- tions requiring certain states to amend their SIPs to ing background conditions as well as considering the provide for visibility protection. On December 2, 1980 effects of existing sources. This monitoring, coupled EPA promulgated the required visibility regulationsp with the evaluation of potential impacts by the pro- that required the states to submit revised Si s to posed source, will benefit the visibility program in satisfy such provisions no later than September 2, 1981. preventing degradation of the area, according to the EPA. Several suits eventually resulted in an agreement that gave states an opportunity to avoid federal promulga- Utah incorporated its permitting regulations into its tion if they submitted a SIP no later than May 6, 1985. Visibility SIP as well as requiring the application of On April 26, 1985 the Governor of Utah submitted a SIP Best Available Control Technology and emission limita- Revision for Visibility Protection together with the tion requirements of any new or modified source locat- Visibility Regulations for monitoring and new source ing anywhere in the state. The regulations describe the review. On November 13, 1985 EPA proposed to ap- analyses to be performed by the state and the FLM. prove the Utah Visibility SIP and regulations. Com- Permits can be denied if visibility impact is determined ments were received in support as well as against by the permitting authority. The regulations provide approval. the mechanisms for permit conditions on control equipment, technology, methods, and work practices that The monitoring section of the Utah Visibility Protection provide the insurance that source emissions will be Plans consists of three components: consistent with making reasonable progress toward the national goal. Further, the regulation requires the • Monitoring by the Federal Land Manager (FLM) permitting authority to provide an explanation of its • Monitoring by sources proposing to locate or decision should it disagree with the FLM's assessment modify in an area where emissions may impact on a proposed source's impact on visibility. The final Class I areas decision rests with the permitting authority. • Implementation of a state monitoring network. Based on its analysis of Utah's SIP revision, the EPA approved the plan effective June 30, 1986. Copies of "Monitoring by the FLM" consists of an assessment of the revision are available at the following offices: visibility background and trend data available from the FLM. The National Parks in Utah have been monitored by the National Park Service (NPS). For those areas

1-42 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Environmental Protection Agency Region VIII, Air Programs Branch One Denver Place, Suite 1300 999 Eighteenth Street Denver, Colorado 80202 Environmental Protection Agency Public Information Reference Unit Waterside Mall, 401 M Street, SW Washington, D.C. 20460 The Office of the Federal Register 1100 L Street, NW, Room 8401 Washington, D.C.

1-43 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RECENT GENERAL PUBLICATIONS/PATENTS

American Chemical Society's "Official Public Policy Statements arid Communications," March 7, 1986. "Energy 2000," A National Energy Policy Review, Australian Department of Resources and Energy, March 1986.

111986 Guide to the Federal Panel on Energy Research and Development Activities of the Government of Canada," Canadian Office of Energy Research and Development.

"World Energy Outlook," Chevron Corporation, Economics Department, June 1986.

"Energy Policies and Programmes of lEA Countries," International Energy Agency, 1985 Review. "Synthetic Liquid Fuels," International Energy Agency Seminar, Paris, 1985.

"A Survey of United States and Total World Production, Proved Reserves, and Remaining Recoverable Resources of Fossil Fuels and Uranium as of December 31, 1984," IGT World Reserves Survey. "Lead in Gasoline: Alternatives to Lead in Gasoline," The Royal Society of Canada, February 1986. Salmon, Reyes, "Economics of Methanol Production from Coal and Natural Gas," Oak Ridge National Laboratory.

United States House of Representatives, "Department of the Interior and Related Agencies Appropriation Bill, 1987."

GENERAL - PATENTS

"Method of Making Carbon Black Having Low Ash Content from Carbonaceous Materials," Wenjai R. Chen and Robert L. Savage - Inventors, United States Patent 4,590,0056, May 20, 1986. A partial combustion method of producing commercially acceptable carbon black containing less than approximately 1 percent ash from carbonaceous material taken from the group consisting of coal, lignites, tar sand, pitch, oil shale, and asphaltic substances, which comprises reacting the carbonaceous material with oxygen at a temperature of from 2,000°F to 3,000°F, the carbonaceous material having an average particle size of from 75 microns to 1,700 microns and wherein the oxygen to carbonaceous material weight ratio is no more than 0.4, and recovering the carbon black from the reaction.

"Use of Ethers in Thermal Cracking," Partha S. Ganguli - Inventor, HRI Inc., United States Patent 4,592,826, June 3, 1986. A process for improving the upgrading/conversion of hydrocarbonaceous materials such as coals, petroleum residual oils, shale oils, and tar sand bitumens. In the process, the free radicals formed from thermal cracking of the hdyrocarbons are reacted with the free radicals formed by the thermal cracking of a free radical forming chemical reactant, such as dimethyl ether, to yield stable low molecular weight hydrocarbon distillate products. The hydrocarbonaceous feed material is preheated to a temperature of 600 0 to 7000F, and the hydrocarbon and the free radicals forming chemical, such as dimethyl ether, are passed through a now reactor at temperature of 750 0 to soo°, pressure of 200 to 1,000 psi, and liquid hourly space velocity of 0.3 to 5.0 LHSV. Free radicals formed from the hydrocarbon feed material and from the ether material react together in the reactor to produce low molecular weight hydrocarbon liquid materials. The weight ratio of ether material to hydrocarbon feed material is between about 0.3 and about 2.0.

"Conversion of High Boiling Organic Materials to Low Boiling Materials," Curtis D. Coker and Stephen C. Paspek, Jr. - Inventors, United States Patent 4,594,141, June 10, 1986. A process for the conversion of high boiling saturated organic materials is described. The method comprises contacting said high boiling organic materials at a temperature of at least about 300°C and at a reaction pressure of at least about 2,000 psi with an aqueous acidic medium containing at least one olefin, and a halogen-containing compound selected from the group consisting of a halogen, a hydrogen halide, a compound which can form a halide or a hydrogen halide in the acqueous acidic medium under the process conditions, or mixtures thereof whereby the high boiling organic material and aqueous acidic medium form a substantially single phase system. Optionally the process can be conducted in a reducing atmosphere. The process of the invention is useful for producing and recovering fuel range liquids from petroleum, coal, oil shale, shale oil, tar sand solids, bitumen, and heavy hydrocarbon oils such as crude oil distillation residues which contain little or no carbon-carbon unsaturation. Preferably, the halogen compound is at least one halogen or a hydrogen halide.

1-44 SYNTHETIC FUELS REPORT, SEPTEMBER 1996 COMING EVENTS

1986 SEPTEMBER 7-12, ANAHEIM, CALIFORNIA—American Chemical Society, American Chemical Society National Meeting.

SEPTEMBER 8-11, TORONTO, CANADA—Gas Research Institute, International Gas Research Conference.

SEPTEMBER 8-12, PITTSBURGH, PENNSYLVANIA—Third Annual Pittsburgh Coal Conference, University of Pittsburgh and DOE.

SEPTEMBER 16-18, SURREY, ENGLAND—The Symposium on Gas Cleaning at High Temperatures, Institution of Chemical Engineers.

SEPTEMBER 21-23, CALGARY, ALBERTA, CANADA-42nd Petroleum Mechanical Engineering Workshop and Confer-

SEPTEMBER 21-25, TOKYO, JAPAN—World Congress Ill of Chemical Engineering, The Japan Society of Chemical Engineers.

SEPTEMBER 22, SAN FRANCISCO, CALIFORNIA-1985 Mining Convention, American Mining Congress.

SEPTEMBER 29-OCTOBER 3, HALIFAX, NOVA SCOTIA, CANADA—Sixth International Workshop on Coal-Liquid and Alternate Fuels Technology (CLAFT), Centre for Energy Studies, Technical University of Nova Scotia.

SEPTEMBER 30, PARIS, FRANCE—Hydrogenation and Pyrolysis of Coal Meeting, GRECO.

OCTOBER 1-3, DENVER, COLORADO—Rocky Mountain Oil and Gas Association, Annual Meeting, Denver Marriott City Center.

OCTOBER 5-8, NEW ORLEANS, LOUISIANA—Society of Petroleum Engineers Annual Meeting.

OCTOBER 5-8, SARNIA, ONTARIO, CANADA-36th Canadian Chemical Engineering Conference-Preparing for the Nineties, Canadian Society for Chemical Engineering.

OCTOBER 5-9, LAS VEGAS, NEVADA—American Mining Congress, International Mining Show.

OCTOBER 5-11, CANNES, FRANCE—Energy 13th World Congress and International Energy Exhibition of Plant and Equipment, World Energy Conference.

OCTOBER 6-7, CHICAGO, ILLINOIS—Coal & Synfuels Technology, Fluidized Bed Combustion.

OCTOBER 15-16, PALO ALTO, CALIFORNIA—Sixth Annual Coal Gasification Contractors' Conference, Electric Power Research Institute.

OCTOBER 16-17, WASHINGTON, D.C.—Third International Clean Coal Technology and Acid Rain Conferenc e , McGraw- Hill Energy Publications.

OCTOBER 20-22, ST. LOUIS, MISSOURI—International Clean Coal Technology Congress, National Coal Association.

OCTOBER 20-23, PARIS, FRANCE—Alcohol Fuels 7th International Symposium, lnstitut Francais de Petrole.

OCTOBER 26-30, TUCSON, ARIZONA—Fuel Cell Seminar, Electric Power Research Institute, Gas Research Institute, and United States Departments of Energy and Defense.

OCTOBER 27-30, DEARBORN, MICHIGAN-24th Automotive Technolo gy Development Contractors' Coordination Meeting, United States Department of Energy.

OCTOBER 27-28, HOUSTON, TEXAS—Gas EOR Technology & Economics: Beating the OH Price Crisis, Enhanced Recovery Week.

1-45 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 NOVEMBER 2-7, MIAMI BEACH, FLORIDA—Winter Annual Meeting, American Institute of Chemical Engineers.

NOVEMBER 11-13, PITTSBURGH, PENNSYLVANIA—Coal Technology '86: 9th International Coal Utilization Confer- ence National Coal Institute, EPRI, et al.

NOVEMBER 19-21, LEXINGTON, KENTUCKY-1986 Eastern Oil Shale Symposiun, Commonwealth of Kentucky Energy Cabinet.

1987

FEBRUARY 15-19, DALLAS, TEXAS—Technical Economics, Synfuels and Coal Energy Symposium, Energy Sources Technology Conference.

MARCH 29-APRIL 2, HOUSTON, TEXAS—AIChE's Spring National Meeting and 1987 Petrochemical and Refining Exposition, AstrohalL

APRIL 5-10 9 DENVER, COLORADO-193rd National Meeting of the American Chemical Society.

APRIL 8-11, SAN FRANCISCO, CALIFORNIA—Alternate Energy '86, Council on Alternate Fuels.

APRIL 16-19, MINNEAPOLIS, MINNESOTA—AIChE's Summer National Meeting.

1-46 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Inc \ oii JR allxmilbe PROJECT ACTIVITIES

UNOCAL MAKES PROGRESS ON START-UP--BUT FACES LAWSUIT FIGURE 1

Unocal's Parachute Creek oil shale facility was success- TOOLEBUC fully run several days at a stretch for the first time this summer. After a shutdown of several months for OIL SHALE FORMATION modifications to the spent shale shaft cooler system, startup attempts began again in May. A 60 hour run was completed in July and then a six day run.

By increasing the size of the crushed shale from a nominal diameter of 2 inches to a diameter of 3 inches, and processing a leaner grade of shale, the retort has operated successfully at about 40 to 50 percent of design capacity.

In late August, Unocal began taking applications for 50 Townsville new jobs at the plant. These jobs are expected to be Mt available for miners, heavy equipment operators, and process operators in November when the plant is scheduled to come back onstream after a 4 to 6 week maintenance turnaround. TOQLEBUC'a Meanwhile several congressmen and the Friends of the Earth have filed a lawsuit in the United States District QUEENSLAND D Court for the District of Columbia against Unocal and Brgbsuis the United States Treasury Department. The lawsuit attempts to void the agreement reached early this year between Unocal and the at-the-time disappearing United States Synthetic Fuels Corporation (SFC). That agreement changed $327 million of a $500 million price guarantee awarded to Unocal into a loan guarantee. combustor with a retort in which heat is transferred The lawsuit charges that the agreement violated Con- from hot shale ash to cold raw shale. CSR and CSIRO gress' intent when they prohibited the SFC from issuing have carried out a series of trials in laboratory scale any new awards after December 19, 1985. equipment. The program has Involved studies at two sites—Concord (CSR) and Clayton (CSIRO Division of Mineral Engineering).

Since recommissioning the CSR retort in February 1986 and overcoming problems with both heater and filter, RESEARCH CONTINUES ON JULIA CREEK preliminary results of retorting raw shale in the pre- SHALE OIL PROJECT sence of hot shale ash suggest that the earlier yield loss problem has been overcome. Tests are underway to CSR Limited anc the CSIRO Division of Mineral Engi- explore process conditions and their effect on oil yield neering in Australia are working jointly on the develop- and quality. ment of a new retorting process for Julia Creek oil shale. This work is gathering fundamental and operat- In conjunction with the work at Concord, CSIRO's ing data for design of a larger scale pilot plant. Project Division of Mineral Engineering has been carrying out status was discussed at the 3rd Australian Workshop on several studies on Julia Creek oil shale which are Oil Shale in May 1986. fundamental to the design of the CSIRO/CSR retorting process. A block diagram of the overall processing Proven reserves at Julia Creek are about 2 billion scheme is shown in Figure 2. The raw oil shale under- barrels of oil in open-cut shale (see Figure 1). CSR goes pyrolysis when mixed with the hot ash in the began work on the Julia Creek Project in 1969 and until retort. Vapor products are passed to the separation 1973 the commercial emphasis was as much on the section where after quenching the three major products extraction of vanadium as on oil from shale. An of oil, gas, and liquor are produced. extensive preliminary feasibility study in 1979/1980 highlighted the need to make major cost reductions in Solids from the retort are combusted in a fluidized bed the areas of mining, retorting, and power supply. combustor. A small quantity of hydrogen sulfide arising from shale oil refining is also combusted. A portion of the solids from the combustor is returned to the retort Retorting Process Development as heat carrier and the remainder is cooled in the solids heat recovery section and then discarded as waste ash. The CSIRO/CSR retorting process integrates a fluid bed Provision is made for the hot flue gases from the FEC

2-1 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 to undergo heat exchange with the cold combustion air The naphtha fraction (6.2 percent sulfur, 0.3 percent and then pass to a waste heat boiler where further heat nitrogen) was readily converted in a single step process, recovery occurs in the form of steam raising for over a commercial Co-Mo hydrotreating catalyst, into process requirements and power generation. products suitable for isomerization and reforming (0.2 ppm sulfur, 0.5 ppm nitrogen) or upgrading by Preliminary results of material and energy balance molecular sieve adsorption. studies indicate that the process concept is quite robust over the combustion temperature range examined. The topped crude oil (196° - FBP; 5.5 percent sulfur, 1.8 percent nitrogen) was hydrotreated separately In Upgrading of Shale Oil two stages. Following initial hydrostabilization in which the production of secondary naphtha was mini- In 1978 CSR commenced a study of the refining of Julia mized, the 1960 to 3170C cut was further upgraded over Creek shale oil Into transport fuels. The composition of commercial Ni-Mo catalyst. The jet and diesel fuel Julia Creek shale oil is sufficiently different from fractions of the product were the first shale-derived conventional petroleum crude oils and typical shale oils synfuels produced in Australia to meet all specifica- to make actual refining studies necessary. tions. Cetane numbers up to 59 for the diesel fractions indicated excellent potential for automotive use. Studies between 1978 and 1981 indicated that after hydrostabilization, the whole oil may be acceptable as a The proposed scheme also includes the production of a syncrude feedstock to conventional refining processes. small amount of bitumen, a high value product In Alternatively, the raw oil could be fractionated and Australia currently manufactured from imported heavy upgraded to finished products. crude oils. This would facilitate the removal of some of the more intractable heavy materials in the shale oil CSR and CSIRO's Division of Energy Chemistry in 1985 and would decrease the heavy asphaltene and metals completed NERDDP Project 560, "Marketable Trans- burden on hydrostabilization catalysts. port Fuels from Toolebuc Shale Oil." The main objective was to develop an overall oil hydrotreatrnent In order to continue the development of the CSIRO/ scheme that would minimize the naphtha yield from the CSR retorting process, an integrated retort/combustor hydrotreatment of middle distillates and the hydro- of 3 to 5 tonnes per day capacity is required for the cracking of heavy residues, in favor of higher yields of next step. distillate.

2-2 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RESEARCH CONTINUES ON JULIA CREEK Upgrading of Shale Oil SHALE OIL PROJECT In 1978 CSR commenced a study of the refining of Julia CSR Limited and the CSIItO Division of Mineral Engi- Creek shale oil into transport fuels. The composition of neering in Australia are working jointly on the develop- Julia Creek shale oil is sufficiently different from ment of a new retorting process for Julia Creek oil conventional petroleum crude oils and typical shale oils shale. This work is gathering fundamental and operat- to flake actual refining studies necessary. ing data for design of a larger scale pilot plant. Project status was discussed at the 3rd Australian Workshop on Studies between 1978 and 1981 indicated that after Oil Shale in May 1986. hydrostabilization, the whole oil may be acceptable as a syncrude feedstock to conventional refining processes. Proven reserves at Julia Creek are about 2 billion Alternatively, the raw oil could be fractionated and barrels of oil in open-cut shale (see Figure 1). CSR upgraded to finished products. began work on the Julia Creek Project in 1969 and until 1973 the commercial emphasis was as much on the CSR and CSIRO's Division of Energy Chemistry in 1985 extraction of vanadium as on oil from shale. An completed NERDDP Project 560, "Marketable Trans- extensive preliminary feasibility study in 1979/1980 port Fuels from Toolebuc Shale Oil." The main objec- highlighted the need to make major cost reductions in tive was to develop an overall oil hydrotreatment the areas of mining, retorting, and power supply. scheme that would minimize the naphtha yield from the hydrotreatment of middle distillates and the hydrocracking of heavy residues, in favor of higher yields of Retorting Process Development distillate.

The CSIRO/CSR retorting process integrates a fluid bed The naphtha fraction (6.2 percent sulfur, 0.3 percent combustor with a retort in which heat is transferred nitrogen) was readily converted in a single step process, from hot shale ash to cold raw shale. CSR and CSIRO over a commercial Co-Mo hydrotreating catalyst, into have carried out a series of trials in laboratory scale products suitable for isomerization and reforming equipment. The program has involved studies at two (0.2 ppm sulfur, 0.5 ppm nitrogen) or upgrading by sites—Concord (CSR) and Clayton (CSIRO Division of molecular sieve adsorption. Mineral Engineering). The topped crude oil (196° - FBP; 5.5 percent sulfur, Since recommissioning the CSR retort in February 1986 1.8 percent nitrogen) was hydrotreated separately in and overcoming problems with both heater and filter, two stages. Following initial hydrostabilization in preliminary results of retorting raw shale in the pre- which the production of secondary naphtha was mini- sence of hot shale ash suggest that the earlier yield loss mized, the 1960 to 317°C cut was further upgraded over problem has been overcome. Tests are underway to commercial Ni-Mo catalyst. The jet and diesel fuel explore process conditions and their effect on oil yield fractions of the product were the first shale-derived and quality. synfuels produced in Australia to meet all specifications. Cetane numbers up to 59 for the diesel fractions In conjunction with the work at Concord, CSIRO's indicated excellent potential for automotive use. Division of Mineral Engineering has been carrying out several studies on Julia Creek oil shale which are The proposed scheme also includes the production of a fundamental to the design of the CSIRO/CSR retorting small amount of bitumen, a high value product In process. A block diagram of the overall processing Australia currently manufactured from imported heavy scheme is shown in Figure 2. The raw oil shale under- crude oils. This would facilitate the removal of some goes pyrolysis when mixed with the hot ash in the of the more intractable heavy materials in the shale oil retort. Vapor products are passed to the separation and would decrease the heavy asphaltene and metals section where after quenching the three major products burden on hydrostabilization catalysts. of oil, gas, and liquor are produced. In order to continue the development of the CSIRO/ Solids from the retort are combusted in a fluidized bed CSR retorting process, an integrated retort/combustor combustor. A small quantity of hydrogen sulfide arising of 3 to 5 tonnes per day capacity is required for the from shale oil refining is also combusted. A portion of next step. the solids from the combustor is returned to the retort as heat carrier and the remainder is cooled in the solids heat recovery section and then discarded as waste ash. Provision is made for the hot flue gases from the FBC to undergo heat exchange with the cold combustion air and then pass to a waste heat boiler where further heat RUNDLE PROJECT SEES 1,000 HOUR RUN IN recovery occurs in the form of steam raising for EXXON PILOT PLANT process requirements and power generation. Following renegotiation of the Joint Venture Agree- Preliminary results of material and energy balance ment between Esso Exploration and Production Austra- studies indicate that the process concept is quite robust lia Inc. (Esso), Southern Pacific Petroleum N.L., and over the combustion temperature range examined. Central Pacific Minerals N.L. (SPP/CPM), a new work program was initiated in March 1985 to continue development of the Rundle Shale Oil Project. This program is directed toward resolving outstanding questions iden-

2-3 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 tified at the completion of the Rundle Commercializa- the fresh Kerosene Creek material which was extracted tion Study (RCS), which was carried out through by large diameter coring in 1985. Primary crushing to 1983/1984. minus 200 millimeters was performed in Australia and the material was then shipped to Baytown, Texas where In the RCS a staged development was proposed. In the final feed preparation occurred. Pilot plant runs are first stage over 17,000 barrels per day of shale oil expected to continue through September 1986. would be produced from 25,000 tonnes per day of wet shale. An initial investment of $645 million (1983 U.S. dollars) was estimated. Two subsequent stages of Upgrading development would increase total shale oil production to approximately 75,000 barrels per day at an added Some upgrading studies were carried out initially on oil cost of $2,000 million. produced by the Lurgi, Dravo, and Tosco pilot plants. These tests served to illustrate the differences In oil These studies were initiated during 1985, with activities quality produced by the various processes. Shale oil divided between Australia and the United States. The from the Exxon pilot plant is now available and frac- most intense activity has been centered at Baytown, tionation tests have taken place. Upgrading pilot plant Texas where a 5 tons per day pilot plant has operated studies are underway at Exxon's Research and Develop. successfully on Rundle shale. ment Laboratories, Baton Rouge, Louisiana to compare this oil's performance with those tested previously.

Resource Studies The rate of further development at Rundle is stated to be determined by technological developments and mar- The RCS proposed to commence extraction of the re- ket conditions. source in the rich and easily-accessible Kerosene Creek Member which contains 15 percent of the total resource. Previous delineation drilling had not explored ### U the seam in great detail. During 1985 an infill drilling program was undertaken which involved the completion of 33 additional holes totalling 2,900 metres. Drilling was limited to overburden material and the Kerosene Creek Member.

The extent of faulting within part of the Kerosene Creek seam has been shown to be somewhat greater than previously anticipated and the extent of Kerosene Creek resource to the north of the Stage I Mine area has been increased as a result of the drilling program.

Shale Research

Exxon's efforts to develop a proprietary shale retorting process are being assisted by research conducted in Australia. During 1985, CSIRO and the University of Queensland began studies relating to:

• Understanding of the gaseous-mineral reactions which take place during the retorting and combustion of Rundle shale • Developing correlations to predict the behavior of fluidized beds of mixed-size shale particles.

Pilot Plant Testing

Exxon's shale development efforts are centered at Bay- town, Texas. Rundle shale has run successfully in the pilot plant for over four months. One run of over 1,000 hours of continuous operation was achieved. Determination of oil yield under varying operating conditions has been a prime objective of the runs.

Shale from both the Lower Ramsay Crossing and the Kerosene Creek Members has been run successfully in the pilot plant. The Lower Ramsay Crossing material which was extracted in 1981 has processed as well as

2-4 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 CORPORATIONS

CENTRAL PACIFIC MINERALS AND 33 HQ coreholes, which provided detailed stratigraphic SOUTHERN PACIFIC PETROLEUM and structural data throughout the proposed mine area. DETAIL OIL SHALE ACTIVITIES On August 23, 1985, the Companies announced a new As noted in their 1985 Annual Report, issued May 1986, Joint Venture Agreement had become effective. As a Central Pacific Minerals N.L. (CPM) and its affiliate result, Esso made a payment to the Companies of company, Southern Pacific Petroleum N.L. (SPP) have $32 million. A further $12.5 million is expected to be continued to remain in the forefront of oil shale explor- payable in early 1987, subject to the Joint Venturers ation, evaluation, and research around the world. maintaining satisfactory title arrangements over the resource at that time. The Companies' in situ shale oil resources in Queens- land, Australia are their major assets and are listed as Under the new Agreement, the Companies and Esso follows: each have a 50 percent interest in the Rundle Project. Esso agreed, from March 1, 1985, to fund all program costs until construction of the first stage of a commer- CPM/SPP QUEENSLAND TERTIARY cial development commences, up to a maximum period SHALE OIL RESOURCES of 10 years. (Billion Barrels) Condor Oil Shale Project, In Situ CPM/SPP Queensland Deposit Name Shale Oil Interest Condor is the largest of the Companies' oil shale Condor 9.65 9.65 deposits. A 20,000 tons bulk sample of Condor shales Duaringa 3.72 3.72 was shipped to Japan for large scale pilot plant trials. Lowmead 0.74 0.37 Nagoorin 2.65 1.32 Condor research effort was carried out by the Com- Nagoorin South 0.47 0.47 panies in cooperation with the CSIRO Division of Rundle 2.65 1.32 Energy Chemistry. Stuart 2.51 2.51 Yaamba 2.82 0.28 Shipment of Condor oil shale to Japan was completed 25.21 19.64 early in 1985. This was supplied under contract to the Total Japan Oil Shale Engineering Company (JOSECO). JOSECO is co-ordinating the construction and operation of a 250 tons per day pilot plant of Japanese design, due to be commissioned in 1987. Condor material is to be one of several international shales under test. Locations of the Queensland oil shale projects are Following completion of the Condor Joint Feasibility shown in Figure 1. Study, in October, 1985, the Companies allowed to expire the period for which the Japan Australia Oil Rundle Oil Shale Project, Shale Corporation had the exclusive right to negotiate participation in the next stages of project development Queensland at Condor. On the technical front, Esso, as operator of the Rundle project, conducted several series of trials in the Exxon Stuart Oil Shale Deposit, Shale Retort pilot plant at Baytown, Texas, utilizing Rundle shale from the Lower Ramsay Crossing and Queensland The unit, rated at five tons Kerosene Creek Members. The attractive ore grades in Stuart's southern area per day, showed encouraging operating characteristics continued to receive the Companies' attention during on Rundle shale. 1985. In preparation for the tests, an 1,100 ton bulk sample of One oil shale member, known as Kerosene Creek, offers Kerosene Creek shale was mined using a novel extrac- an excellent opportunity for initial development. Cov- tion method - 1 meter diameter coring, with a ered by only 16 meters of overburden, it could be mined 2.8 meter long core barrel to extract full seam inter- to provide 10,000 tons of high grade ore per day for at cepts of oil shale to depths of up to 60 meters. Thirty least 20 years. The average grade would be 185 liters three holes were drilled, providing exposure for detailed geological logging and allowing sampling which simu- of shale oil per ton (44 gallons per ton) measured at zero moisture. lated selective mining. In addition, an infill resource drilling program was The most flexible mining method is likely to be by conducted in the Kerosene Creek Member, comprising means of large diesel excavators loading into haul

2-5 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 trucks, in combination with scrapers, and the later their foremost oil shale deposit on which to initiate addition of conveyors to transport shale to the process development. plant. Strip ratios of less than two and a half to one (by volume) are estimated. Nagoorin Oil Shale Deposit In the study, conversion of the oil shale to raw synthe- Queensland tic crude oil would be achieved by a single Lurgi LR retort, built to a scale well within its current techno- The Nagoorin Technical Screening Study (NTSS) is crit- logy limits. ically reviewing all information from previous Nagoorin investigations including resource data and information The existing infrastructure of the nearby city of Glad- generated by the Comparative Processing Character- stone could be readily expanded for such a project. In istics of Australian Oil Shales Study (Project COPCAS). addition, investigations indicated that there are no Project COPCAS is a collaborative program managed environmental issues likely to impede development. by the CS1RO Division of Energy Chemistry and sup- The Companies continue to regard Stuart as potentially ported by a grant under the Federal Government's

2-6 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 National Energy Research, Development, and Demon- Means Oil Shale Project, USA stration Program (NERDOP). In 1982 the Companies applied to the United States Synthetic Fuels Corporation (SFC) for financial assis- Nagoorin South Oil Shale tance for the development of a project at Means, Deposit, Queensland Kentucky in the United States However, the SFC has now been disbanded. Drava Corporation has indicated Characterization studies were completed on samples that it is considering withdrawing from the Project. from this deposit. Oil shale samples were studied by the CSIRO Division of Energy Chemistry in the During 1985 the Companies significantly scaled down "NERDDP" research project. Samples of the deposit their activities in connection with the Means Project. were found to respond similarly in retorting processes The project area was appraised with a view to relin- to oil shale from the Rundle and Stuart deposits. quishing those leases with little or no resource development potential. The remaining leases are now kept on a care and maintenance basis. The Companies intend to Lowmead Oil Shale Deposit, keep the prospect area intact until market conditiops Queensland warrant re-activation of a development program. Samples of Lowmead oil shale from the Korenan Oil Shale Member were tested by the CSIRO Division of Luxembourg Oil Shale Project, Luxembourg Energy Chemistry in the "NERDDP" research project. Pyrolysis studies indicated that reaction rates of the During the year inquiries were initiated and negotia- samples were not very different from Rundle, Stuart, tions undertaken concerning the possibility of financial and Duaringa deposits. Combustion of spent shale support by the European Economic Community under showed a similarity in reaction rate to samples from certain EEC energy research schemes. These inquiries the Condor deposit. are continuing.

Duaringa Oil Shale Deposit, Montcey Oil Shale Deposit, France Queensland Application has been made to reduce the surface area During the year an engineering study was completed on of the permit to cover only the more prospective the Duaringa oil shale deposit. No technical imped- eastern area. As the village of Montcey will not be iments to development were identified. included in the reduced permit area, the Authorities have suggested the permit should be known as "Perrnis The Duaringa deposit is large, containing the equivalent de Mont Morian" in future. of 3.72 billion barrels of in situ shale oil at a grade above 50 liters per dry ton, but the shale has a rela- Geological data of previous years have been evaluated tively high in situ moisture content. The study was and a preliminary feasibility study has been carried out. based on a project processing 66,000 tons per day of oil shale to produce 20,000 barrels per day of synthetic crude oil for 25 years. An area of the deposit was Springe Oil Shale Deposit, identified, capable of satisfying this production rate Federal Republic of Germany which could be mined using open cut methods with a volumetric overburden ratio of less than 3:1. This A three-year extension to the term of the Permit has overburden ratio is higher than that applying to the been granted. Evaluation of geological data and re- Companies' other deposits. Duaringa is also farther serve calculations was carried out and alternative min- from established infrastructure. For these reasons ing schemes were considered. Duaringa has less potential for development than the Rundle, Stuart, or Condor deposits.

GARY REFINING COMPANY EMERGES FROM Yaamba Oil Shale Project, CHAPTER 11 BANKRUPTCY Queensland On July 24, 1986 Gary Refining Company, Inc., an- During the year an additional 14 holes were drilled in nounced that the Reorganization Plan for Gary Refining the Yaamba Basin to assist mine planning, quality Company, Inc., Gary Refining Company, and Mesa Re- control, and to obtain samples for process testing. fining, Inc. has been approved by the United States Bankruptcy Court (District of Colorado). The compan- Process testing was carried out by Lurgi GmbH in ies filed for protection from creditors on March 4, 1985 Frankfurt, West Germany. The results of the small under Chapter 11 of the United States Bankruptcy scale tests are considered encouraging. Code. Payments to creditors are expected to begin upon start-up of the Gary Refining Company (GRC) Engineering studies of a project designed to produce refinery in Fruits, Colorado after delivery of shale oil 50,000 barrels per calendar day were continued through from Union Oil's Parachute Creek plant. In the interim, the year. These studies have demonstrated substantial CRC will continue to explore options for possible start- cost reductions from previous estimates, attributable up (on a full scale or partial basis) prior to that time. mainly to the selection of more efficient mining systems and minesite preparation.

2-7 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 GOVERNMENT

WORKSHOP HELD ON OIL SHALE TEST Representatives of Mesa College, in Rangety, Colorado CENTER--DOE REPORT DUE presented a proposal for Mesa College to house the 5,000 volume BIJM oil shale library after BLM closes Its On June 26, 1987 the Associated Governments of oil shale projects office. Northwest Colorado (AGNC) held a workshop in Meeker, Colorado for the purpose of exploring possibili- Although the workshop participants were by no means ties to develop a Western Oil Shale Test Center. The united in their views, some of the broad recommenda- workshop was intended to bring federal, state, and local tions on which a general consensus was obtained government officials together with industry, scientific, include: and educational representatives to discuss the scope, location, timing, and potential funding sources for es- • More oil shale R&D is needed tablishing such a center. About 70 persons attended. • The federal government must play a major role AGNC efforts began as a specific attempt to help • Marketing research is needed on by-products obtain funding for continuation of the Cathedral Bluffs project on tract C-b. However, once the project spon- • Industry needs a consistent federal energy sors decided to request a lease suspension for that policy tract, AGNC broadened Its efforts to include Utah and • There should be an oil shale center to retain Wyoming officials to assess regional oil shale research institutional memory of R&D efforts. needs and possibilities. At the conclusion of the workshop a follow-up commit- The United States Department of Energy was charged tee was established to try to present a united Color- by Congress with investigating and making recommen- ado/Utah/Wyoming position in Congress. The commit- dations on the establishment of a "generic" oil shale tee plans to meet with the region's congressional repre- research center. That report is due at the end of sentatives to develop a national policy for oil shale September 1986. AGNC intended the workshop in development. The committee hopes to develop specific Meeker to serve as input to that study, and to swing any alternatives, with cost estimates, for location of a recommended location toward the western oil shale national test center. area.

United States Bureau of Land Management Director R. Burford made a presentation on the status of the ELM oil shale leasing program. He expressed willing- ness to help make land and/or oil shale available for such a center, but said the group should not look to ELM as a funding source.

2-8 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ECONOMICS

FAVORABLE CONDITIONS NOTED FOR Stuart/Kerosene Creek Shale Project AUSTRALIA SHALE OIL The upper Kerosene Creek seam overlying this deposit In a presentation to the conference at Captiva Island, could be mined to provide 10,000 tonnes of ore per day Florida sponsored by the Council on Synthetic Fuels in for 20 years at an average grade of 1.16 barrels per May, the relatively favorable conditions for oil shale tonne measured at zero moisture. This provides an development in Australia were noted by J. V. Browning, excellent basis for a relatively small capacity plant to Executive Director of Southern Pacific Petroleum and be the pioneer commercial installation in Australia. Central Pacific Minerals. A joint study venture with Lurgi GmbH established that The majority of Australia's oil shale reserves are loc- a plant producing over 8,000 barrels per day of ated in Queensland where in situ reserves of about upgraded shale oil could be built for $230 million 27 billion barrels of shale oil have been demonstrated. (United States). Operating costs would average US$12 These deposits, according to Browning, share character- per barrel. istics which make them more economic to develop than deposits anywhere else in the world. These qualities include: Economic Analyses • Favorable Grade—ranging from 16 to 40 gallons A measure of the competitive advantages offered by per ton Australian deposits can be obtained from Table 1 where cost data per barrel has been updated to 1985 United • Open Pit Mine—thick deposits near the surface States dollar and exchange rates. These results are • Mild Climate---semi-tropical, pleasant living based on a highly refined syncrude which would sell at a premium over crude oil. S Abundant Water • Near Deep Water Ports—for inexpensive water Depending on what forecasts for oil prices and Austral- transport ian government policies might be, an insight into when Australian oil shale projects will be viable can be • Near Required Infrastructure—power, natural derived from Table 2 where further assumptions In gas, rail and road transport project parameters are made for a 50,000 barrels per • In locations which are not environmentally sen- day plant working in the Stuart deposit. Such a plant sitive. might follow a pioneer Stuart plant. Improvements in efficiency and costs which can be expected from current research and previous pioneer experience are antI- The Rundle Oil Shale Project cipated in the first case. Improvement is assumed equal to that of the successive SASOL plants. The Present plans envisage construction of a first stage importance of the project financing terms is illustrated capable of processing 25,000 metric tonnes of wet shale in the next two cases which translate Case 1 into per day to yield over 17,000 barrels per day of upgraded leveraged financing from the United States and Japan. shale oil. Following successful operation of this The last column summarizes the probable cost of new Stage 1, further Stages II and Ill, each for 50,000 metric crude oil landed in Brisbane from the Cooper basin. tonnes of wet shale will be successively constructed and operated. At full capacity the whole complex will These figures suggest that Australian oil shale deposits produce about 75,000 barrels of upgraded shale oil each can economically replace any new oil which is likely to day. be found within Australia. In 1983 United States dollars, investment estimates for the project were $645 million for Stage I and Government Attitude $2,650 million for the entire project. Since that time, the exchange rate for the Australian dollar has fallen Since government responsibilities affecting oil shale in from 0.9 to 0.7 to the United States dollar so that these Australia are shared between the Commonwealth and totals have decreased. the state of Queensland, the policies and attitudes of each are important in developing such projects.

The Condor Oil Shale Project Queensland Government—Onshore ownership and administration of natural resources is vested in the A two year study concluded that a 75,000 barrels per state government. Queensland had traditionally day production plant could be constructed at an encouraged the private development of its mineral estimated cost (again in mid-1983 United States dollars) resources and never more so than under the present of $2.35 billion. Operating costs at full production government. In addition to a cooperative attitude would then average $10 per barrel. in formulating mining rights and infrastructure, oil shale developers could possibly receive special assistance in the form of:

2-9 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

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2-10 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 • Lower state royalties in the early years of a project. • A state franchise agreement which pre- empts the rights of local governments in favor of a project. • Construction by state and local entities at their expense of power, water, and harbor facilities to service a large project. • Sometimes direct financial assistance to projects desired by the state have been discussed. The degree of commitment to oil shale development may decrease after the reign of Mr. Peterson but the generally cooperative attitude of the state government is likely to persist. Commonwealth Government—Historically the attitude of the Commonwealth is less consistent. Their authority is especially important in five areas: • The price of oil to Australian refineries is set by the Commonwealth government. At present this closely approximates the landed price of Arab Light crude oil in Australia. • Rules for foreign investment in Australia. Generally such natural resource projects must retain a 50 percent Australian ownership. • Taxation policy. • Permission to export production. • Direct Commonwealth financial assistance. Browning feels that Australia is the ideal country in which to start an oil shale industry. The location and character of its oil shale deposits confer an appreciable cost advantage on them as compared with those of other countries. The currency exchange rate is likely to remain favorable. The country will require an increasing level of oil production for its own use and is well situated to supply some of the oil needs of the vigorously growing nations of the Pacific rim. The governments involved will accomodate and assist the growth of this industry. The vast spaces of Australia with their small but technically sophisticated population predispose the country for this type of a resource plus technology industry.

2-11 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TECHNOLOGY

IGT PATENTS FREE FALL RETORTING PROCESS United States Patent 4,578,176 issued March 25, 1986 to P. B. Tarman and assigned to Institute of Gas Tech- nology, reveals a process for retorting solid organic materials, particularly oil shales, by reacting free falling solids in a countercurrent gas stream.

According to the patent description, the process can use as feed material any solid organic material having sufficiently high density to cause solid particles of a size providing reasonably reactive surface area to fall in a lean solids stream countercurrent to a gas stream. The particle size may vary over quite wide ranges depending on the density of the solids. Suitable particle sizes are preferably about -10 to +200 (United States) sieve.

Referring to Figure 1, the oil shale may be provided from a storage hopper (21). Any suitable solids feeding means may be used. The feed solids are introduced to the reactor through the vessel top bell and pass over baffles (24) to provide even distribution of flow across the reactor. The solids fall by gravity and pass sequentially through solids preheat and pretreatment zone I, reaction zone II, heat addition zone Ill, and gas preheat zone IV. Heat addition zone Ill is provided between gas preheat zone IV and reaction zone II to provide the necessary addition of heat to maintain the reaction zone 11 at temperatures of about 800 0 to 2,000°F. The spent solids leave the reactor by a solids discharge conduit (19) at the reactor vessel bottom. Gas passes through the reactor countercurrent to the falling solids. Gas at or near ambient temperature is introduced through conduit (31) and passes upward through a distributor plate (32). In the gas preheat zone IV the free falling solid particles transfer heat to the countercurrent flowing gas stream. The gas stream is further heated in heat addition zone Ill which may be considered as the lower portion of reaction zone II. Hot gas or hot non-reactive solids may be introduced through conduit (44). The amount of heat necessary to add in zone Ill is that amount sufficient to maintain the reaction zone II at desired temperatures of 800° to 2,000°F. The temperatures in reaction zone IL are maintained at about 800° to 1,200°F for the production of liquids and at about 1,400 0 to 2,000°F for the production of gases. Thermal energy may also be provided to zone III by addition of combustible material through conduit (41) and mixing with an oxygen-containing gas, such as air, introduced through conduit (42). The upward flowing hot gas stream entering reaction zone II is in an amount of about 15 to 25 standard cubic feet of gas per pound of raw carbonaceous material in countercurrent flow. The solids move downward through the reaction zone at about 0.5 to 2 feet per second, while the heat-containing gas moves counter- currently upward at a now rate of about 2 to 4 feet per second, providing solids residence times in the reaction zone of 20 to 200 seconds. These velocities are expressed as absolute rates of travel, not relative to each other.

2-12 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 One feature of this invention is high carbon conversion When hydrogen is used as the heat-containing gas, the with high heat-up rate of the solid particles. Heat-up process may be carried out at total pressures of about rates of 1,0000 to 10,000°F per minute are preferred for 1 atmosphere to 1,500 psia. most carbonaceous materials. Laboratory tests using shale particles of -170 to +200 (United States) sieve size in a nitrogen stream at 1 atmosphere pressure show that a rapid heat-up of 4,000°F per minute to a temperature of 899°F results in high total carbon conversions SOLVENT DEDUSTING OF SHALE OIL without any additional retention time at that tempera- DEVELOPED BY AMOCO ture. The Dust Problem In the solids preheat and pretreatment zone I, thermal transfer between the heat containing gas and carbona- Colloidal, inorganic dust must be removed from shale ceous solids takes place, cooling the gas and heating the oils produced by above ground retorting. The dust can solids. When hydrogen-rich gas is used, it additionally foul heat exchangers, plug catalyst beds, and cause pretreats the organic material in such a manner as to other problems in downstream upgrading processes. improve production of saturated liquid and gaseous Dust enters the oil when vapors from the retort are hydrocarbon products in the reaction zone. The upward condensed. Some of the dust can be removed from the moving gas stream also carries with it the gaseous and vapors with cyclones or other devices but no gas-solid vaporized liquid products from the reaction zone. The separation technology has been demonstrated to be height of the solids preheat and pretreatment zone may highly efficient for removing shale dust. Moreover, be sufficient to allow substantial thermal exchange to retorts that give higher oil yields, such as fluid-bed take place which heats the free falling solids to near retorts, are suspected to give higher dust carryover into the desired temperature of the reaction zone. This is the oil products. practical due to the lean solids which will continue to flow uniformly even in the presence of condensation on Solvent extraction processes are among the more pro- cold feed material as is encountered by moving bed mising techniques for removing the dust from shale oil. reaction systems. The gas stream passes upward to a Mechanical processes alone, such as centrifugation, are solids/gas separator (33) located near the top of the expensive or ineffective and unlikely to be practical. reactor. The solids/gas separator may be conventional The dust loading in the oil typically exceeds 5 weight cyclones. The solids/gas separator is preferably located percent; the average size of the dust particles is 2 to within the reactor vessel so that the solids may be 5 microns in diameter. In solvent extraction processes, returned directly to the solids preheat and pretreat- the oil is washed from the dust with a solvent. The ment zone for recycle. Gas with entrained product solvents are recovered by evaporation. The main vapor and gases passes from the reaction system difficulty in extraction processes is obtaining an ac- through conduit (34). ceptable settling rate for the dust. For this reason, supercritical processes have been proposed for dedust- The fuels produced according to the invention vary with ing shale oils. These processes, however, must operate the gas used. When hydrogen is used as the upflowing at high pressure. gas, the product stream comprises principally hydrocarbon liquids and low molecular weight paraffinic gases. The paraffinic gas products include methane, ethane, The Amoco Process propane, butane, and isobutane. When air, oxygen, steam, flue gases, or mixtures thereof are used as the Amoco Oil Company, under the sponsorship of Rio gas, the product stream will also contain steam, carbon Blanco Oil Shale Company, has developed an alternative dioxide, carbon monoxide, and nitrogen in amounts extraction process that gives very high settling rates at depending on the type and quantity of gas used. ambient pressure. In Amoco's process, mixtures of light alkanes and alcohols are used as solvents. Specifically, When liquid products are desired, withdrawal conduit alkanes with 3 to 9 carbon atoms and alcohols with 1 to (50) removes gas with entrained liquids and vapor from 4 carbon atoms are effective solvents. the upper region of reaction zone II. The gas stream is then passed through a cooler (51) to liquid/gas separator Figure 1 illustrates the equilibrium behavior that Is (52). The gas stream is reheated by passage through generally observed for mixtures of shale oil, light heater (54). The heated gas is returned to upward flow alkanes, and alcohols. Dusty shale oil was used in through the solids preheat zone by passage through the constructing this diagram. Because the dust is an plenum defined by gas distributor plate (56) and solid immiscible component, it is excluded from the diagram plate (57). Solids falling through preheat zone I are for clarity. Also note that the oil is a heavy shale oil directed into a solids conduit (60) and pass through obtained by distilling off the lighter components. By valve V6 (such as a trickle valve, a seal-pot valve, or a concentrating the dust in a fraction of the oil, solvent J-valve), and are redistributed across the cross section use is reduced. of the reactor by distributor baffles (58). When liquid product is desired, the process conditions may be ad- When this heavy dusty shale oil, alkane, and alcohol are justed so that less than 20 percent of the organic mixed, two regions of equilibrium behavior are material is converted to gas. observed. In the one phase region, below and to the right, the three components are substantially miscible, and the dust settles slowly from solution at rates

2-13 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 The properties of shale oil vary significantly as retorting conditions, especially temperature, change. Any TYPICAL EQUILIBRIUM BEHAVIOR viable dedusting process must be capable of acqom- FOR MIXTURES OF SHALE OIL, modating diverse feedstocks. Table 1 lists the proper- LIGHT ALKANES AND ALCOHOLS ties. of heavy shale oils produced at three retorting temperatures. As temperature is increased, the oil Alcohol becomes denser and has a lower molecular weight. The o Components dust contents of the oils were similar. Miscible o Components TABLE 1 o. Immiscible • Saturated PROPERTIES OF OILS PRODUCED AT VARIOUS RETORTING TEMPERATURES 0 0 Solution 0 0 Base Base 0 Retort Temperature, °C o 0 Base +40 +35 Oil Gravity, *API 22 11.5 13 Oil Mole Weight, g/mol 320 295 245 0 Dust Loading, % Feed 37 38.5 39 0— Shale Oil Alkane around 1 foot per hour. In the two phase region, the oil is partially miscible with the solvents, but the dust Each of these oils was dedusted in a continuous unit. The feed rates to the unit were around 1 kilogram per settles at rates exceeding 100 feet per hour. The two hour. The volume of the dedusting unit was turned over solvents are completely miscible in all proportions at every 10 to 15 minutes. The results of these tests are the fixed temperature used to obtain these data. Test shown in Table 2. compositions in the one phase region are located by diamonds; in the two phase region, by open circles. The compositions of the saturated solutions formed in the TABLE 2 two phase region are located by filled circles. The phase boundary between the two regions is fixed by the locus of filled circles. DEDUSTING RESULTS OBTAINED FOR OIL PRODUCED AT VARIOUS When dedusting by solvent extraction, the settling rate RETORTING TEMPERATURES of the dust and the recovery of dedusted oil must be simultaneously maximized. This is accomplished by using compositions in the two phase region near the Retort Composition Oil Dust phase boundary. The oil in the solvent-rich phase is Temperature Oil/Allc/Alc Recovery Carryover ultimately recovered as the dedusted product. The rC) (Wt%) (wt%) (Wt%) second phase serves to agglomerate the coliodal dust particles. This accelerates the settling of the dust, but Base 21/31/48 93 0.8 the oil in this phase is rejected with the dust. Base +40 21/23/56 91 0.2 Base +85 26/11/63 92 1.2 Dedusting Results

Shale oils were dedusted in batch and continuous units. The latter has two counter-current stages, each consisting of a mixer and a settler. Oil recoveries exceeding 90 weight percent were obtained for heavy oils produced at a variety of retorting Tests were carried out in a continuous dedusting unit temperatures. Only the heavy oil fraction was with a heavy shale oil having a molecular weight of 330 dedusted. Oil recoveries on a whole oil basis were 97 to and a gravity of 130API, and containing 47 weight 98 weight percent. Oil losses were around 15 weight percent dust. For the points in the two phase regions, percent of the dust rejected. The minimum oil losses the dust rapidly separated from the dissolved oil. The obtained with acceptable separation rates correlate volume of the dedusting unit was turned over every with dust content of the feed. The extraction process twenty minutes while dust carryovers averaged rejected 97 to 99.5 weight percent of the dust con- 0.3 weight percent on a solvent-free basis. The best tained in the feed. Dust carryovers are reported on a compromise between the separation rate and oil recov- solvent-free basis. The dust carryover for the second ery occurs for points near the phase boundary inside the oil was substantially lower than the others because a two phase region. knock-out pot was added to the unit for this test. The

2-14 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 knock-out pot increased the volume of the unit by DIFFICULTIES OF ARSENIC MANAGEMENT IN 30 percent, and served to minimize the dust carried SHALE OIL REFINING REVEALED over by turbulence in the settlers. Although not unique to shale oil, the presence of At ambient pressure, mixtures of alkanes and alcohols arsenic in the liquid oil is of special concern because of give superior dedusting results compared to using either its relatively high concentration. Depending on both of the solvents separately. Below their normal boiling the resource and retort type, arsenic concentration may points, alcohols are relatively immiscible with shale oil vary from a few parts per million to over 100 ppm. so that oil recoveries are low. Alkanes are substantially miscible with heavy shale oils, but the dust separates A recent report by UOP Inc. reviews techniques to slowly from solution. Table 3 compares test results for safely manage the arsenic associated with shale oil neat alkane and alkane-alcohol solvents obtained from a production. Two approaches were investigated: continuous dedusting unit. The feed had properties similar to the second oil in Table 1. In each test, the • Crude shale oil arsenic solubilization temperature was near the normal boiling point of the • Deposited arsenic passivation or extraction. solvent(s). Higher solvent to feed ratios were required to give acceptable settling rates for the alkane, yet much higher throughputs were possible with the mixed Arsenic Solubilization solvent. Similar dust carryovers were obtained for the two systems, but higher oil recoveries were obtained The first hypothesis investigated involved converting for the mixed solvent. This is related to the relatively the arsenic in the raw shale oil to a water soluble low dust concentration in the sludge for the neat compound. This might be accomplished by injecting a alkane. solubilization reagent downstream of the retort into the oil-water mixture. After the two phases are allowed to TABLE 3 coalesce, the water phase is drained off leaving a shale oil with reduced arsenic content. The water containing arsenic could then be further treated, if necessary, to COMPARISON OF DEDUSTING RESULTS render it environmentally safe. USING A NEAT ALKANE AND A MIXTURE OF ALCOHOL AND ALKANE Desalted, western United States shale oil with 19 ppm arsenic was utilized for a series of experiments attempting to convert arsenic into water soluble com- Alkane/ pounds. For these experiments, the water, reagent, and Alkane Alcohol shale oil were intimately contacted in a shear-type mixer. The type of emulsion formed while adding Solvent/Feed, Weight 3 2 various reagents was observed, and the arsenic level Residence Time, Minimum 100 20 left in the oil was measured. Dust Over, % Oil 0.2 0.3 Oil Recovery, % Feed 84 91 A summary of results is shown in Table 1. Arsenic solubilization ranged from 13 to 52 percent. The removal of arsenic was probably accomplished by the formation of an insoluble material that is associated with the emulsion. The water solubilization of arsenic from shale oil does not appear to be very promising. Solvent Recovery Arsenic Passivation and Extraction Although light alkanes and alcohols are relatively inexpensive, they must be recovered efficiently from the dedusted oil and sludge if this process is to be economi- Catalytic hydroprocessing or hydrotreating is the most widely used catalytic process in petroleum refining. In cal. Light alcohols have relatively high heats of this operation the hydrocarbon and hydrogen are passed vaporization, but can be evaporated with low-grade over a catalyst at relatively high temperatures and steam. Low-grade steam should be abundantly avail- pressures to remove contaminants from and add hydro- able from many retorting processes. Amoco's work has shown that negligible solvent losses are obtained when gen to the oil. The catalysts used in the operation are the dusty sludge is stripped with 50 psig steam. Follow- typically a base material of alumina and/or silica with various amounts and combinations of nickel, moly- ing a flash at 1500C, 0.3 weight percent alcohol remains bdenum, and cobalt. in the dedusted oil while the entrainment of alkane is negligible. Thus, the solvents can be recovered effi- The common contaminants of sulfur and nitrogen are ciently with low-grade steam. removed as H2S and NH3, respectively. The metallic compounds present in the hydrocarbon such as vanad- These results demonstrate that solvent extraction with ium, nickel, iron, and arsenic are removed from the oil light alkanes and alcohols should be a viable process for and remain closely associated with the catalyst. In removing colloidal dust particles from shale oil. shale oil hydrotreating operations, the arsenic concentration on a catalyst at the end of its useful life could be equivalent to about 20 percent of the fresh catalyst weight.

2-15 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1 FIGURE 1 SIMULATED EPA TOXICITY SHALE OIL ARSENIC SOLUBILIZATION STUDY TEST ON USED CATALYST

Arsenic 100 Reagent Observation in Oil Legend (pp m) 90 • As received o Fe53 treated 10% KOH Emulsion stable, broken by 10.8 I CaCO3 treated addition of isooctane/ 80 o CuS treated methanol A H2SO4 treated 3% 10% H2 SO4 No emulsion (armed 16.6 A HNO, treated 50% Acetic Acid Formed emulsion which 14.7 10 slowly broke E Id3 10% Na2S Formed emulsion which did a so not break with isooctane/ C methanol treatment 0 (1) One hour at 220C 11.7 j so (430°F) under 100 ATM of 0 broke 40 WN Centrifuged at 7,000 ppm 8.1 part of the emulsion broke 30

.23 Before arsenic-laden catalysts can be disposed of as non-hazardous wastes, the aqueous solubility of arsenic as measured by the EPA Toxicity Test must be reduced 10 _ to less than 5 ppm. /67 ___ 0 Samples of spent catalysts were thermally treated by 0 1 spreading the catalyst pills inside a 1 inch silica tube 2 3 and heating under controlled atmospheres. As on catalyst, wt.% Thermally treated and as-received samples were then extracted in various solvents. same, arsenic sulfide, and arsenic oxide, it appeared The chloroform-washed catalyst samples were then that arsenic would be removed at elevated tempera- subjected to a modified EPA Toxicity Test for arsenic. tures in either oxidizing, reducing, or neutral atmo- As shown in Figure 1, the arsenic solubility of the spheres. chloroform-washed catalyst appears to be a linear function of the arsenic content of the catalyst. In order to meet the EPA limit, the catalyst would have to contain As shown in Figure 2, the volatility of arsenic from less than 0.2 weight percent arsenic. spent catalyst was dependent on temperature, residence time, and atmosphere. It appears that a temperature of Metal salts were blended with the used catalyst, then about 500°C is required to break down the original heated in an inert atmosphere in an attempt to fix the arsenic minerals and to ensure adequate vapor pressure arsenic as metal arsenides or metal arsenous sulfides. of volatile species. If the rate of arsenic volatilization It was anticipated that conversion to these compounds can be increased, arsenic might be recovered by such a would cause the arsenic to be less soluble; however, as process. shown in Figure 1, this proved to be unsuccessful. Arsenic extraction results, from catalysts that were The EPA test was also performed on several used thermally oxidized at the severe conditions of 500°C in catalysts that had been previously extracted with sul- 5 percent oxygen, were very similar. None of the furic and nitric acid solutions. The arsenic solubility thermal treatments produced a material that allowed was decreased; however, the arsenic level remaining on high levels of arsenic extraction. In the best case, the catalyst was still too great for direct disposal. As about 80 percent of the arsenic was removed by a shown in Figure 1, in order to meet the EPA limit, it combination of thermal treatment and leach extraction. would be necessary to reduce the arsenic content on the Increasing the Icachant concentration to increase the acid-washed catalyst to about 0.5 weight percent. arsenic extraction would result in considerable alumina dissolution. An alternative approach to arsenic recov- If essentially all of the arsenic could be volatilized in a ery utilized solution oxidation. Acid digestion of as- roasting process, arsenic collection would be feasible. received used catalyst was performed in a stoichio- Considering the relatively high vapor pressures of ar- metric quantity of sulfuric acid.

2-16 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Since none of the tested approaches seem satisfactory, FIGURE 2 additional research will be necessary before an acceptable arsenic management technique can be devised. EFFECT OF THERMAL TREATMENT ON ARSENIC VOLATILIZATION 100 # ### • SO, 1HR TEXACO PATENTS BOREHOLE REAMING METHOD OSO,2HR - FOR RADIO FREQUENCY EXTRACTION GCO1HR 1 002 5%1 HR - United States Patent 4,576,231 issued March 18, 1986 AO,5%2HR --- Al to D. J. Dowling and H. A. Palmer of Texaco concerns a 70 A02 5%6HR ---- method for keeping the borehole clear when a radio C I frequency in situ extraction method is used. o 60 I I There have been extensive theoretical studies which are 50 supported by a certain amount of experimental work on I a method of heat transfer to down hole formations by g40 electromagnetic propagation at radio frequencies. / '0 Figure 1 is a schematic diagram showing the basic 30 elements of equipment for carrying out such radio / I, frequency heating in situ. The procedure involves a I 20 bore hole (11) that extends into an oil shale formation. -, II In order to apply the radio frequency energy down hole II at the formation there is a central conductor or pipe 10 •.4° / * (15), which is coaxial with an outer casing or shield pipe 0 f (16). Pipe (16) acts as a coaxial shield for the electro- 0 magnetic radio frequency energy being applied. At the 100 200 300 400 500 600 700 800 900 surface, there is a generator which applies high- Temperature, *C - powered radio frequency energy to the central conductor pipe via circuit connection (20). The circuit to the coaxial shield (16) goes via a circuit connection (21) The digestion was carried out under reflux for 8 hours. In order to obtain high recoveries of the elements, the reaction had to be carried out at a positive solution potential. This was accomplished by adding 3 weight FIGURE 1 percent HNO3 to the sulfuric acid. Results showed 90 percent recovery of arsenic was achieved with both the 10 and 20 weight percent sulfuric acid solutions. SCHEMATIC OF TEXACO RADIO FREQUENCY Conclusions HEATING EQUIPMENT The hOP researchers have concluded that used cata- aec lysts from processing shale oil will contain higher levels / FNWdroe of soluble arsenic than allowed by the EPA for non- Ii I hazardous disposal. Much of the arsenic is present on the catalyst as thermally stable metal arsenides and metal arsenous sulfides. It was not possible to fix or passivate the arsenic on the catalyst in an insoluble form by thermally treating the catalyst either with or without additives. MIR Leachants, which do not dissolve excessive quantities of alumina, extract only about 20 percent of the arsenic from non-thermally treated catalysts. Increasingly severe thermal pretreatments allow up to 75 percent of the arsenic to be extracted by dilute leachants. Results of toxicity tests on pretreated catalysts indicate that high extraction levels are necessary before the residue is acceptable. Although digestion was successful in dissolving the arsenic, digestion of as-received spent catalyst requires a high solution potential in order to achieve good extractions.

2-11 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 that is grounded. There is good electrical connection to the pipe (16) by a conductor (22) insulated from the FIGURE 3 coaxial shield or outer conductor pipe by insulating packers as shown. The structure in Figure 1 becomes RADIO an applicator for the electromagnetic propagation of radio frequency energy. Such an applicator may be FREQUENCY CONDUCTOR described also as an antenna. The exposed portion (29) WITH "CHISELS" of the central conductor (15) functions as a transmit- ting antenna. As formation temperature is raised by the heating effect of radio frequency energy absorption, the kerogen undergoes a chemical transformation. During the process, as heat is being absorbed and the chemical conversion begins in situ, the earth formation is subjected to expansive forces which fracture and expand the rock masses toward the bore hole. As the heating continues the rock will squeeze in and may engage the applicator's central conductor (29). This results in serious loss of electromagnetic energy into the formation. Often the swelling and approaching of the formation will be accompanied by high voltage standing wave ratios and reflected radio frequency power. Further- more if the rock intrudes close enough to the unshielded portion of the central conductor, it will cause arcing between the central conductor and the formation. Any or all of the foregoing conditions will preclude efficient transfer of the radio frequency energy to the formation.

The invention deals with this problem by making the alternative design in Figure 3 makes use of a third central conductor movable in order to periodically coaxial pipe (38), which is stored inside the coaxial remove the encroaching formation. Figure 2 illustrates shielding pipe (16). In this manner it does not interfere how the central conductor may be modified by having with the radio frequency propagation during the heating steel protuberances or bumpers (30) mounted externally procedure. Then, as the formation has swollen and on the conductor (29). Consequently, when the con- intruded into the heating operation the pipe (38) may be ductor is moved up and down and/or rotated the forma- lowered as indicated in Figure 3 so that it may be tion will be mechanically removed by breaking it away. rotated and/or vibrated in order to cut the intruding formation away and clear the borehole. The patent also describes an apparatus which may be FIGURE 2 employed to provide the necessary vertical movement or oscillation of the central conductor pipe. RADIO FREQUENCY CONDUCTOR WITH BUMPERS"

OIL SHALE COMBUSTOR MODEL DEVELOPED BY GREEK RESEARCHERS Work carried out in the Department of Chemical Engi- neering at the University of Thessaloniki, Thessaloniki, Greece has resulted in a model for the combustion of retorted oil shale in a fluidized bed combustor. The model is generally applicable to any hot-solids retorting process, whereby raw oil shale is retorted by mixing with a hot solids stream (usually combusted spent shale), and then the residual carbon is burned off the spent shale in a fluidized bed. Although some processes carry out the shale combustion in a lift pipe rather than a fluidized bed, these researchers believe that a fluidized bed is preferable, for the reasons listed Instead of the bumpers, a number of other structures in Table 1. such as chisels or teeth could be attached. Another

2-18 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1

COMPARISON OF FLUID BED AND RISER COMBUSTORS

Item Riser Combustor Fluid Bed Combustor

Operating Temperature Riser exit temperature Flexible due to the greater than 1,200°F increased particle required residence time Gas Requirements Determined by the mini- Determined by the car- mum transport velocity bon combustion re- of the particles quirements Carbonate Decomposi- High due to the high Potentially low due to tion combustion T and resi- the lower combustor dence time in the col- temperature lecting bin Carbon Conversion Incomplete due to low Potentially high due to residence time flexibility in solids residence time and temperature Commercialization Need to develop scale- Limited due to the ex- Requirements up criteria for large tensive fluid bed coal size units combustor experience

TABLE 2 They found that the model results were strongly dependent on the calculated size of the gas bubbles in a fluidized bed. The calculated bubble size varies widely VARIATION IN CARBON CONVERSION depending on the theoretical equation used (Figure 1). (Average Solids Residence Time Although the lack of experimental data in this area Equals 10 Minutes) makes it difficult to assess the model results, the authors of the study point out the importance of grids in reducing bubble size. Tempera- lure Pressure Bubble Model Carbon (Figure 1) Conversion The variation in carbon conversion (percent carbon ("K) (ATM) (Cranfield&Geldart) burned) as a function of combustor temperature, pres- (%) sure, and bubble size is given in Table 2. It was noted 894 1.4 C&G 37 that this model does not account for change of reactive 894 1.4 C&G -5 Grids 50 particle diameter with time. As a result the calculated 894 2.7 C&G 62 carbon conversions are conservative. The results shown 894 2.7 C&G -5 Grids 100 in Table 2 indicate that a higher pressure operation of 978 1.4 C&G -5 Grids 64 the combustor results in increased carbon conversion 978 2.7 C&G -5 Grids 100 and that the effect of bubble size depends on the unit pressure. At low pressures where the carbon burning rate is low, reducing the bubble size has a relatively minor effect on carbon conversion. That is, the carbon conversion is kinetically controlled. At high pressures, where the kinetic rates are high, the effect of bubble By considering the recombination of CO2 with MgO and size is significant. In this regime the carbon conversion CaO, it was found that percent carbonate decomposi- is mass transfer controlled. tion is reduced at low temperatures and low residence times. The percent carbonate decomposition was found to be a strong function of temperature. At temperatures under This is mostly due to the effect of CO2 pressure on 978°K, the decomposition of CaCO3 is negligible. This MgCO3 decomposition. At high temperatures where implies that at low temperature, only MgCO3 decom- the decomposition pressure of calcite is high, the effect poses. This will result in only low energy losses due to of reduction in MgCO3 decomposition due to the pre- carbonate decomposition. The decomposition curves sence of CO2 is negligible. These results imply that are seen to flatten at higher temperatures due to the minimum carbonate decomposition (less than 15 pecent) fact that all available MgCO3 has been decomposed is achieved when the combustor operates at tempera- while the CaCO3 contribution is still very low at these tures below 922°K and for residence time less than conditions. 15 minutes.

2-19 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 MEAN BUBBLE SIZE VS. BED HEIGHT

350— MODEL I: WEN $ MOW ... MODEL 2: CRANFIELD & GELDART 300— ---MODEL 3: CRAN. & GELD. --5 GRIDS

250 - S N 200- a ISO 3 S 100 - - 0' ...... •

a •SSS .... Go- ...'fl'"''"" ------p ------

0- I I 0 1.5 3.0 4.5 6.0 7.5 9.0 BED HEIGHT FT

Based on their modelling work, the following conclu- FULL SCALE BLAST MEASUREMENTS REVEAL sions were drawn by the researchers: NO DUST HAZARDS • For the retorted particle size distribution The United States Bureau of Mines has been involved in selected (average particle diameter 1,600 mic- monitoring oil shale blasts to expand its data base and rons) complete carbon conversion is feasible at to explore correlations between this field work and high pressures (2.7 atmosphere) and over the experimental research. entire temperature range studied (8940 to 978°K). In August 1985, two Colorado oil shale mines invited the Bureau to participate in three additional full-scale • Bubble size was found to have an important blasts. From the knowledge and experience obtained in effect, especially at conditions where reaction the earlier blasts, the research effort this time focused rates are high (high temperature and pressure). nearer to the face in order to better estimate the • Carbonate decomposition increases with com- explosion hazards there. Emphasis was placed on bustor temperature and residence time. Com- accurately measuring the airborne dust concentrations plete carbon conversion is feasible at high pres- produced during the blasts and collecting post-blast sures (2.7 atmosphere) with less than 20 percent floor dust samples to determine if the airborne dust carbonate decomposition. near the face was of sufficient concentration to support a secondary explosion. The Bureau is attempting to • At the preferred combustor operating condi- better understand the explosion dynamics and potential tions (high pressure, low temperature) the main hazards which may be associated with the development reaction is dolomite decomposition while cal- of as much as 3,000 tons of oil shale from a single cite decomposition is negligible. blasting face. Data were obtained during earlier blasts • Recombination of CO2 with MgO occurs at low at Exxon's Colony Mine. temperatures, high pressures, and long particle residence times. Instrumentation Based on the above, there is a clear incentive to verify the conclusions of this study in a large-scale system Figures 1. and 2 are diagrams of the three blasting zones where pressurized combustion can be tested. that were monitored in August 1985 at two Colorado oil shale mines. Figure 1 illustrates the position of the two target faces for blasting in one of the mines. The instrumentation in this figure is depicted as it was positioned for blast 4. The instrumentation was relocated in a similar manner for blast 5 by moving the

2-20 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 MAP OF BLASTING AREA FOR BLASTS 4 AND 5

_JBlast5 Blast 4

essur transducer JRPre Auxiliary fan—a° Airflow R R £

LEGEND o so laO If £ Camera . Instrument stand — Camera flash • Gas sampler o is 30 m R Respirable dust Scale sampler

FIGURE 2 MAP OF BLASTING AREA FOR BLAST 6 CROSSCUT NQ7 LEGEND —C Canaan slapping • Camera Cc.nra flash R RebS dust sampler • lnstrunwnt stand New taco-1 AuxiliaELyo t fan •R • Control - • base ' t LW o so toot? CROSSCUT NÜ9 0 IS 30m Scale equipment to the next face. Figure 2 displays the the dust cloud arrival times at the probes, the wind equipment as it was installed for blast 6 in the second velocities of the dust clouds. The optical path lengths mine. for the probes were 5 centimeters, and air jets were directed over the sensor windows to eliminate obscura- Sampling of floor dust loadings deposited during the tion due to coating of the windows. To lessen the earlier blasts provided a reliable estimate of the air- contamination by existing mine dust, the majority of borne or float dust concentrations up to 550 feet down- the mine floor was wetted with water prior to the blast. stream. However, the post-blast rubblization generally covered the collection plates within 40 meters of the In blasts 4 and 5, the optical dust probes were posi- original face. For blasts S and 6, careful attention was tioned within the first open crosscut, about 40 meters directed toward sampling dust from the rubble pile to from the face. Two probes were mounted on one stand: determine if the concentration nearer the face may the first 1.5 meters and the second 3 meters above the have been of sufficient quantity to represent a second- mine floor. Across the entry, the other probe was ary explosion hazard. A total of three dust probes were about 1 meter off the floor. In blast 6, the two-probe utilized in each recent blast to provide a better esti- stand was located approximately 85 meters out from mate of the dust concentrations and to calculate, from

2-21 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 the face at mid-entry; the other stand was 15 meters the mine floor were necessary to eliminate the uneven farther down the entry. For this blast, the instrument floor surfaces encountered in earlier blasts. In blast 6, stands were in a direct line of sight to the face. To all the production holes were loaded from the back of determine the respirable dust concentrations produced each hole to within 5 meters of the face, with each hole during a 1 hour period following the blasts, several containing 50 kilograms of AN-FO. The presplit and sampler units were positioned throughout each zone. production holes for every blast were II centimeters in diameter. Non-electric blasting caps with time delays A high speed, evacuated-vial sampling system was in- of 25 through 600 milliseconds were used in the blasts, stalled in each of the recent blasts to draw batch as shown in Figure 3. samples of the mine atmosphere every 2 minutes.

Observations, based on film taken in an earlier blast, Blast Results showed evidence of flame near the face. It was indeterminate from the film whether the flame was due A uniform fragmentation and distribution resulted from to the burning of oil shale or the explosive material blast 6. The rubble pile extended out by the original from the unstemmed blastholes or a combination of face about 50 meters. The presplit holes and the both. Two 16 millimeter movie cameras were mounted powder factor (AN-FO loading) were the primary condi- on the mine roof in an explosion-proof housing about tions affecting both the extent and size of the rubbliza- 40 meters from each of the blast faces in order to give tion. Larger boulders associated with blasts 4 and 5 a visual record of the detonations and to document any were a result of the different blasthole pattern; the secondary explosions. larger rubblization was preferred at this mine because of their retorting process. In blasts 4 and 5 the blast faces were 15 meters by 8 meters and were drilled to a depth of 7.3 meters. A Dust samples were collected from measured rock sur- total of seven presplit holes were drilled into the face faces at various locations on the rubble piles. From along each rib. Figure 3 is the blasthole pattern for previous research, only the finer particles were found blast 6, when the face was 17 meters by 9 meters. This to present potential explosion hazards; therefore, only pattern used one additional presplit hole along each rib the minus 20 mesh dust from each sample was analyzed, and contained four fewer production holes. The holes in eliminating the small flyrock and very coarse particles. this pattern were 9.5 meters deep. The dust loadings generated during blasts 5 and 6 are Detonation of the presplit holes 25 milliseconds prior to plotted along with those samples gathered in the earlier the initial detonation of the production holes provided blasts in Figure 4. The earlier blasting research pro- the necessary expansion space, similar to that of under- vided a reasonable estimate of the dust loadings from cutting a coal face, and minimized rib damage. The 40 to 165 meters out by the new face. In Figure 4, the dashed lines in the figure show the 32 degree V-cut at floor dust loadings are shown as the left ordinate, and the center of the faces. The four additional holes near the nominal volumetric concentrations (assuming the

FIGURE 3

BLASTING PATTERN FOR BLAST 6 (OPEN CIRCLES ARE THE PRESPLIT CHARGE WITH NO DELAY AND SOLID CIRCLES ARE THE MAIN CHARGE) o 0 15 14 14 15 . . . S o 0 KEY No. O.Ioy, Ms 0 - I 25 3 75 50

/5• to 6cttntrt)ctr:c:r:J t!

s,.

2-22 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 4 FLOOR DUST LOADINGS (MINUS 20-MESH FRACTION) AFTER 5 BLASTS. 260 '. ' I • I I -28 A 240 E 220- -24 200- KEY 9 ISO - - 20 < (6 t Blast 160- Blast I- o Blast Z - 16 si 140 8b05t5 = a BlastS t I20 u - 12i... 100- U, D 0 80- - o X 0 C 60 z • S • .4 •$ 40 - • I • x I 20F rOriginal face, I ' 0 30 60 90 120 150 180 0 - DISTANCE FROM NEW FACE, m

dust to be dispersed throughout the cross section) are diately following the blasts. The quartz content of the shown as the right ordinate. The samples in blasts 5 samples ranged from 4 to 14 percent. and 6 were taken exclusively from the rubble piles to determine if the nominal dust concentrations nearer the In blasts 4 and 5, the static pressure exerted against the face were high enough to promote secondary explosions. ribs was approximately 4 psig at about 25 meters from The nominal concentrations on the rubble pile increased the face. The pressure measured from blast 4 at the from 6 to 28 grams per cubic meter as the distance to control base 65 meters away in the adjacent room was the face decreased. These average concentrations are about 0.6 psig; and the pressure measured at the control higher than those sampled in previous blasts but remain base in blast 5, 115 meters from the face, was about an order of magnitude below the experimentally deter- 0.3 psig. The main transducer for blast 6 was located mined lean limit concentration for explosions of fine 85 meters from the face and recorded a peak static sized oil shale dusts of similar grade. The surface mean pressure of about 1.5 psig. Additional transducers were diameters (DS) and the weight mean diameters (DW), mounted on several test stoppings located over were calculated from the size distributions of the minus 430 meters from the blast face during blast 6. The 20 mesh fractions of the samples. Within 45 meters of maximum recorded pressure exerted against these ven- the face, DS ranged from 15 to 137tm, DW ranged tilation stoppings was about 0.16 psig. from 50 to 315pm, and the minus 200 mesh fraction ranged from 10 to 81 percent. The range of values is Problems encountered during the earlier blasts pre- similar to those of earlier blast findings, and no system- vented measuring the airborne dust concentrations pro- atic variation with distance was found within this area. duced from the exploding rock at the face. This time The assay of the floor dust samples ranged from 15 to careful attention was given to wetting the mine floor, 25 gallons per ton. This is lower than found in earlier particularly in front of the optical dust probes, to data. suppress the existing floor dust and to lessen the probability of entrainment of that dust. For blasts 4, 5, Previous data had shown lower assay for the finer sized and 6, very low dust concentrations were calculated dust particles. During the earlier blasts, the particle from the high transmission measurements (95 to 99 per- size of the oil shale became finer and the assay lower cent) recorded from the dust probes. However, even as distance from the face increased. The lower assay these transmissions over the 5 centimeter optical path of samples analyzed from the rubble pile in the latest length of the probe would correspond to a very low blasts may be due to the variability in the grade of the visibility over a distance of a few meters. The mea- rock being blasted and/or the slightly finer dusts result- sured transmission values of 95 to 99 percent are con- ing from these blasts. sistent with the measured floor dust loadings at the positions of the dust probes. Close to the face, there Several respirable dust sampling units were positioned were probably higher airborne dust concentrations, as at various locations within the blast zones. These units shown by the billowing clouds in the high speed movies were operated for a 1 hour period during and imme- and the higher floor dust loadings.

2-23 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 In the 16 millimeter movie film for blast 6, flame was evident for at least 220 milliseconds after ignition, at which time the dust totally obscured the view. Similar results were observed in other blasts. It is uncertain whether the flame luminosity at the face was due solely to the explosives in the unstem med blastholes or partly due to localized burning of the oil shale dust clouds. There was no evidence of flame luminosity after the end of the blasting sequence. The high-speed movie cameras were very successful in documenting the three blasts on film. There was no evidence of any excessive flame after the end of the blasting rounds. There may still exist small pockets of high concentrations of dust that could cause localized secondary explosions near the face, but there was not enough dust generated to cause large-scale propagating secondary explosions.

2-24 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 INTERNATIONAL

TACIUK PROCESSOR PROPOSED FOR AUSTRALIA tions. However, it is believed that the basic flow OIL SHALE scheme will be largely unchanged. Since 1977, the Alberta Oil Sands Technology and The Taciuk Processor consists of two concentric hori- Research Authority (AOSTRA) in conjunction with zontal vessels or kilns which rotate together. The UMATAC Industrial Processes, Division of JiMA Engi- design of the Processor is such that individual compart- neering Ltd. (UMATAC) have pioneered the developments or zones are created within the Processor and in ment of a novel thermal retorting system for the which all of the basic processing steps occur (Figure 1). extraction and primary conversion of bitumen occurring in oil sands. This retort is known as the Taciuk Run-of-mine ore is fed by conveyor into a preheat zone Processor. in the inner kiln. Here, water is evaporated, and the feed is preheated by heat exchange with hot tailings. The Taciuk Processor has demonstrated an ability to Steam given off in the preheat zone, which may contain satisfactorily process run-of-mine oil sands in pilot some low boiling point hydrocarbons, is condensed and plant operations and it is thought by AOSTRA that the the light hydrocarbons are recovered and included in Processor may be equally capable of processing oil the total liquid product. The preheated, dry feed then shales. passes through a solids seal into a reaction zone where it is intimately mixed with recycled hot, oil free While the principle of the Taciuk Processor has re- tailings. The temperature of this mixture of fresh feed mained virtually unchanged since it was conceived over and recycled solids feed is sufficient (500 0C+) to ther- 10 years ago, the specifics of design and operation have mally crack the bitumen in the oil sand feed and evolved through 7 years of testing in a 5 tons per hour vaporize the cracked liquid hdyrocarbon products. The pilot plant located at Calgary, Alberta. During this vaporized cracked liquid and non-condensable gases exit time more than 12,000 tons of oil sands have been the kiln and are recovered as cracked liquid oils and processed successfully in the pilot. The majority of the refinery fuel gas in a fractionation system. Coke pilot plant work has been conducted on a variety of oil formed by the cracking reaction coats the inert sand. sands from Alberta's Athabasca deposit. However, The coked sand flows through a seal Into a combustion successful operation has also been achieved on consoli- zone where preheated air is introduced to burn the coke dated sands obtained from the United States and Mada- thereby raising the temperature of the tailings above gascar. the reaction zone temperature to provide the heat for the process. Auxiliary burners provide trim control and Processing oil shales would be expected to lead to heat for start-up. A portion of the hot, coke depleted variations in the design developed for oil sands applies- sand is recycled to the reaction zone to raise the

2-25 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 preheated teed to cracking temperature. The net flow ENERGY EFFICIENCY ANALYSIS CARRIED OUT of coke depleted sand passes into a cooling zone where FOR PETROSIX PROCESS it gives up most of its sensible heat to the incoming teed. In the design of chemical plants the effective use of energy has always been an important consideration. In While a limited amount of batch testing has been the production of shale oil, the effective use of energy carried out on oil shale samples from both the United is critically important for the viability of the process. States and Australia, much more work needs to be done, The design of the Petrosix process developed by Petro- particularly in the continuous flow pilot plant. A prime lea Brasileiro S.A. (Petrobras/Superintendencia de In- concern is whether or not the granules of crushed shale dustrializacaO do Xisto (SIX)) reflects such a preoccu- will remain largely intact in the combustion zone so pation with energy efficiency. A semi-industrial plant they may be recycled as the heat carrier into the for the production of shale oil, the Irati Prototype Unit reaction zone. If the material disintegrates, a supple- (UPI), is being operated successfully by Petrobras in Sao mental heat carrier may be required. In addition, the Mateus do Sul in south central Brazil. Brazil has the dust loading in the product and flue gas streams would world's second largest reserves amounting to 800 billion require very high capacity dust removal systems. barrels of shale oil. The connate water contained in Athabasca oil sands An industrial module with a scale-up factor of 4 is may vary between 1 and 10 percent depending on the under construction. The plant, due on stream in 1988, ore grade. All of this water would be driven off in the will produce 2,650 barrels per day of shale oil and preheat zone of the Processor. The same would gen- 50 metric tons per day sulfur. Future plants will be a erally hold true for oil shales. However, in the case of multiplication of such modules. A thermodynamic shales from the Kerosene Creek area of the Stuart energy analysis of the retorting section of the industrial deposit in Australia the free water content may be as module was carried out by Petrobras in order to iden- high as 22 percent. In such a situation it might be tify critical points where the thermodynamic efficien- advantageous to pre-dry the feed to less than 5 percent cies can be improved. A mass and energy balance of moisture before entering the Processor. the plant was made using mainly the process design data. The energy availability functions of different Bench scale batch tests conducted on samples of oil streams were evaluated and a lost work analysis was shales from the Stuart deposit in Australia and also done for different units of the retorting section. from Colorado have provided the product yield data in Results were reported in Energy Progress in March Table 1. These data are the averaged results of several 1986. tests which gave reasonably consistent results. The data available at this time on oil product quality are The retorting section of the Petrosix process (Figure 1) not conclusive but typically the liquid oil gravity would is characterized by operational simplicity. Oil shale, range from 26 to API. after crushing to a particle size range of 6.35 to 69.85 millimeters, is continuously fed into the top of the retort. The charging mechanism is comprised of a TABLE 1 rotary feeder and an anti-segregational mechanism. Through the rotary feeder oil shale is introduced into the retort and inert gas is injected to prevent the entry OIL SHALE OVERALL PRODUCT YIELDS of air or the escape of pyrolysis gases. The anti- (WEIGHT PERCENT ON HYDROCARBON segregational mechanism distributes the charge to the IN FEED) FROM TACIUK feed tubes which spread it evenly over the retort, PROCESSOR BATCH TESTS avoiding segregation. As the shale moves down the retort under the action of gravity, it passes successively through the drying, heating, pyrolysis, and cooling Stuart Colorado zones. Australia U.S.A. A thermodynamic lost work analysis rather than an Gas, C3(-) 7.8 5.1 energy analysis was used because of the advantages of Liquid Oil C4( +) 55.2 64.2 calculating thermodynamic properties of complex Gross Coke 37.0 30.7 streams with existing data and because of the difficulties in computing the lost work of the retort from Total 100.0 100.0 energies of different streams. The lost work for each unit of the plant is calculated from a combined energy and entropy balance equation. In Table 1, (ama) is the sum of the availability flows leaving a unit minus the sum of those entering the unit, The results of this very preliminary work on processing and t W is total work done by the system on the oil shales in the Taciuk Direct Thermal Retorting surroundings, which includes the shaft work, electrical System are thought to be technically encouraging. work, and the work resulting from expansion or con- AOSTRA and UMATAC believe that future pilot plant traction of the control volume against the surroundings. operation could establish the Taciuk Processor as a technically and economically viable oil shale retorting system.

2-26 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1 fuel gas and the irreversibili ties resulting from the heat transfer from furnace temperature to the temperature RELATIVE AMOUNTS OF LOST WORK of recycle gas are the reasons for the high loss for the (Percent) fired heater. It is interesting to observe that a first law analysis would indicate an efficiency of nearly 90 percent, leading to the conclusion that there is little Unit room for improvement in this sector. However, the Operation/Equipment (-mB) LW thermodynamic efficiency can be improved by changes in other parts of the plant, for example changing the Fired Heater 46.2 (0.4) 46.6 retort operational conditions or the feed shale moisture Retort 34.7 - 34.7 content. It can also be improved through heat recovery Main Light Oil Condenser 8.2 (0.3) 8.5 from the burning of spent shale in a fluidized bed Hydraulic Sealing System 3.7 - 3.7 combustor. Inert Gas Generator 2.4 - 2.4 Compressor (10.5) (12.3) 1.8 In the retort there are two basic sources of lost work. Spray Cooler 0.8 - 0.8 One is the temperature gradient necessary for heat Secondary Light Oil 0.5 (0.1) 0.6 transfer from hot recycle gas to the oil shale, the other Condenser is the irreversible endothermic decomposition of kero- Electrostatic Precipitator 0.5 - 0.5 gen. The thermodynamic efficiency of the retort and Cyclone 0.4 - 0.4 the overall process can be improved by pre-drying and/or pre-heating the shale rock which is entering with Total 86.9 (13.1) 100.0 about 5 percent moisture. The moisture indirectly accounts for about 30 percent of the fired heater duty. This suggests that perhaps different zoning of the retort for drying, heating, pyrolysis, and cooling will lead to higher performance in future designs. The relative values of the calculated lost work are Although accounting for large amounts of external presented in Table 1 for different units of the retorting work, the percentage of lost work in the compressor is section of the shale oil plant. not high. A part of the work done is recovered as low quality heat. Some possible improvements have been The fired heater and the retort account for the major identified in this sector, as the cold recycle gas does part of the lost work. The irreversible combustion of not need the same pressure as the hot recycle gas.

2-27 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

In the hydraulic sealing system, a part of the low TABLE 1 pressure vapor generated by the quenching of the retorted shale by sealing water can be used in another sector, for example for pre-heating air in the fired CHARACTERISTICS OF IMPORTANT LIGNITE heater. However, collection poses a problem as some AND OIL SHALE RESERVES OF TURKEY inerts enter the system unavoidably. Some amount of work is lost in the condensers although Total Mois- not as much as a first law analysis would indicate. Name Reserve Ash ture VM LCV There is also a possibility of utilizing the hot air (MM Tons) BF &T -r (kJflcg) produced in the fired heater. These process modifications will result in a higher overall efficiency of the Zonguldak 539.2 13.3 9.6 24.4 27,839 plant. Heat recovery from streams like the cold Tuncbllek 220.3 24.9 20.8 24.3 15,215 recycle gas stream and product gas to the condensation Soma 515.0 23.5 15.1 32.1 15,591 system stream can be considered. In the case of the Can 128.3 30.4 21.4 25.5 11,704 gas stream before the precipitator, heat recovery would Seyitomer 228.6 14.8 31.0 28.4 13,627 eliminate the spray cooler. Orhaneli 58.5 24.2 26.8 24.6 11,202 Beypazari 222.0 34.8 22.1 25.1 10,283 The analysis identified several low temperature heat Yatagan 535.1 15.8 37.3 28.2 10,617 sources available in the plant which can match with Saray 143.0 16.8 44.9 19.2 8,276 sinks in other sectors of the plant after upgrading. The I{angal 176.0 21.0 48.3 19.8 5,685 low pressure steam can perhaps be effectively mixed Elbistan 3,539.0 23.3 49.5 18.3 4,680 with high pressure steam from the boiler and can be Seyitomert 1,000.0 68.5 5.0 25.7 12,540 effectively used in other parts of the plant. Another Goynuk- 2,500.0 32.0 - - 12,720 possibility is to use mechanical vapor recompression. Bolut In general, the study points the way toward a fine- Bituminous Coal tuning of the retort heat balance. "Oil Shale

FLUIDIZED BED COMBUSTION TESTED thermal output. This aggravates 50x and parti- FOR TURKISH OIL SHALES culate emission problems. • Sulfur content is very high (about 2.5 percent). About 7.5 billion tons of lignite and 5 billion tons of oil • Nitrogen contents are higher than world aver- shale deposits are potential energy sources and there- age. fore potential air pollution sources for Turkey. The low calorific value, and high ash and sulfur contents of • Ash and water contents are also high. these fuels render fluidized bed combustion a promising • Properties fluctuate drastically within a single method of utilization. reserve. This will create problems in com- However, most of the existing worldwide fluidized bed bustor design and efficient operation. combustion experience is based on bituminous coals, the • The low ash fusion temperatures pose combus- combustion behavior of which may be significantly tion difficulties in conventional combustors. different from that of Turkish lignites and oil shales. Specific development work on fluidized bed combustion It is expected that more and more lignite will be burnt systems may be necessary if this technology is to be for electricity, process steam, and residential heating. implemented successfully in Turkey. Air pollution has already reached alarming levels during winter months especially in the inland towns of Anato- A fluidized bed combustion system with a nominal lia. Given the characteristics of Turkish lignites and oil capacity of 418,000 to 627,000 kilojoules per hour for shales FBC seems to be a promising solution. producing hot water has been designed and constructed at Istanbul Technical University. Researchers in the However, the Istanbul Technical University team be- Department of Chemical Engineering note that there lieves that the design of lignite and oil shale-fired are many potential benefits of fluidized bed combustion fluidized bed combustors for use in Turkey will be (PBC) systems to burn lignites and oil shales with different in many respects. For example with high effective sulfur dioxide and NOx emission control. quality coals, the active bed plays an important role as a heat generator and exchanger. Generally, the free- Table 1 gives the important characteristics of the main board serves mainly as a disengagement device. In the Turkish lignite and oil shale reserves. case of lignite and oil shale utilization, however, the active bed may act as a partial heat generator and the These data show that: freeboard as a partial heat generator and full exchanger. Relative to bituminous coals significantly greater amounts of Turkish lignites and oil FBC units may be designed to accept a wide range of shales must be burned to achieve the same fuel inputs compared to the conventional solid fuel

2-28 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 burners. However, the variation in the characteristics CANADA OIL SHALE POTENTIAL LIMITED of lignites in Turkey will require an extremely versatile TO NEW BRUNSWICK design. The deviation in calorific value can be almost 40 percent and in some cases agglomeration can occur A review of the potential for oil shale development in at temperatures as low as 870°C. Canada was presented at the June 1986 symposium "Canada's Hydrocarbon Reserves for the 21st Century" Lignites and oil shales, being high in volatile matter, by G. Macauley. The theme presented to the sympos- tend to burn differently in FBC than higher grade coals ium was that oil shales are a definite future source of which generally have lower volatile matter contents. petroleum substitutes in North America. Specific econ- This behavior makes the FBC freeboard an active omics for their development are not yet clearly de- medium for combustion of volatile matter. Therefore, fined; however, the factors which will establish the the freeboard should be designed with secondary air economics can be outlined for the more significant injection and with the assignment of heat transfer tubes Canadian deposits. The only one with apparent near- to the appropriate places where heat release is intense. term potential is the Mississippian Albert Formation at Albert Mines near Moncton, New Brunswick. Table 1 shows that the calorific value of the Turkish lignites and oil shales may be an important design Macauley points out that oil shale exploration and constraint since reserves below 5,016 kilojoules per development will involve problems far beyond those kilogram are considerable. The high volatile matter encountered either in the conventional petroleum in- contents of these low calorific value fuels means that dustry or in oil sands. Oil shale ores can be extremely during normal operation no heat may be available from heterogeneous, much more so than oil sands. They can the active bed itself. In this case the fluidized bed acts vary both laterally and vertically in lithologies and as a hot gasifier. mineralogies, and in both quantity and maturation of source kerogen, with resultant major variations of min- An FBC system for hot water production from Turkish ing characteristics and of retorted hydrocarbon pro- lignites and oil shales has been constructed at Istanbul ducts from within a single ore body. Technical University with the design parameters given in Table 2. A portable heat transfer panel makes it Possible to adjust the heat removal from the active bed. Albert Mines Deposit, New Brunswick Thus, it is possible to operate the bed as a hot gasifier in extreme cases of very low calorific value fuels where The oil shales at Albert Mines deposit are easily the no heat should be removed from the active bed. most promising of known Canadian deposits. Ore occurs as three main rock types: high grade laminated TABLE 2 marlstone, low grade clay marlstone, and moderate grade dolomite marlstonc and dolostone. An estimated DESIGN DATA FOR ITU PILOT FBC 270 million barrels in situ shale oil reserves are contained in an area of 2.6 square kilometers to a depth of Capacity, kJ/b 418,000 627,000 600 meters. About 100 million barrels are available per Operational Temperature, °C 800 800 square kilometer of surface area, which may be mineable by surface techniques to a depth of approximately Characteristics of the Fuel 100 meters. Of these potential reserves, 150 million Calorific Value, kJ/kg 6,270 12,540 barrels are contained in the dolomite marlstone, 67 mil- Moisture, % 45 26 lion barrels in the laminated marlstonc, and the re- Ash, % 22 27 mainder in the clay marlstone. Sulfur,;% 3 4 Feed Rate, kg/b 85 42 The complexities for mining become apparent as the Air Feed Rate, m3/s 7.5x10-2 5.6x10-2 laminated and clay marlstones will require minimum Operational velocity, m/s 1.86 1.37 Bed Height, m 0.40(adjustable) effort for their exploitation; however, the dolomite Bed Crass-Section, m 2 0.40x 0.4 marlstone may require blasting at the mine face. Freeboard Height, m 2 Heat Transfer Area, m2 Oil shale retorts are generally designed to operate on Active Bed 1 (0.022 m ID.ST 30 uniformly graded crushed ore. The varied crushing steel pipe) characteristics of Albert oil shales may preclude the Freeboard 5 (0.022 m ID.ST 30 use of a single type of retort to process all the ore. steel pipe) There is no reason that different retort systems cannot Material of Construction 0.005 m, sheet iron be inter-utilized to provide optimum processing and oil Insulation Materials 50% AI203 refractive recovery. lining and 0,06 m fiber glass Based on recovery potential, the laminated marlstone is Coal Feeding Arrangment Freeboard and in bed the best unit, averaging 22.3 gallons per ton (United feeding are possible States) with many yields in the 24 to 38 gallons per ton range. Recoveries from the dolomite marlstone beds Distributor Plate Nozzle type and per- forated plate type are lesser, averaging nearer 14.4 gallons per ton (United States) but also with individual yields much in excess of Bed Material Quartz sand, ash 24 gallons per ton.

2-29 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Potential reserves are greater for the dolomite marl- Kettle Point occurs in an area of farmland, industrial stones because the zone thickness greatly exceeds that development and residential districts. Thicknesses are of the laminated lithotype. such that underground mining, or a form of in situ retorting, may be practical, in which case exploitation The Albert oil shales remain of economic interest would be a possibility. Although overburden is typically because of their location in the center of an energy- only 30 meters, the present surface land usages miti- deficient area. At Minto, New Brunswick, up to gate against surface exploitation techniques. 30 meters of overburden is stripped to exploit 0.3 meter of high sulfur (7 percent) coal to be burned for the generation of electrical power. Sulfur emissions are a Stellarite, Nova Scotia consequent problem. Research at the New Brunswick Research and Productivity Council, Fredericton, has Near the towns of Stellarton and New Glasgow, within determined that SO, emissions can be contained below the Pictou coal mining district of Nova Scotia, an oil Canadian environmental standards by the co-combus- shale-coal seam, averaging 3 meters in thickness, con- tion of oil shale and coal in a fluidized bed combustor sists of generally equal intervals of an overlying coal at a ratio of 2.6:1 oil shale to coal. bed and an underlying torbanite (locally termed stellarite). Although neither appears to be economically A coal-fired 22 megawatt power generating station at attractive by itself, Macaulay believes that co-exploit- Chatham, New Brunswick, is currently being modified ation of these two energy sources may be feasible. The to co-combust coal and oil shale. Funding for the coal will yield in excess of 24 gallons per ton petroleum modifications Is estimated at $33 million, with comple- product. That oil is considered to be derived from tion in late summer 1986, after which a 40,000 tonne telaginite within the coal. Telalginite, a Botryococcus- 4,000 hour test will commence. type alga, is the prime constituent of the torbanite. If successful, current plans anticipate a 200 megawatt fluidized bed combustor at a cost of $320 million. Boyne-Favel Formations (White Further plans also involve co-linked retorting of the Specks Zones), Manitoba shale for oil products prior to the co-combustion process: research on this phase is under way at the Type II marine mixed oil shales of the Cretaceous Research and Productivity Council. Boyne and Favel Formations, characterized by white speckling resulting from the presence of coccolith debris, yield about 10 (U.S.) gallons per ton along the CoUlngwood Oil Shale, Southern Ontario north slope of the Pasquia Hills at the northern limit of the Manitoba Escarpment. Over 30 meters of gross The Ordovician Collingwood oil shale is a thin wide- zone are present in this area. Over 1.2 billion barrels spread unit of generally low yield potential (10 gallons may be recoverable by surface mining within a strip per ton). Because of the poor yield potential and 56 kilometers by 1.6 to 19 kilometers along the north limited thickness, large surface areas are necessary to face of the hills. define significant petroleum recoveries. In the Calling- wood area, on Georgian Bay, only 1.0 million barrels are At 11.50API, the oil is low grade and extremely aro- estimated per square kilometer of surface area. The matic; therefore, major product upgrading will be ne- best potential is presently known on Manitoulin Island, cessary. where 3 million barrels of in situ shale oil reserves are estimated per square kilometer. Over 12 billion barrels The Pasquia Hills, although only partially developed for of reserves can be projected from this zone. agriculture, are a scenic area, and environmental considerations will be a barrier to exploitation. Environmental considerations almost preclude any development of this oil shale interval as the shores of Several other Canadian oil shale deposits have been Georgian Bay at Collingwood and Manitoulin Island are studied, including: the Ordovician Boas beds on Sout- resort areas. hampton Island; the Middle Devonian Marcellus Forma- tion in southern Ontario; the Mississippian Big Marsh oil shales near Antigonish, Nova Scoita; the Carboniferous Kettle Point Formation, Southwestern Ontario Rocky Brook beds in the Deer Lake area, Newfound- land; and the Jurassic Kunga Formation of the Queen Equivalent to the many oil and gas shales of the eastern Charlotte Islands. Most of these are of little interest United States (Antrim, Ohio, New Albany, Chatta- because of insufficient continuous kerogen-bearing sec- nooga), the Upper Devonian Kettle Point beds are the tion or because of insufficient yield potential. most interesting of the Ontario deposits because of thickness (up to 75 meters gross zone) and location in the Sarnia area at the heart of the Ontario petrochemi- It If 0 If cal industry. According to Macaulay, an upper 10 meters of Kettle Point, present in a small area along the St. Clair River south of Sarnia, will yield an average 10 gallons per ton (United States).

2-30 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENVIRONMENT

£18 ISSUED FOR UNOCAL PHASE II EXPANSION On April 11, 1986 the United States Army Corps of Engineers (COE), Sacramento District, announced the • A new room-and-pillar underground mine and release of the draft Environmental Impact Statement crushing facilities at Old Mountain and expan- for the proposed Phase II expansion of Unocal's Para- sion of the existing mine at Long Ridge. chute Creek Shale Oil Project. The draft EIS discusses • New shale handling and surface retorting facili- the impacts of construction and operation of an ties with a total capacity of 80,000 barrels per 80,000 barrels per thy expansion of Union's completed thy at the top of Old Mountain. Expansion Phase I oil shale project. would occur in four 20,000 barrels per day increments. With the demise of the United States Synthetic Fuels Corporation, there is, of course, no chance that the • Expansion of the existing upgrading plant in project will proceed under current economic conditions. four 20,000 barrels per day increments. • A water supply system consisting of an existing If and when the project is able to proceed, the £18 Colorado River intake structure and the follow- indicates that it would be possible without exceeding ing proposed facilities: a settling basin, water the allowable PSD increments for air quality. pipelines to facilities, water treatment facilities at the upgrading plant and retorts, a back- The £15 was triggered when Union submitted an appli- up storage reservoir on the mainstem of Para- cation for a COE Section 404 Permit to place fill chute Creek, and/or other supplemental storage material In the mainstem of Parachute Creek to con- in the Colorado River drainage. struct a reservoir. Preparation of the EIS took four • An expanded common pipeline corridor from years. the Colorado River through Parachute Creek Union had applied for a 404 permit for the underdrain Valley to the top of Old Mountain, containing for the East Fork retorted shale disposal alternative. pipelines for raw and pretreated water, re-use This application was withdrawn with the relocation of water, raw shale oil, syncrude, retort gas, and the proposed retorted shale pile to Old Mountain. A natural gas. 404 permit is not required for disposal of the retorted • A proposed retorted shale disposal system shale on Old Mountain. Currently the COE does not which would eventually result in the placement regulate retorted shale under Section 404. The COE of a stablized and vegetated embankment of defines "fill material" as material discharged for the retorted shale on Old Mountain. primary purpose of raising the elevation of a water- body, not for the purpose of discharging waste material. • A connecting pipeline to transport syncrude The EPA has disagreed with the COE "primary purpose" from the upgrading plant to an existing crude definition and believes that solid material should be oil pipeline, or any future joint-industry pipe- regulated under Section 404. The issue must be line. resolved by the Administrator of the EPA and the • A natural gas supply system to Union Meadow Secretary of the Army. and spurs to Old Mountain and the upgrading plant. Overall permitting of the Phase 11 Program was coordinated through the Colorado Joint Review Process • An extension of Union's 230 kilovolt power (CJRP). The CJRP is a voluntary mechanism for transmission line to Old Mountain, and spurs to coordination of local, state, and federal permitting other new facilities. actions. • Associated road development or improvement. • The single workers' housing complex would be reopened as the local housing situation de- Proposed Action mands. In Phase II of the Parachute Creek Shale Oil Program, Union had proposed to expand its oil shale mining, retorting, and upgrading capacity by 80,000 barrels per Shale Mining day at the Parachute Creek property (Figure 1). Major Phase II material inputs would include approximately The proposed mines would be at Long Ridge and Old 115,000 tons per thy of raw shale, up to 15 million Mountain, with bench portals overlooking the East Fork cubic feet per day of natural gas, an average of Canyon. The Long Ridge mine currently supports the 14,300 acre-feet per year of water, and 185 megawatts Phase I 10,000 barrels per day retort. Long Ridge of peak electricity at full production; outputs would be facilities would be expanded and Old Mountain would be 84,000 barrels per thy of syncrude, 220 tons per thy of developed to provide the additional 80,000 barrels per sulfur, and 300 tons per thy of ammonia. A total of day production capacity for Phase IL Mining facilities approximately 600 million tons of retorted shale would are shown in Figure 2. be disposed of on Old Mountain. Major Phase II components include:

2-31 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 PROJECT FACILITIES, PARACHUTE CREEK SHALE OIL PROGRAM, PHASE II RBOW I R95W

GASPIPELINE

fljtt 2: mitt,

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2-32 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 2 MINE FACILITIES, PARACHUTE CREEK SHALE OIL PROGRAM, PHASE I AND II 200-root Prop.rtv Boundary Mahogany Gut,., 50-Foot Mark.' Zoo. Bouad,ry LONG RIDGE MINE Outcrop z.

ORE WEST KET DAY. LIGHT CROSS-CANYON FORKED GULCH ORE CONVEYOR DAYLIGHT AND / VENTILATION FAN MINE SHALE CONVEYOR BENCHES PORTAL Fork Ee° Itypati SHOP AND WAREHOUSE DAYLIGHT ORE POCKET

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2-33 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Retorting • East Fork short pile with rock underdrain to The 80,000 barrels per day raw shale oil production carry East Fork flows facility would include: • East Fork short pile with tunnel diversion of East Fork flows • Raw shale retorting facilities, including retorts, • East Fork long pile with flows carried over fluidized bed combustors, heat recovery sys- surface of pile tem, and oil and gas processing units. These would be located on a leveled site at an eleva- • Combined East Fork and in-mine tion of 8,000 feet on Old Mountain. • Old Mountain disposal sites A, B, C, and E • Retorted shale cooling, moistening, and trans- • Combined Old Mountain and in-mine. fer facilities. These would include overland conveyors running southward from the retorts The proposed Old Mountain disposal site (alternative D) to the disposal area on Old Mountain. would require about 1,600 acres to accommodate the • A raw shale oil pipeline from the retorting estimated 532.1 mllion tons of Unishale C retorted facilities to the upgrading plant in Parachute shale that would be generated during the life of the Creek Valley. Phase II program. • Support facilities. Table I lists characteristics of the nine retorted shale disposal alternatives and the proposed action. Figure 3 shows the proposed location of the retorting facilities relative to the raw shale handling system and the Old Mountain mine portal. Environmental Consequences Impact analyses were based on the assumption that Water Supply mitigation measures would be implemented by the ap- plicant and may be stipulated in the COE 404 permit, All of Union's water rights from the Colorado River and Environmental Protection Agency P50 permits, Color- from the Roaring Fork and Parachute Creek drainages ado air quality permits, CMLRB mining permit, Gar- may be used to supply Phase II. However, the primary field County Land Use permits, NPDES permits, and water right to be used is Union's Pumping Pipeline BLM right-of-way permits issued for the project. Major water right, which is decreed for 118.5 cubic feet per impacts are listed in Table 2. second from the Colorado River at the existing intake structure. During times of low water flows when the Table 3 compares estimated maximum off-property Pumping Pipeline water right would not otherwise be concentrations of criteria pollutants (i.e., sulfur dio- entitled to divert, storage water would be used. An xide, TSP, nitrogen dioxide, carbon monoxide, and annual average storage water supply of about NMHC) resulting from Phase II emissions (Unishale B 2,230 acre-feet could be required to supplement the with retorted shale disposal in East Fork Canyon) with Pumping Pipeline water right. Union proposes to con- ambient background concentrations, PSO Class II incre- struct the first stage of Parachute Creek Reservoir ments, and ambient air quality standards for these (3,500 acre-feet) for this purpose. The Parachute pollutants. As indicted in the table, project emissions Creek Reservoir would be filled with water impounded with Unishale B technology and retorted shale disposal by the dam on Parachute Creek and/or by water di- in East Fork Canyon would not exceed PSD Class II verted from the Colorado River through the existing increments or ambient air quality standards. However, intake structure. the maximum 24 hour TSP concentration of 34 ).grams per cubic meter resulting from Phase I and If mines, The Parachute Creek Reservoir was adjudicated for retorts, and shale disposal operations would consume 33,773 acre-feet in 1971 with an appropriation date of 92 percent of the Class II increment with the Uni- 1966. It is owned jointly by Union and Chevron Shale shale B process/East Fork Canyon disposal alternative. Oil Company. Each company is entitled to one-half of The maximum 3 hour sulfur dioxide concentration of this right. 501 grams per cubic meter resulting from retort/mine emissions would consume 98 percent of the Class It The proposed first stage of the Parachute Creek dam increment. and reservoir would be located approximately 2.8 miles downstream from the confluence with the East Fork, The maximum NMHC and nitrogen dioxide levels asso- and would consist of an earthen dam, a vertical shaft ciated with the Phase II expansion (56,.0 grams per cubic emeregency spillway, and outlet works. meter, 3 hour average and 28pgrams per cubic meter annual average, respectively) would occur very close to the project site. These pollutant concentrations are Retorted Shale Disposal well below significance levels.

This EIS considers nine alternative retorted shale dis- Although the project as proposed would not exceed the posal piles in either the East Fork Canyon or on top of allowable PSD increments, the project would place Old Mountain as well as the proposed Old Mountain severe constraints on any other industries locating disposal pile. These alternatives are: nearby because little air quality increment would be left for consumption by others.

2-34 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 3 RETORTING AND SHALE HANDLING FACILITIES, AND ACCESS ROADS, PARACHUTE CREEK SHALE OIL PROGRAM, PHASE II

A 96W I 21) - I . - L --- I \\' I,...

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2-35 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

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2-36 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 3

SUMMARY OF MAXIMUM AIR QUALITY IMPACTS V0Mm5 Per Cubic Meter)

Incremental Impact Highest Ambient Unishale B Unishale C P50 Background Air Pollutant/ Upgrading Retort/ Retort/ Class 11 Concen- Quality Averaging Time Plant Mine Mine Increment tration Standard Sulfur Dioxide 3 Hour 165 501 250 512 16 1,300 24 Hour 37 81 40 91 8 365 Annual Average 4 11 6 20 3 80 Total Suspended Particulate 24 Hour 9 34 41 37 93/28 150 Annual Average 1 8 10 19 33/9 60 Nitrogen Dioxide Annual Average 28 24 54 - 8 100 Carbon Monoxide 1 Hour 1,033 478 956 - - 40,000 8 Hour 252 228 456 - 1,500 10,000 Non-Methane Hydrocarbons 3 Hour (6-9 am) 21 56 56 - 69 160

SPENT SHALE PROVES EFFECTIVE ABSORBENT To date, the federal government has not promulgated FOR SULFUR EMISSIONS New Source Performance Standards (NSPS) for the oil shale industry. However, the United States Work funded by the United States Environmental Environmental Protection Agency does regulate sulfur Protection Agency and carried out by J&A Associates, dioxide (and some other emissions) through Prevention Inc. has proved the effectiveness of retorted shale as an of Significant Deterioration (PSD) permitting absorbent for sulfur oxides in flue gases. requirements of the Clean Air Act. This legislation requires use of Best Available Control Technology Need for Sulfur Control (BACT - costs considered) to minimize the emission of specified pollutants. PSD permits are Issued on a Control of sulfur emissions is a key environmental facility-by-facility basis. The federal P50 requirement concern in the retorting of oil shale. Although a typical that generally is most difficult to meet is the 24 hour shale from the Green River Formation of Colorado Class I air quality standard limiting sulfur dioxide contains only about 0.7 percent sulfur, large-scale concentrations to 5g per cubic meter. In addition to production of shale oil will require processing millions federal requirements, the State of Colorado limits sulfur dioxide emissions to less than 0.3 pounds per of tonnes of oil shale; thus, sulfur emissions would be barrel of shale oil produced. To meet this regulation very great if controls were not applied. About 16 to about 95 to 96 percent of the total sulfur in a typical 30 percent of the sulfur in oil shale is liberated to the off-gas would have to be removed. vapors (oil and gas) produced during retorting, and the remainder stays with the spent shale. Retort gases generally contain hydrogen sulfide (1125) as the major Control of sulfur emissions constitutes a major portion sulfur compound and lesser amounts of other organic of the environmental control cost for oil shale sulfur compounds such as sulfur dioxide carbonyl facilities. The J&A work has been directed toward the concept of burning the residual carbon on retorted shale sulfide (COS), carbon disulfide (CS2), and mercaptans (CH35H and C2115SH). to recover its energy value (a plus in terms of economics and resource conservation), and then

2-37 SYNTHETIC FUELS REPORT, SEPTEMBER 1996 absorbing the sulfur gases produced during retorting coolers, scrubbers, and/or baghouses are provided for onto the calcined carbonate material resulting from recovering heat and removing dust from the combustor combustion of retorted western oil shale. flue gas. NOx emissions are controlled by staged combustion; The ASSP Concept i.e., an oxygen-lean first stage followed by an oxygen- rich second stage. Spent shale from indirect heated retorts contains from 4 to 10 weight percent organic carbon, and research Spent ash is discharged and cooled for heat recovery, efforts have been directed to recovering this energy by then moisturized prior to disposal. combusting the shale, usually in a fluid bed. Initially there was some concern that excessive sulfur emissions Conceptual Designs might result because the retorted shale contains approximately 0.7 weight percent sulfur as organic For study purposes, specific retorting technologies and sulfur, pyrite (FeS2), and/or pyrrhotite (FeS). However, sites were selected as representative of three retort it was soon discovered that sulfur emissions were very types: low when combusting carbonate-containing retorted shale. Approximately one-half the mineral content of Green River oil shale consists of dolomite Retort Type Process (CaMg(CO3)2) and calcite (CaCO3). These two minerals are the essential components of calcareous Direct Heated MIS with lJnishale C rocks used in controlling sulfur emissions from coal Indirect Heated Unishale B combustion. These carbonates In oil shale are fine- Integral Combustor Lurgi grained, with grain sizes ranging from I to 10,ameters. Unishale C Fine-grained calcareous rocks are generally better sulfur dioxide sorbents than the coarse grained rocks. Cost Estimates A number of laboratory and small pilot scale experiments have shown the ability of carbonate- Equipment costs for Lurgi, Unishale, and MIS commer- containing shales to absorb sulfur emissions. cial plants were taken from the EPA Pollution Control Technical Manuals (PCTM5) which describe the Union, This concept is referred to as Absorption on Spent Shale Cathedral Bluffs (Tract C-b), and Rio Blanco Process (ASSP). The ASSP concept has several (Tract C-a) projects. Major ASSP equipment additions potential advantages over conventional sulfur removal and deletions are summarized in Table 1. technologies: Resulting changes in capital and operating cost esti- • The sorbent is cheap and inherently abundant in mates are shown in Table 2. oil shale plants. • The required combustion of spent shale is These results show that the best potential for applica- already incorporated into several retorting tion of ASSP are those processes which already have a technologies or would be a useful add-on to spent shale combustor integrated into the retorting recover residual carbon values. process (e.g., Lurgi, Unishale C, Chevron STB, and Tosco HSP). Capital and operating cost savings for • Since non-hydrogen sulfide compounds are lJnishale C and Lurgi cases are primarily a result of converted to sulfur dioxide by combustion, deleting the Unisuif and Stretford units from these ASSP should be more efficient than gas plants. sweetening processes which only remove hydrogen sulfide. For indirect heated processes (e.g., Paraho Indirect, • The process does not create any new waste Tosco II, and Unishale B), the payout on the additional disposal requirements. investment for ASSP equipment would be good to marginal depending on how effectively the add-on spent The ASSP concept uses a fluidized transport system to shale combustor can be integrated into the process. combust either raw or retorted shale, thereby providing That is, economically, it is better that heat from the the means for converting sulfur compounds to sulfur combustor products be recovered and used directly in dioxide and absorbing the sulfur dioxide in the shale the retort rather than used for steam raising. matrix. The concept envisions either a conventional dense-phase fluidized bed or a dilute-phase contactor In the direct heated cases, the results show substantial (lift pipe). Key elements of the process are shown in savings in capital costs for ASSP relative to both Figure 1. Stretford and flue gas desulfurization approaches. However, the capital savings are at the expense of Solids feed is either crushed raw shale or retorted shale increased operating costs. or a combination of the two with a top size of 1/4 inch. Air is introduced at the bottom of the contactor along with process and/or waste gases to be treated. The Pilot Plant Tests contactor is provided with coils for removing heat. Heat removed is used either for heating process gas To test the effectiveness of the ASSP concept, experi- streams or for raising steam. Cyclones, flue gas ments were carried out in a pilot plant built by Tosco

2-38 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 ASSP PROCESS FLOW DIAGRAM STEAM HEATED PROCESS OASES

FLUE NAB I:FM:OV]AL TOATMOSPHE RE - -

R RETORTED SHALE BOILER PEED LPO2En!ES ANDIOR WATER - RAW SHALE FINES CONTACTOR STEAM H20 (FLUID BED OR L LIFT PIPE) SOLIDS TO AL ...... _...... f COOLER MOISTURIZER

SOILILER PEED WATER

1 OASES

AIR

SUPPLEMENTAL FUEL (IF REQUIRED)

TABLE 1

EQUIPMENT CHANGES FOR ASSP

Direct Heated Case A: Case B. POD Stretford Indirect Heated Integral Combustor Retort Process MIS/Unishale C MIS/linishale C Unishale B Lurgi Unishale C Systems Added for ASSP: MDEA MDEA MDEA MDEA --- Fluidized Beds- - Fluidized Beds Systems Deleted for ASSP: Unisuif Unisuif Unisulf DEA Unisulf MIS POD System MIS Stretford Recycle Gas Heater Stretford MIS Steam Boiler MIS Steam Boiler Spent Shale Cooler

Corporation to develop their Hydrocarbon Solids Pro- up to 3000 to 500°F. The retort is an inclined rotating cess (HSP). The pilot plant has a nominal capacity of cyclinder in which oil shale and hot heat carrier solids 6 tons per day of oil shale and contains a fluidized bed (from the fluid bed combustor) are mixed. The feed combustor which Is 18 inches in diameter. Figure 2 is a rates of raw oil shale and heat carrier are adjusted to process flow diagram of the plant. maintain the desired temperature in the retort, approximately 900°F. Raw oil shale, crushed to minus 1/4 inch is pneumatically lifted to the shale feed weigh hopper system from The mixture of spent shale and heat carrier from the which shale Is metered into the retort at a constant retort is pneumatically conveyed from the accumulator rate. The raw shale from the weigh hopper is preheated discharge screw into the fluid bed combustor using

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2-40 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 2

COST COMPARISON FOR ASSP

Direct Heated Indirect Case A Case B Heated Integral Combustor Retorting Process MIS/linishale C Unishale B Lurgi Unishale C (Base) Incremental Capital (71.2) (63.2) 90.2 (13.0) (32.1) Cost, MM$ (Relative to Base) Incremental Annual 10.83 12.07 (19.21) (2.29) (1.56) Operating Cost, MM$/Year

* 150 psig steam $8.81/tonne (4.00 per kilo pound) 400 psig steam $9.91/tonne ($4.50 per kilo pound) 600 psig steam $11.01/tonne ($5.00 per kilo pound) Fuel Gas $2.84/gigajoules ($3.00 per million BTU) Electricity $0.014/megajoules ($0.05 per KWH)

superheated steam. The fuel residue on the spent shale is combusted to provide part or all of the heat required TABLE 3 to pyrolyze the oil shale. Combusted solids, which constitute the heat carrier, are drawn off from the fluid bed combustor and are recycled to the retort. RANGE OF OPERATING CONDITIONS AND PROCESS VARIABLES The combustor is an atmospheric, dense-phase, bubbling, fluidized bed. The spent shale fuel is supplemented as needed by injection of natural gas or Bed Temperature, OF 1,127-1,558 retort gas into the bed. Freeboard Temperature, OF 1,273-1,593 Retorted Solids to Combustor, lb/hr 2,487-3,615 Flue gas and entrained shale ash from the combustor Raw Shale to Combustor, lb/hr 0-133 are cooled, and the ash is separated in a baghouse. Retort Gas to Combustor, scfm 0-6.66 H2S in Retort Gas, vol % 0.43-9.28 Pyrolysis vapors from the retort are cooled and the oil Bed Depth, feet 3.27-4.28 and water condensed in a quench tower and overhead Solids Residence Time, min 8.07-18.72 condenser. The non-condensed retort vapors are Gas Superficial Velocity, ft/sec 3.78-7.20 diverted to a fluid bed combustor through a blower used Gas Residence Time, sec 0.46-1.13 to overcome the pressure in the bed. For the majority Flue Gas Oxygen, vol % 0-6.25 of the pilot plant tests, retort gas was burned in the Carbonate Decomposition, % 45.5-83.3 fluid bed to supply the hydrogen sulfide and non- Ca/S Mole Ratio 6.20-10.25 hydrogen sulfide sulfur compounds. In addition, hydrogen sulfide and carbonyl sulfide from pressurized cylinders were used to "spike" the retort gas to test at significantly higher sulfur concentrations. about 3 volume percent. The lowest NOx concentrations were seen at oxygen levels approaching zero but The ranges of key operating conditions for the 44 tests at the expense of higher carbon monoxide and trace performed are summarized in Table 3. Correletations hydrocarbon emissions. of emissions (502, NO,, CO, trace HC) with key process variables indicated that the only significant Good control of carbon monoxide and trace hydrocarbon factor which affected emissions was flue gas oxygen emissions was obtained at oxygen levels above about concentration. Sulfur dioxide emissions were easily 2 volume percent. controlled to low levels at virtually all conditions tested, probably as a result of the high Ca/S ratios Emissions of NOx move in a direction opposite to sulfur used. Thus, the inlet sulfur concentration is immaterial dioxide, carbon monoxide, and trace hydrocarbon emis- providing the Ca/S ratio is adequate. sions. Thus, finding a set of operating conditions which minimizes all four represents a compromise. One test It was found that reasonably good NOx control could be was run which produced nearly optimum results. Condi- obtained with flue gas oxygen concentrations below tions for this test were:

2-41 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Bed Temperature, OF 1,220 LOS ALAMOS CHARACTERIZES OIL SHALE Solids Residence Time, minutes 9.4 INDUSTRY HAZARDS Gas Residence Time, seconds 0.9 Gas Superficial Velocity, ft/sec 4.4 A study by Los Alamos National Laboratory Flue Gas Oxygen, vol % 2.6 (LA-10472-MS) titled "Health Hazard Evaluation and Ca/S Mole Ratio 10.3 Recommended Industrial Hygiene Practices for Above- Raw Shale/Spent Shale Ratio 1:36 ground Oil Shale Processing" addresses possible hazards in mining, retorting, and upgrading oil shale. Individual hazardous components and their regulated limits are At these conditions the following results were obtained: identified in Table 1. Sulfur Dioxide, ppmv 11 NOx, ppmv 160 Potential Health Hazards Associated Carbon Monoxide, vol % 0.27 With Oil Shale Mining Trace Hydrocarbon, ppmv 388 Combustion Efficiency, % 89 According to the study, the mining of oil shale by either underground or surface techniques will result in a number of potential health hazards to workers. These These tests essentially confirmed the design basis used include exposure to oil shale dusts, diesel exhaust, gases for the comparative cost estimates. and vapors produced in blasting, and gases released from mine water or the oil shale, and exposure to noise, vibration, and heat generated by heavy mining equipment. Mining will often take place under stressful environmental conditions of poor lighting as well as cold, dampness, and high humidity.

TABLE 1

HAZARDOUS COMPONENTS/LIMITS

Component Hazard TYL STEL (ppm) Oil Shale Unknown Retorted Shale PAH, Carcinogenicity Free Silica Inhalation, Silicosis Hydrogen Sulfide Toxic 1015 Sulfur Dioxide Toxic 2 5 Carbon Monoxide Toxic 50 400 Carbonyl Sulfide Toxic 10 Carbon Dioxide Asphyxiation 5,000 15,000 Ammonia Asphyxiation 25 35 Carbon Disulfide Toxic 10 20 Arsenic Toxic 0.20 0.01 Hydrogen Cyanide Toxic 10 Carbonyls Toxic 0.05 OSHA 0.001 Nitrogen Oxide Asphyxiation 3 5 Formaldehyde Carcinogenic 2 Mercury Toxic 0.05 0.1 Heterocyclic Nitrogen Carcinogenic 5 10 Compounds Heterocyclic Oxygen Unknown and Sulfur Phenols Toxic 5 10 Aliphatic Amines Toxic 5-25 Aromatic Amines Toxic 0.1-5 milligrams per cubic meter "OSHA

2-42 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The majority of these potential health hazards are not TABLE 2 unique to oil shale mining, and most appear amenable to control by techniques used In other types of mining. DUST SAMPLING IN EXPERIMENTAL UNDERGROUND ROOM-AND-PILLAR OIL SHALE MINES Mining Dusts Dust (mlllIgran/cubic, meter) Quartz Almost all operations Involved in oil shale mining Total Respirable Content (%) generate airborne dust. These operations include drill- Operation Mean Max. Mean max. Mean ing of blastholes, pneumatic charging of explosives, Blasthole Drilling 31.9 10.7 14.6 1.8 5.4 4.9 blasting, mucking and haulage of the ore, and scaling of Charging - 1.2 1.8 0.9 - - the newly exposed surfaces. Oil shale crushing opera- Blasting - 82.2 - - 14.3 14.0 tions, which may be conducted underground in some Mucking, Loading 14.1 6.2 3.3 1.3 14.4 4.6 mines, also generate dust. Scaling - 8.5 2.7 1.3 6.7 2.4 Roof Bolting 12.6 7.0 2.4 1.2 2.3 1.6 The mineral portion of Green River oil shale Is primarily a rnarlstone or a mixture of calcium and magnesium carbonates, with some quartz, silicates, and other minerals. Pockets of sodium and aluminum carbonates also particulate. Similar results of quartz analysis were occur. The quartz content of Green River oil shale obtained on samples from the two MIS oil shale mines. rock is reported to range from 10 to 20 percent. Com- pared with common rocks, Green River oil shale is reported to contain much higher levels of arsenic and Diesel Exhaust selenium (mean levels of 35 and 1.5 ppm, respectively); moderately higher levels of boron, molybdenum, anti- It Is expected that almost all mining equipment in mony, and mercury (mean levels of 65, 10, 1, and underground United States oil shale mines will be diesel 0.4 ppm, respectively). powered. Diesel exhaust contains particles of a high organic content, as well as nitric oxide, nitrogen dio- The presence of crystalline silica, such as quartz, in oil xide, carbon dioxide, carbon monoxide, sulfur dioxide, shale suggests the potential for fibrogenic lung disease. and organic gases and vapors including aldehydes and No definitive correlation of pneumoconiosis with oil polynuclear aromatic hydrocarbons (PAlO. Whether shale dust exposures has been found in workers at diesel equipment in underground mines constitutes a demonstration oil shale facilities in the United States, health hazard remains a subject of controversy. To but medical surveys have been very limited. Exper- date, no toxicological studies have been conducted to ience in Scotland and the Soviet Union suggests a examine whether the combination of diesel exhaust relatively low potential for pneumoconiosis from oil particles and oil shale dust may result in health hazards shale dusts In those areas. to oil shale miners. Pneumoconiosis has not been noted by chest X-ray in Estonian oil shale workers with long exposure histories. Blasting

Average total dust levels in mines in the Soviet Union The danger of toxic gases produced by the detonation of are reported to range from 6.5 milligrams per cubic explosives in underground mines has been recognized meter in drilling for roof bracing to 12.1 milligrams per since the early 19009. Gases of primary concern with cubic meter in horizontal blasthole drilling and to even the use of ANFO for blasting are carbon monoxide, as high an average as 52.1 milligrams per cubic meter nitrogen monoxide, nitrogen dioxide, carbon dioxide, in drilling vertical blastholes into the roof. These and ammonia. Dust and organic gases and vapors will levels are much higher than allowed in United States also be produced. Only very limited data are available mines. The quartz content of the airborne dust In on levels of dusts, gases, and vapors created in oil shale Estonian oil shale mines is reported to average 3 per- mines by blasting. Table 2 contains results of one total cent. dust sample collected soon after blasting in an experimental oil shale mine in Colorado. Samples collected Table 2 summarizes results of dust sampling in experi- at the mine portal of a second experimental mine after mental room-and-pillar oil shale mines in the United blasting showed levels of about 100 ppm of carbon States. These results Include data for total dust, monoxide, 120 ppm of total hydrocarbons, 20 ppm of respirable dust, and alpha quartz content of the dusts. nitrogen monoxide, and 0.12 percent of carbon dioxide.

Quartz content of the airborne dust in the experimental Gassy Mines room-and-pillar oil shale mines has been reported to range from 0.1 to 14.4 percent. Table 2 also sum- Deep oil shale mines located in the center of the marizes these results by operation. The overall arith- Piceance Basin of Colorado have been found to be metic mean for the 23 dust samples analyzed for alpha "gassy." Gases of primary concern In gassy mines are quartz is 5.1 percent. This is much lower than in rock methane and hydrogen sulfide. Methane is a simple or bulk dust samples. The lower level of quartz In mine asphyxiant and should not be a health hazard at levels air samples relative to quartz content of the oil shale that are safe from the standpoint of fire prevention rock has been attributed by the United States Bureau of (that is, less than 1.0 percent methane in air). Mines to dilution of the oil shale dusts by diesel

2-43 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Hydrogen sulfide appears to be associated with mine Retorting water in deep oil shale mines. Hydrogen sulfide has been measured to range from 0.5 to 10 ppm near the Potential health hazards associated with aboveground mine-water sump of a deep experimental MIS oil shale oil shale retorting consist of (I) inhalation exposures to mine even with a high rate of ventilation in the area. dusts and retort product gases, (2) skin contact with liquid products of retorting, and (3) exposures to physi- The emanation of radon gas from surrounding rock is a cal agents. Dust in the retort area will include both concern in several types of underground mines. Radon- raw and spent shale dusts (possibly contaminated by daughter measurements have been conducted by the condensed organic materials). Retort product gases Mine Safety and Health Administration (MSUA) in an contain inorganic gases (primarily carbon dioxide, hy- experimental MIS oil shale mine, with results of these drogen, carbon monoxide, hydrogen sulfide, and am- measurements less than 0.1 time safe working level. monia); trace elements such as arsenic and mercury; and organic gases and vapors (including aliphatic and Shale Preparation and Handling aromatic hydrocarbons, PAH, amines, and heterocyclic nitrogen and sulfur compounds). Physical agents of concern consist of noise and heat. Table 3 summarizes results of two air-sampling studies around the aboveground crushing and screening opera- Operations of charging oil shale to the retort and tions at an experimental United States oil shale facil- removal of spent shale generate airborne dust. Table 4 ity. Total dust levels ranged from 0.8 to 47.2 milli- summarizes results of dust sampling at an experimental grams per cubic meter, whereas respirable dust levels United States oil shale retorting facility. Dust concen- ranged to 20.0 milligrams per cubic meter. The parti- trations were high throughout the area of the retorts, cle size data indicate that a substantial fraction of the dust may be considered respirable by ACGIH criteria. with total dust concentrations ranging to 90.8 milligrams per cubic meter and respirable dust concentrations ranging to 15.6 milligrams per cubic meter. These TABLE 3 levels are much higher than the levels expected for a commercial-scale operation. DUST SAMPLING IN EXPERIMENTAL UNDERGROUND ROOM-AND-PILLAR OIL SHALE MINES TABLE 4 Dust (inilllgran/cubic meter) Quartz Total Respirable Content (%) Operation Max. Mean Max. Mean Max. Mean DUST SAMPLING AROUND THE Crushing: RETORTING OPERATION Primary 33.6 18.0 6.5 3.1 -16.5 (Milligrams Per Cubic Meter) Secondary - 4.7 20.0 10.4 - - Tertiary 47.2 28.1 11.0 8.3 - - Screening - - 8.5 8.0 15.2 14.3 Bin Feed Dist. - - 1.5 1.0 19.2 17.7 Area Dust Crusher-Retort -. 0.8 - - - - Total Respirable Area Area of Retort Max. Mean Max. Mean Crusher-End - 45.2 - 5.2 - - Conveyor Top Seal Operators - - 5.9 2.8 22.4 17.7 90.8 41.5 15.6 8.7 (Personal Bottom Seal 54.0 17.3 4.5 1.8 Samples) Retort, Ground Level 12.0 8.0 4.4 2.5 Middle Distributor 28.6 14.6 4.2 1.5 Bottom Distributor - 59.2 - - Bottom Conveyor - 7.4 Quartz content of respirable dust samples collected - nd Outside Landings 2.7 1.3 1.8 0.8 around the crushing and screening operations ranged Thermal Oxidizer - 1.1 from 13.0 to 22.5 percent. The average for the 12 - 0.9 Retort Operator - 1.7 - 0.4 samples analyzed was 15.5 percent. This is consider- (Personal Sample) ably higher than for the samples analyzed from the Pilot Plant Retort - 10.5 - 1.2 experimental room-and-pillar mine. As in the mine, the First Level dust levels and quartz content observed in the crushing (Personal Sample) and screening operations indicate a high potential for Pilot Plant Middle - 11.7 - 1.1 overexposure of workers to quartz-bearing dusts unless Distillate effective dust control measures are employed. (Personal Sample)

Concentrations of dust in commercial oil shale crushing nd = no detectable dust in sample collected and screening operations in the Soviet Union are reported to range from 25 to 60 and 11 to 35 milligrams per cubic meter, respectively. Noise and whole-body vibrations are also reported to constitute problems, with noise levels in crushing and screening ranging from 105 to 112 decibels.

2-44 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLES

GAS AND VAPOR CONCENTRATIONS IN THE RETORT AREA EXPERIMENTAL ABOVEGROUND RETORTING FACILITY

Total Contaminant Concentration (ppm) Location Hydrocarbon CO NO2 NH3 H2S 502 CS2 IICN HCHO LIM03 CO2 Retort: Top Seal 100-400 25 nd nd 20 nd - 8 2 nd 1,000 Bottom Seal 0.7, 0.2 5 nd 0.1 nd nd nil nd nd nd - Ground Level 100 ------Bottom Distributor 9.0, 3.0, 0.2 ------Middle Distributor 3,0, 0.2 ------Top Distributor 4.5, 4.0, 25 nd nd nd nd nd - nd - nd - Offgas Collector 10-50 ------Thermal Oxidizer nd, 0.6, 25pprn 200 10-15 4-6 nd 35 - 60 - - - Recycle Gas Blower 80-170 200-1,000 20-700 nd 40, 30 10-20 nd 5 5-15 10-15 nd 5,000 Blower Area - 15-25 ------Retort Shale Conveyor - 10 ------Retort Shale Piles nd 12 - - nd nd - nil - - - nd = none detectable

Retort Gases TABLE 6 Levels of a few gases and vapors have been measured around one experimental aboveground retorting opera- DUST SAMPLING AROUND THE SPENT SHALE tion. Those results are presented as Table 5. The DISPOSAL OPERATION At AN EXPERIMENTAL ABOVEGROUND OIL SHALE highest concentrations were not measured at the retort PROCESSING FACILITY itself but in the area of a blower that recycled a (Milligrams Per Cubic Meter) portion of the retort product gases back to the retort vessel. Fugitive emissions, particularly in the area of the recycle-gas blower, were high because of leaks in Total Dust Respirable Dust the system. Operation No. Max. Mean No. Max. Mean At Spent Shale 6 18.6 7.3 6 7.2 Pile 3.2 Skin Contact With Liquid Over Spent Shale 3 640 10.0 3 16.7 Conveyor 14.1 Experiences in Scotland and the Soviet Union suggest that skin disease from contact with liquid retort products is a very important potential hazard in retorting of oil shale. However, it should be noted that the most mately 6.5,a microns, which would indicate that about severe problems in Scotland occurred before the 1930s, 25 percent! of the dust would be considered respirable and a relatively simple program of engineering controls, by the ACGIH criteria. personal protection, and better personal hygiene greatly reduced the problem. Recommended Program

Spent Shale Disposal Based generally on analysis of the preceding data, the Los Alamos report concludes that mining and processing Airborne dust is the primary concern in spent shale of oil shale will create a number of potential health disposal. Dust samples have been collected in the area hazards to workers. These include exposure to dusts, of the spent shale disposal operations at one experi- gases, vapors, liquids, and physical agents. Throughout mental United States oil shale retorting facility. Spent most of the operations, exposures to chemical agents shale was conveyed in dry form from the outlet point at will be to complex mixtures of agents rather than to the bottom of the retorts and discharged onto a pile in single materials. The primary health hazard in mining an adjacent canyon. Results of dust samples collected appears to be exposure to oil shale dusts, which contain near the spent shale disposal operations are presented significant levels of alpha quartz. A pneumoconiosis in Table 6. Dust concentrations in the retorting area hazard will exist if oil shale dust exposures are not were relatively high, particularly during periods when adequately controlled. At this time the emanation of the spent shale was blown by winds. Particle size of radon gas is not considered to be a health hazard. the dust in the spent shale disposal area was approxi-

2-45 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Although the materials to be processed and handled in hydrocarbon (PAll) content of diesel fuel engine ex- oil shale mining and processing are unique, most of the haust and alters its nitrated-PAH content. These process operations are not unique. The known potential findings Lead to the prediction that the lower aromatic health hazards associated with oil shale mining and hydrocarbon content of the shale oil-derived diesel fuel processing may also be found in existing industries. It may lead to a lower PAH content in the diesel engine is believed that these potential health hazards are exhaust, relative to that from combusting petroleum- amenable to the same types of controls that have been derived diesel fuel. successfully applied to such hazards in other industries. Benzo(a)pyrene (BaP), a classic dermal tumorigen, is often used as an "indicator" of PAll and potential tumorigenicity. Several diesel fuels are compared in Table 1 for their SaP content, It is evident that the TOXICITY OF SHALE-DERIVED DIESEL FUEL concentrations of flaP in the two shale oil-derived JUDGED SIMILAR TO PETROLEUM diesel fuels fall within the range of values determined for the petroleum-derived diesel fuel. There is consid- The Department of Defense is concerned with deter- erable variability in the flaP content of the petroleum mining if a changeover from petroleum to shale oil diesel fuel, but all concentrations are lower than lp g derived mobility fuels would be accompanied by a per gram. These results suggest that the deImal significantly different toxicological hazard. To address tumorigen PAll content and tumorigenicity of the die- this issue they have been conducting a toxicological sel fuel derived from petroleum and shale will be very comparison of diesel fuels derived from shale oil and low and similar. However, the differences in the major petroleum. Dermal and inhalation toxicology are cur- organic composition of the diesel fuel may impose rent primary concerns. subtle differences on the expression of tumorigenicity by the PAIL Tumorigenicity of a petroleum diesel Oak Ridge National Laboratory carried out comparative fuel-2 has been found to be very low, but small chemical analyses of a set of 11 diesel fuels derived differences have been observed between the skin from petroleum, shale oil, and tar sands-petroleum tumorigenicities of shale oil- and petroleum-derived jet coprocessing to estimate relative hazards. fuels. The major conclusion from the gas chromatographic studies of diesel fuel derived from different fossil TABLE 1 energy sources is that generic compositional differences exist among diesel fuel refined from petroleum crude oils, shale oils, and tar sands. Although differ- COMPARISON OF BENZO(A)PYRENE CONTENT ences are observed among the samples within a given OF DIESEL FUELS DERIVED FROM group, these differences are small compared to those PETROLEUM AND SHALE OIL found between groups. The petroleum- and shale oil- derived diesel fuel differ mainly in their makeup of the lesser components which elute in the central region of Sample the gas chromagraph profile between dodecane and non- Number Description Concentration adecane. The relative simplicity of the gas chrome- $.ag/g) graph profiles of the shale oil-derived diesel fuel is a result of much lower concentrations of the alkylated Shale Oil Derived diaromatic hydrocarbons relative to those in the petroleum-derived diesel fuel. Although the petroleum-and 4610 Paraho/Sohio DFM 0.03+/-0.005 shale oil-derived diesel fuel exhibit very similar con- 4810 Geokinetics/Suntech DF-2 0.09+/-0.013 centrations of the straight-chain alkanes and alkyl benzenes, the concentrations of the higher (C3) alky- Petroleum-Derived lated benzenes, the mono- and dimethyl naphthalenes, and the phenanthrenes are much higher in the petro- Phillips Reference DF-2: leum diesel fuel. 9101 Lot C-345 0.08+/-0.04 1910 Lot C-747 0.05 In contrast, a diesel fuel-derived from the co-process- 1914 DOD Reference DF-2 0.19+/-0.01 ing of tar sands and petroleum is distinctly different DF-2-1 Ft. Carson DlO DF-2 0.84+/-0.10 from either the petroleum- or shale oil-derived diesel Petroleum Diesel Fuel 0.07 fuel. It is characterized by a relatively high ratio of Petroleum Diesel Fuel 40.001-0.42 aromatics to aliphatics, and a low ratio of pristane and phytane to heptadecane and octadecane, respectively. The n-alkanes concentrations in the mid-range (decane through non-adecane) are about one-half to one-third those in the other two groups of fuels. The relative ratio of aromatics to aliphatics in the diesel fuel Differences in the bulk composition of the diesel fuel increases in the order shale oil-diesel fuel C petroleum- lead to differences in the volatile organic compounds diesel fuel C tar sands/petroleum-diesel fuel. which can be inhaled from the vapors of the fuels as they evaporate. All of the fuel vapors contain aliphatic Studies have shown that increasing the aromatic con- hydrocarbons ranging from C4 through at least CIO and tent of a diesel fuel increases the polycyclic aromatic alkylated monoaromatics. They represent the most

2-46 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 volatile portion of the diesel fuel. As with the bulk Quantitatively, the concentrations of the major compo- fuels, some compositional differences were noted nents in the vapors (Table 2) are quite similar for most among the vapors of the fuels. The vapors of the components of the shale and petroleum-derived diesel petroleum-derived diesel fuels-2 are somewhat more fuel. However, the iso-pentane is notably lower in the complex than those of the shale-derived diesel fuel, vapors of the shale oil diesel fuel. The toluene content particularly in the C4 and C5 region. This most likely of Geokinetics-Suntech Diesel Fuel-2 vapors also stands corresponds to a greater content of branched and out as unusual. Oak Ridge concludes that differences in partially unsaturated hydrocarbons in the petroleum inhalation toxicity are likely to be small among the diesel fuel-2. fuels, with the possible exception of the Geokinetics- Suntech Diesel Fuel-2.

TABLE 2

COMPARISON OF INHALABLE ORGANIC COMPOUNDS IN READSPACE VAPORS OF DIESEL FUELS REFINED FROM PETROLEUM AND SHALE OIL Concentration in Heatpaee Vapors* Per Liter)

Petroleum Shale Oil No. 1910 No. 1914 DF-2-1 No. 4616 No. 4801 No. 4610 Phillips DOD Ft.Carson WPAFB Geokinetics- Paraho- Reference Referee DID Suntech Sohio Compound DF-2 DF-2 DF-2 DFM DF-2 DFM

Iso-Pentane 260 520 440 920 nd 150 Normal-Pentane 61 190 260 450 nd 76 2,2-Dimethyl Butane nd 8 5 13 nd 6 3-Methyl Pentane 53 79 89 110 nd 41 Normal-Hexane 53 99 190 160 nd 95 Benzene 16 62 33 50 17 29 3-Methyl Hexane 34 59 85 66 11 92 Normal-Heptane 42 87 170 80 22 148 Toluene 35 140 110 45 970 30 Normal-Octane 35 69 140 53 70 74 m+p-Xylenes 31 61 80 30 26 6 Normal-Nonane 74 45 140 45 93 38 1,3,5-Trimethyl Benzene 23 nd 33 nd 22 8 Normal-Decane 53 12 120 25 57 19

nd = not detected

2-47 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 WATER

WATER APPLICATION RELATED TO OIL SHALE LISTED

The following recent water right application relevant to western oil shale projects was filed in the Office of the Water Clerk, District Court, Water Division No. 5, in Glenwood Springs, Colorado.

86 CW 188 (W220, W221, and W2541) Rio Blanco Oil Shale Company, Inc., a Division of Amoco Corporation, do William C. Waldeck, Post Office Box 2188, Grand Junction, Colorado 81502. Application for quadrennial Finding of Reasonable Diligence for following water rights: Duck Creek Reservoir for 345,000 acre-feet from Yellow Creek, groundwater and the White River; Yellow Creek Reservoir for 428,000 acre-feet from Yellow Creek, groundwater and the White River; and Yellow Creek Dam Diversion and Pumping Works for 300 cubic feet of water per second from the White River; all above structures in Rio Blanco County and all decreed for mining, industrial, refining, retorting, power, domestic irrigation, fish and wildlife propagation, recreation and augmentation uses. The 14 page application contains details of work performed during quadrennial period.

2-48 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RESOURCES

INTERIOR AGREES TO SETTLE OIL SHALE • By restricting the claimants' non-oil shale acti- CLAIMS--STRONG REACTION RESULTS vities on the surface area for 20 years, the settlment maintains the integrity of the initial In a decision which surprised many, the United States claim that was for oil shale and which has the Department of the Interior reached a negotiated settle- effect of encouraging oil shale development. ment in an oil shale land case involving Tosco, Exxon, • By removing the contested lands from federal Unocal, and other claimants for 82,000 acres of land in ownership the settlement reduces the amount Colorado. United States District Court Judge Sherman of payment-in-lieu-of-taxes due from the Finesilver had made a strongly worded ruling in favor of United States. The state would then be free to the claimants in 1985 (see Pace Synthetic Fuels Report, tax the privately held lands, which should result June 1985, page 2-38). Judge Finesilver urged the in greater revenues. government to reach a negotiated settlement rather than continue with another appeal in the long-standing • The settlement preserves state water rights. case. Although the Interior Department announced that The Bureau of Land Management will relinquish it intended to appeal anyway, in the meantime it its claims now pending with the state for water continued to negotiate with the companies, out of the rights and the claimants will have to file under public view. state law for any future needs, as they would with any surface title transfer. The settlement, when announced, provoked a storm of • By discontinuing appeals on the patents, sub- public protest, presumably from those unfamiliar with stantial legal fees will be saved. Had the the case, over the "giveaway" of public lands. Public appeals continued, the Departments of Justice hearings were immediately called for in Congress. On and the Interior would be continuing to commit August 12, J.S. Griles, Assistant Secretary for Land and both manpower and dollars to a seemingly end- Minerals Management, Department of the Interior, less process. testified before the Committee on Interior and Insular Affairs of the United States House of Representatives. • And finally, the settlement limits the impact of Exerpts of his testimony follow. a very unfavorable district court decision from being applied to other locatable minerals under the 1872 Mining Act as well as other pending oil Griles testified that the agreement in the Tosco Oil shale claims. Shale case which resolves a 66 year dispute over numerous oil shale claims in the State of Colorado provides a As part of the agreement, the claimants will receive a number of advantages to the government and to the patent on their claim which grants them the fee title to public at large. Interior points out advantages from the the surface area, and the rights to the oil shale and the settlement including: sand and gravel. Simultaneously the claimants will issue a special warranty deed to the United States • First, the settlement resolves a long-standing conveying title to the oil, gas, and coal. Both sides will legal battle with a minimum loss to the federal request that Judge Finesilver's decision be vacated, so government when compared with the ultimate that it does not set a precedent for other cases. risk of losing the case in its entirety, in light of numerous adverse court decisions. Interior offered the following historical review of this issue to assist in understanding the basis of the settle- • The settlement gives to the United States the ment: existing and future oil, gas and coal rights on 82,000 acres with the right to lease those min- • The settlement covers certain oil shale mining erals and collect and disburse royalty revenue, claims, presently under patent application, lo- not only for the federal government but also for cated prior to 1920 under the 1872 Mining Law the State of Colorado. in the State of Colorado. The 1872 Mining Law • As a result of this part of the agreement, the provides that a claimant is entitled to a patent State of Colorado's 50 percent share of all oil, of the claim if the claimant has located and gas, and coal mineral leasing royalties is pro- maintained the claim, and proved a discovery. tected. A claimant who meets these requirements is entitled to apply for and receive a fee patent of • A potential trespass action by the claimant for the claim on the payment of $2.50 per acre. oil and gas revenues, were they to receive full title, is avoided. • In the 1930s, the Supreme Court twice reversed efforts by the Department of the Interior to • The settlement extends the public use of the invalidate unpatented claims on at least surface area of 82,000 acres in Colorado and 710,000 acres in Colorado, Utah, and Wyoming. includes a commitment that future grazing, hunting, and use of existing rights-of-way will • Between 1935 and 1960, claims covering over be allowed. 350,000 acres were patented to private parties. In none of these cases was there any reserva- • The settlement, by continuing existing uses and tion of rights to the United States or notice to existing federal oil and gas leases, minimizes • Congress that the patents were being issued. the risk of litigation by those users.

2-49 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 the Kansas Energy Office in 1981 focused on the • In 1960, the Department reversed its policy of feasibility of using coal as an "economic aid" to making 25 years and revived its efforts to invalidate Kansas oil shales economically recoverable. That study the remaining unpatented claims on also showed that the amount of oil shale available for 360,000 acres. extraction is approximately 33 x 10 tons with reserves • In 1970, the Supreme Court held that the De- of shale oil estimated at 33 x 108 barrels at 75 percent partment of the Interior could seek to invali- recovery. date claims where there was a failure to "substantially comply" with annual assessment work Thirty-seven shale units sampled at 68 locations form requirements. the basis of the study. Most of the shales have a thickness of at least 1 meter and a predominantly dark • In 1980, the Supreme Court ruled that the color. The majority of the shales sampled crop out in Department of the Interior could not invalidate Kansas. Exceptions are the Chattanooga Shale, Maquo- claims on the grounds that oil shale had no keta Shale, and black shales of the Kearny Formation. present commercial value. These latter-named shales occur only in the subsurface • Judge Finesilver, in Tosco versus Hodel, deci- in Kansas. sively ruled against the Department on both the discovery and assessment work issues. This Samples yielding three gallons shale oil per ton of shale represented the culmination of litigation that or more are listed in Table 1. commenced in 1966.

• Since 1920, the Department has lost on the TABLE 1 discovery issue twice in the district courts and once each in the court of appeals and in the Supreme Court, without ever winning a case. OIL SHALE ASSAY BY • Since 1920, the Department has lost on the MODIFIED FISCHER RETORT METHOD assessment work issue 5 out of 6 times in the district court, 3 out of 3 cases in the court of appeals, with one procedural remand, and 2 out Sample Gallons Per Ton Specific of 3 cases in the Supreme Court. Number Oil Water Gravity

A Boulder, Colorado company may be the biggest 5 4.6 3.4 0.920 winner in the settlement. Energy Resources Techno- 7 5.0 3.4 0.920 logy Land Inc. (ERTL), owned largely by the Ertl family 8 3.1 3.4 0.920 of Boulder, has an interest in about 35,000 acres of the 31 9.9 4.6 0.924 total 84,000 acres transferred August 4 to companies 40 8.1 7.2 0.918 and individuals under the settlement. 45 13.0 5.8 0.913 47 12.6 5.5 0.922 ERTL's claim to the acreage, acquired in the 1950s by 48 7.5 6.2 0.923 the late Tell Ertl from the claim's original locator, is St 15.8 7.2 0.927 the largst single claim among the litigants. 52 15.7 6.0 0.929 53 23.3 5.6 0.922 54 3.9 7.7 0.920 55 6.3 7.2 0.898 56 17.4 5.1 0.918 KANSAS OIL SHALE POTENTIAL EVALUATED 59 5.2 7.4 0.920 In a study completed in 1983 but only recently placed in 61 5.0 6.7 0.920 NTIS accessions, the Kansas Geological Survey investi- 63 18.3 12.9 0.918 gated potential oil recovery from Kansas oil shales. 64 7.9 8.6 0.912 66 12.8 8.4 0.914 Dark organic-rich shales are present in many parts of 67 3.1 3.8 0.920 the stratigraphic column of Kansas. Some of these 69 3.2 6.7 0.920 shales yield appreciable amounts of oil when tested. 72 14.0 4.1 0.903 These shales are mainly of marine origin. 76 18.6 10.8 0.943 77 5.6 15.6 0.937 Kansas oil shales considered to be of potential econo- 79 4.8 16.8 0.920 mic interest are primarily of Middle and Upper Pennsyl- vanian age and are present in the southeastern part of 81 10.8 12.0 0.945 the state. A total of 147 samples from 37 shale units 83 16.4 11.4 0.970 around the state were tested for potential oil recovery. 85 15.0 14.4 0.942 Fischer assay results indicate yields ranging from trace 87 10.5 14.4 0.960 amounts to 23.3 gallons of oil per ton of shale. 88 8.5 16.8 0.954 89 10.0 12.0 0.953 Few studies have previously evaluated Kansas shales for 90 8.0 14.4 0.945 potential oil recovery. An investigation sponsored by 92 9.1 14.4 0.941

2-50 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Seven of the shales tested displayed some economic FIGURE I potential and may be sources for future exploitation. Three factors were used to determine potential. They SAMPLE LOCATIONS are: (1) oil yields greater than 10 gallons per ton of IN EASTERN KANSAS shale, (2) considerable lateral extent and, (3) minimum vertical thickness of I meter. Statigraphic proximity V to coal beds was also considered where applicable. The shales satisfying these requirements are the Heebner, Neør.ska Eudora, Tacket Formation, Anna, Little Osage, Excello, Kinsas and "V" shales. These are all middle Pennsylvanian and upper Pennsylvanian shales outcropping in the southeastern corner of the state (Figure 1). The total thickness of the Heebner Shale is 2.0 meters at the sites sampled. The oil-bearing unit is a black clay shale ranging in thickness from 0.9 to 1.2 meters. It yields from 8.9 to 10.5 gallons of oil per ton of shale. The Eudora Shale, where sampled, is approximately 2.0 meters thick. The oil-bearing black clay shale portion is 0.3 to 1.5 meters thick. The black clay shale produces from 7.5 to 16.4 gallons of oil per ton of shale. The Tacket Formation is composed of two shales separated by a thin limestone. The formation thickness is variable throughout southeastern Kansas. The examined upper shale unit ranged in thickness from 3.3 to 4.4 meters and produced from trace amounts to Otlibomi 14.0 gallons of oil per ton of shale.

The Anna Shale ranges in thickness from 0.6 to / 1.5 meters. It consists of a thin basal-bedded clay/mud yielding trace amounts of oil, a black claystone that 50 10000 yields 7.9 to 18.3 gallons of oil per ton of shale, and a 0 so IM km thin upper clay shale that yields 0.6 gallons per ton.

The Little Osage Shale ranges from 1.2 to 3.7 meters in lend support to the economic window concept are the thickness. The upper 1.2 to 1.5 meters of this member Little Osage, Excello, and "V' shales. The Little Osage is composed of a black claystone-clay shale. Samples Shale (2.5 meters thick) and Excello shale together with from this section had the largest oil yield of all the the Higginsville (5.0 meters), and the Blackjack Creek samples tested, ranging from trace amounts to 23.3 gal- (3.0 meters) limestones comprise the overburden of the lons of oil per ton of shale. Mulky coal (0.3 meter). Although these shales will theoretically produce economically recoverable The Excello Shale, the upper unit in the Cherokee amounts of oil, the associated limestones complicate Group, is between 0.8 and 1.4 meters thick. It produces extraction. Two problems that reduce the attractive- from trace amounts to 12.6 gallons of oil per ton of ness of exploiting the black shale overburden are the shale. great thickness of the overlying limestones and the repetition of thin limestone stringers within some of The 'V" Shale is 3.8 to 4.5 meters thick and is composed the shales. of three shale units separated by two limestone units. The two uppermost shale units yielded from trace The uranium and phosphate present in these shales also amounts to 1.1 gallons of oil per ton of shale and the may be valuable products when extracted in combina- lowermost shale unit produced 2.1 and 13.0 gallons per tion with the oil. Phosphorite nodules and dispersed ton. phosphate are present in all economically attractive Kansas oil shales. In general, these phosphorite nodules contain 0.01 to 0.03 percent uranium, whereas the raw Co-Extraction With Coal shales contain an average of only 0.005 percent. This suggests that the phosphorite nodules are the major Considerable amounts of coal are strip-mined in south- uranium-bearing components in most of these shales, in eastern Kansas. Extraction costs are high since thick line with expected geochemical theory. black shale-limestone overburden must first be removed The optimum economic window for efficient usage of to recover the coal. The economic window concept these oil shales would involve the early removal of refers to the cost reduction of both black shale and coal phosphate and uranium, followed by retorting of the extraction by using formerly unusable oil-shale overbur- shales for oil. The spent shale could then be used for den. Unfortunately, most of the black shales that light weight road metal or discarded. The initial oil overlie (or underlie) mineable coals do not yield signifi- shale extraction costs would be offset in some cases by cant amounts of oil upon retorting. Those shales that the presence of strippable coals or usable limestones.

2-51 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RECENT OIL SHALE PUBLICATIONS/PATENTS

The following papers were presented at the Third Australian Workshop on Oil Shale held in Lucas Heights, Australia on May 15, 1986: W. J. Curnow, "The Prospects for Shale Oil in Australia" T. A. Noon, "Oil Shale Exploration Activity in Queensland During 1985/1986" D. B. Tolmie, "Status of the Julia Creek Shale Oil Project" K. C. Neale, "Technical Status of the Rundle Oil Shale Project" A. J. Moore, "Implications from SeveralSeveral Oil Shale Project Studies" L. Coshell, "Mineralogy of the Rundle Oil Shale Deposit" D. A. Henstridge, "The Geology and Organic Petrography of the Nagoorin Oil Shale Deposit" D. A. Dixon, "Oil Shale of the Duaringa Basin, Central Queensland" D. Madre, "The Alpha Oil Shale Deposit" S. W. Wilcock, "Bulk Sample Coring and Geology, Kerosene Creek Member, Rundle Oil Shale Deposit" A. C. Hutton, "Beneficiation of Oil Shales - Factor Fiction?" J. H. Patterson, "Characterization of Trace Elements in Rundle and Condor Oil Shales" R. A. Quezada, "Mossbauer Spectroscopy Studies on Retorting of Australian Oil Shales" K. W. Riley, "Determination of Forms of Nitrogen in Oil Shales" B. Evans, "The Yield of Australian Oil Shales as Determined in Nuclear Magnetic Resonance and Infra-Red Spectroscopy" A. Ekstrurn, "The Pyrolysis Kinetics of Rundle Oil Shale" T. J. Parkets, "Simple Kinetic Model for Pyrolysis of Rundle Shale" G. C. Wall, "Kinetics of Production of Individual Products from the Isothermal Pyrolysis of Seven Australian Oil Shales" A. C. Hutton, "Partial Pyrolysis of Condor, Rundle and Stuart Oil Shales" A. J. Gannon, "Pyrolysis Stoichiometry for Three Kerogen Types" R. M. Baldwin, "Pyrolysis and Hydropyrolysis of Four Australian Oil Shales in Supercritical Toluene Under Rapid Heating Conditions" J. H. Levy, "Vapor Phase Cracking and Coking of Three Australian Shale Oils: Kinetics in the Presence and Absence of Shale Ash" J. H. Patterson, "Partitioning of Trace Elements - Retorting of Julia Creek Oil Shale" J. D. Saxby, "An Experimental Study of Oil Shale Weathering and Its Effect on Oil Yields" A. L. Chaffee, "Structure of Kerogen in Julia Creek Oil Shale Revealed by a Simple Oxidation Technique" H. J. Hurst, "A High Pressure High Temperature Electron Spin Resonance Study of Oil Shale Retorting" I. C. Hoare, "Pyrolytic Decomposition of Kerogens: Kinetic Analysis of Thermoanalytical Data" N. V. Dung, "Continuous Fluidized Bed Retorting of Condor and Stuart Oil Shales in a 150 Millimeter Diameter Reactor" T. Uchida, "Oil Shale Development Activities in Japan - Construction of Oil Shale Pilot Plant" J.P.K. Peeler, "Hydropyrolysis of Yaamba Lignitic Shales" N. V. Dung, "A New Concept for Retorting Oil Shales" N. V. Dung, "An Assessment of Lift-Pipe Combustion in the Processing of Australian Oil Shales" Y-O Chong, "A New Oil Shale Retort: Fluid Beds Exchanging Solid but not Gases" B. G. Charlton, "Comparative Kinetics of Fluidized Bed Combustion of Australian Oil Shale Chars" B. G. Charlton, "A Model for the Combustion Kinetics of Spent Nagoorin Carbonaceous Oil Shale" C. B. Mapstone, "A Short History of Shale Oil Production at Glen Davis, NSW"

2-52 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 A. R. Atkins, "Upgrading Strategies for Julia Creek Shale Oil' D. E. Lambert, 'Chemical Changes Upon Storage and Ageing of Rundle Shale Oil" T. G. Harvey, "Extraction and Identification of Nitrile Compounds in Rundle Shale Oil" G. E. Mapstone, "Some Problems in Refining Shale Oil at Glen Davis" IL U. Tait, "Rundle Oil Shale Project: The Environment" L. J. Cutler, "Waste Dump Studies at the Rundle Site" R. D. Tait, "Chemical Composition of Selected Plant Species Grown on Wastes from the Rundle Oil Shale Project" J. K. Marshall, "The Significance of Water Storage in Establishing Vegetation at Rundle" M. Glikson, "Why Environmental Effects from Mining and Retorting of Rundle Oil Shale May be Minimal" P. J. Redann, "Condor Oil Shale Project: The Environment" K. J. Mann, "Toxicity of Oil Shale Waste Waters to Marine Algae" M. W. Corney, "An Adsorption Isotherm Study of the Use of Raw and Spent Rundle Oil Shales for the Treatment of Retort Waters" G. E. Batley, "The Use of Coal Fly Ash for the Treatment of Oil Shale Process Waters" Brandt, M. T., "Health Hazard Evaluation and Recommended Industrial Hygiene Practices for Aboveground Oil Shale Processing," Los Alamos National Laboratory, January 1986.

Los Alamos National Laboratory, "Summary Report of the Oil Shale Fragmentation Project at the Anvil Points Mine, Colorado."

Macaulay, George, "Geochemistry and Geological Factors Governing Exploitation of Selected Canadian Oil Shale Deposits," 1985.

Macaulay, George, "Recovery and Economics of Oil Shale Development, Canada," June 1986.

McGowan, C. W., "Dentification of Organic Compounds in the Bitumen of Chattanooga Oil Shale," September 1986.

McLendon, T. R., "Pressure Drops During Low Void Volume Combustion Retorting of Oil Shale," In Situ, Volume 10, Number 1, 1986.

Miller, R. L., "Liquefaction Co-Processing of Coal and Shale Oil at Low Severity Conditions," American Chemical Society Meeting, September 7, 1986.

Tyner, C. E., "Oil Yield Losses in Non-Uniform In Situ Oil Shale Retorts," In Situ, Volume 10, Number 1, 1986.

The following papers were presented at the Nineteenth Oil Shale Symposium, held on April 21, 1986 in Golden, Colorado: G. Macaulay, "Effects of Maturation on Hydrocarbon Recoveries from Canadian Oil Shale Deposits" J. R. Dyni, "Normative Mineraology Oil Shale in the Juhan Core Hole 4-1, Picenance Creek Basin, Colorado" A. C. Hutton, "Classification of Oil Shales - A Petrographic Approach" S. J. Schatzel, "Case Study of Methane Occurrences at the Cathedral Bluffs Shale Oil Mine, Colorado" E. S. Weiss, "Dust and Pressure Generated During Commercial Oil Shale Mine BLasting: Part II" M. J. Sapko, "Methane Released During Blasting at the White River Shale Project" R. G. Vawter, "The Future for Synthetic Fuels" Sigvard Hellestam, "Results of Flash Fluid Slag Gasification Tests on Swedish Alum Shale in the Slagging Gasification Reactor (SGR-3)" P. V. Punwani, "Status of Current Research for Hydroretorting of Eastern Oil Shales" P. L. Russell, "World History and Resources of Oil Shale" E. M. Piper, "The Petrosix Project in Brazil - An Update" R. J. Cana, "Results and Interpretation of Rapid-Pyrolysis Experiments Using the LLNL Solid-Recycle Oil Shale Retort" T. C. Bickel, "Uniform Retorting of an Anisotropic Shale Bed"

2-53 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 M. R. Khan, "Influence of Wen thering/Preoxidationon the Devolatilization Mechanisms of Oil Shale" M. Shirav, "Pathway of Some Trace Elements During Fluidized-Bed Combustion of Israeli Oil Shale" J. E. Virgona, "Decommissioning of the United States Department of Energy Anvil Points Oil Shale Research Facility" K. D. Vanzanten, "Control of Sulfur Emissions from Oil Shale Retorting Using Spent Shale Absorption Pilot Plant Testing" V. R. Hasfurther, "Oil Shale Process Water Evaporation" E. R. Blatchley, "Sunlight Photochemistry of Retort-Water Organonitrogen Compounds in an Inert Atmo- sphere" R. H. Sakaji, "Ammonia Removal from Oil Shale Process Waters Using Tubular, Microporous Poly tetra fluoro- ethene Membranes" T. D. Steele, "A Comparison of Individual Project-Related Water-Quality Impacts of Processed-Shale Disposal, Northwestern Colorado" S. S. Sorini, "EPA, ASTM, and Column Leaching of Processed Oil Shale - A Comparative Study" Hal Taback, "The Effect of Oil Shale Recovery Processes on Air Emissions"

United States Department of the Interior, "Wolf Ridge Corporation Mine Plan for a Nahcolite Solution Mine," Draft Environmental Impact Statement, July 1986.

OIL SHALE - PATENTS

"Process for Recovering Shale Oil from Raw Oil Shale," Carl S. Minden - Inventor, United States Patent 4,587,006, May 6, 1986. A continuous process for recovering shale oil from raw oil shale using a new integrated hydropyrolysis/thermal pyrolysis technique which produces high yields of improved quality liquid hydrocarbon products and has unusually low heat and energy requirements, which process comprises crushing and grinding raw oil shale, mixing the ore particles with hot recycle heavy oil to form a slurry, treating the slurry with hydrogen under elevated temperature and pressure for a short period, stripping out the desired liquid hydrocarbon products, passing the remaining slurry mixture to a thermal retort where under fluidized bed conditions it is subjected to increased temperatures by adding spent shale that has been burned in an air lift combustor at two different temperature level treatment zones, the upper zone being selected such that the temperature is sufficient to vaporize the remaining slurry oil, and the lower zone being selected such that the temperature is sufficient to retort spent shale and to thermally crack excess heavy gas oil charged to the lower zone, taking product as high temperature vapor to a quench tower where the liquid product is recycled to the hydropyrolysis reactor and the heavy gas oil is recycled to the slurry mixer. "Process for Beneficating Rundle Oil Shale," Glen Brans and Michael Siskin - Inventors, Exxon Research and Engineering Company, United States Patent 4,587,004, May 6, 1986. Disclosed is a process for beneficiating oil shale wherein the oil shale is treated in a first stage with an aqueous ammonium salt solution and in a second stage and optionally a third stage in the presence of a solution containing ammonium ions/ammonia, or both. The pH of the first stage is from about 5 to 9, and the pH of the second and third stages are from about 0.5 to 5 or about 9 to 12 with the proviso that the pH of the second and third stage is not in the same range. "Process for Beneficating Rundle Oil Shale," Glen Brans and Michael Siskin - Inventors, Exxon Research and Engineering Company, United States Patent 4,587,005, May 6, 1986. Disclosed is a process for removing mineral matter from Rundle oil shale by contacting the oil shale with (a) an ammonium salt solution and (b) an organic solvent, at a temperature from about 00 to about 300 C, for a time which is sufficient to substantially separate at least about 80 weight percent of the carbonate mineral matter from the oil shale. "Solid Liquid Extraction Apparatus," F. Morgan Warzel - Inventor, Phillips Petroleum Company, United States Patent 4,588,476, May 13, 1986. A process for replacing a solution obtained for instance by exposing oil shale particles to the action of a solvent under supercritical conditions. The solid/solution mixture is extracted in a multitude of cross flow extractions such as to gradually replace the solution, e.g., a bitumen solution, by the solvent, e.g., toluene. An apparatus. for carrying out this process is also disclosed. "Apparatus for Solar Retorting of Oil Shale," F. Morgan Warzel - Inventor, Phillips Petroleum Company, United States Patent 4,588,478, May 13, 1986. An apparatus for a process for solar retorting of oil shale which comprises pyrolyzing fluidized ground oil shale particles by solar radiation in a retort, wherein said ground oil shale particles are provided in a state of continuous fluidization entrained in a gas and exposed to solar radiation focused through a transparent window, and retorted shale oil fines, gases, and shale oil are removed from the retort to separation and recovery.

2-54 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 "Process for Recovering Oil from Raw Oil Shale Using Added Pulverized Coal," Carl S. Minden - Inventor, United States Patent 4,589,973, May 20, 1986. A continuous process for recovering oil from raw oil shale using a new integrated hydropyrolysis/thermal pyrolysis technique and involving the addition of pulverized coal which produces oil which is more characteristic of typical crude oil, as well as providing supplemental gas and coal char fuel, and has unusually low heat and energy requirements, which process comprises passing hot and crushed raw shale to a slurry mixer where it is mixed with hot recycle heavy oil, treating the resulting slurry with hydrogen under elevated temperature and pressure for a short period, discharging the resulting mixture to a product stripper wherein the product hydrocarbons and a portion of the recycle slurry oil is vaporized and passed to a separation column where the desired fractions are removed and heavy gas oil recovered for recycle, mixing a portion of the heavy gas oil recycle with pulverized coal particles to form a pumpable coal slurry, discharging spent shale and remaining slurry oil from the product stripper to a thermal retort operated under fluidized bed conditions wherein a temperature gradient is maintained by introducing spent shale and coal char that has been burned in an air lift combustor into at least two different treatment zones, the upper zone being selected such that the temperature is sufficient to vaporize the remaining slurry oil, and the lower zone being selected such that the temperature is sufficient to retort spent shale and to thermally crack excess heavy gas oil charged to the lower zone, taking product as high temperature vapor to a quench tower where the liquid product is recycled to the hydropyrolysis reactor and the heavy gas oil is recycled to the slurry mixer. "Method of Making Carbon Black Having Low Ash Content from Carbonaceous Materials," Wenjai R. Chen and Robert L. Savage - Inventors, United States Patent 4,590,056, May 20, 1986. A partial combustion method of producing commercially acceptable carbon black containing less than approximately 1 percent ash from carbonaceous material taken from the group consisting of coal, lignites, tar sand, pitch, oil shale, and asphaltic substances, which comprises reacting the carbonaceous material with oxygen at a temperature of from 2,000°F to 3,000°F, the carbonaceous material having an average particle size of from 75 microns to 1,700 microns and wherein the oxygen to carbonaceous material weight ratio is no more than 0.4, and recovering the carbon black from the reaction. "Use of Ethers in Thermal Cracking," Partha S. Ganguli - Inventor, BRI Inc., United States Patent 4,592,826, June 3, 1986. A process for improving the upgrading/conversion of hydrocarbonaceous materials such as coals, petroleum residual oils, shale oils, and tar sand bitumens. In the process, the free radicals formed from thermal cracking of the hdyrocarbons are reacted with the free radicals formed by the thermal cracking of a free radical forming chemical reactant, such as diunethyl ether, to yield stable low molecular weight hydrocarbon distillate products. The hydrocarbonaceous feed material is preheated to a temperature of 600° to 700°F, and the hydrocarbon and the free radicals forming chemical, such as dimethyl ether, are passed through a flow reactor at temperature of 7500 to 900°F, pressure of 200 to 1,000 psi, and liquid hourly space velocity of 0.3 to 5.0 LHSV. Free radicals formed from the hydrocarbon feed material and from the ether material react together in the reactor to produce tow molecular weight hydrocarbon liquid materials. The weight ratio of ether material to hydrocarbon feed material is between about 0.3 and about 2.0. "Conversion of High Boiling Organic Materials to Low Boiling Materials," Curtis D. Coker and Stephen C. Paspek, Jr. - Inventors, United States Patent 4,594,141, June 10, 1986. A process for the conversion of high boiling saturated organic materials is described. The method comprises contacting said high boiling organic materials at a temperature of at least about 300°C and at a reaction pressure of at least about 2,000 psi with an aqueous acidic medium containing at least one olefin, and a halogen-containing compound selected from the group consisting of a halogen, a hydrogen halide, a compound which can form a halide or a hydrogen halide in the acqueous acidic medium under the process conditions, or mixtures thereof whereby the high boiling organic material and aqueous acidic medium form a substantially single phase system. Optionally the process can be conducted in a reducing atmosphere. The process of the invention is useful for producing and recovering fuel range liquids from petroleum, coal, oil shale, shale oil, tar sand solids, bitumen, and heavy hydrocarbon oils such as crude oil distillation residues which contain little or no carbon-carbon unsaturation. Preferably, the halogen compound is at least one halogen or a hydrogen halide. "Method for Fully Retorting an In Situ Oil Shale Retort," Carl L. Jacobson, Jian-Chyun Shen, and Raymond L. Zahradnik - Inventors, Occidental Oil Shale Inc., United States Patent 4,595,056, June 17, 1986. A method is provided for operating an in situ oil shale retort in a subterranean formation containing oil shale. The retort contains a fragmented permeable mass of formation particles containing oil shale, within top, bottom and side boundaries of unfragmented formation. A drift is in communication with a lower region of the fragmented mass for withdrawal of liquid products of retorting and an off-gas comprising gaseous products of retorting. A gas-sealing bulkhead is placed across the product withdrawal drift and a water spray is installed in the drift through the bulkhead. An upper region of the fragmented mass is ignited for establishing a combustion zone therein. A retort inlet mixture comprising an oxygen- supplying gas is introduced into the top of the fragmented mass for advancing the combustion zone downwardly through it to thereby establish a retorting zone on the advancing side of the combustion zone for producing the liquid and gaseous products. A retort off-gas comprising such gaseous products is withdrawn from the retort through the product withdrawal drift. The temperature of the off-gas is monitored in the vicinity of the gas-sealing bulkhead. When the off- gas temperature reaches a selected value below the design temperature of the bulkhead, sufficient water is sprayed into the off-gas stream in the drift to maintain the temperature of the off-gas in the vicinity of the bulkhead below its design temperature.

2-55 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 "Static Mixer Retorting of Oil Shale," John M. Forgac, Jay C. Knepper, and Earl D. York - Inventors, United States Patent 4,597,852, July 1, 1986. A process for mixing and retorting raw oil shale, comprising the steps of: feeding raw oil shale to an upper free-tall section of a generally upright static mixer having a vertical axis, the raw oil shale being fed to the top of the upper free-fall section at an angle of inclination ranging from about 5 0 to about 450 relative to the vertical axis; feeding spent oil shale to the upper free-fall section of the static mixer at a sufficient retorting temperature to retort the raw oil shale. The spent oil shale being fed to the top of the upper free-fall section at an angle of inclination ranging from about 50 to about 450 relative to the vertical axis and at an acute angle of inclination relative to the raw shale feed; interstecting and colliding the raw and spent shale in the upper free-fall section and moving the shale generally downwardly through the free-fall section in a free-fall flow pattern by gravity flow; substantially completely mixing and randomly distributing the raw and spent oil shale together by flowing and deflecting the raw and spent shale generally downwardly in a generally zigzag flow pattern over and upon at least six verticaly spaced tiers of stationary triangular-shaped baffles with upwardly pointing apexes in an elongated deflector section of the static mixer retort having a greater diameter than and positioned substantially below the free-fall section, such that alternate tiers are spaced substantially parallel to each other and substantially perpendicular to adjacent tiers as viewed in top plan view. The tiers extending laterally across the static mixer and including two inlet tiers and at least four other tiers positioned below the inlet tiers, the other tiers having similarly sized triangular-shaped baffles; gravitatingly moving the shale substantially downwardly in a dilute-phase free-fall flow pattern in an upper portion of a surge bin positioned below the static mixer retort and in a dense-phase moving bed in the bottom portion of the bin at the retorting temperature for a sufficient time to substantially completely retort the raw oil shale so as to liberate hydrocarbons therefrom leaving retorted shale; substantially combusting and recycling the retorted shale for use as the spent shale; and separating at least one fraction of shale oil from the hydrocarbons.

"Retorting Process with Contaminant Removal," Arlo J. Moffat and James Scintu - Inventors, Phillips Petroleum Company, United States Patent 4,599,161, July 8, 1986. Hydrogen sulfide issuing from an oil shale retort is captured in an absorbent bed. When the bed is regenerated as with oxygen containing gas, the sulfur dioxide liberated is reintroduced into the retort for reaction with the spent shale.

"Apparatus for Aboveground Separation, Vaporization, and Recovery of Oil fromn Oil Shale," Ray C. Edwards - Inventor, Edwards Engineering Corporation, United States Patent 4,600,476, July 15, 1986. A retort apparatus for recovering oil from crushed oil shale moved through an elongated housing, includes a plurality of heat exchangers located in the housing for transferring heat to or from the shale. The heat exchangers are spaced to define in sequence a drying zone, a preheating zone, a cracking and distillation zone, and a waste heat recovery zone. An auxiliary heating assembly connected to the heat exchangers delivers sufficient heat to raise the temperature of the shale in the cracking and distillation zone to the critical temperature for separating hydrocarbons in vapor form therefrom. The tubes of the heat exchangers are elongated ovals in cross-section and are offset from each other in alternate rows to increase the area of heat exchange and to reduce the temperature drop between the entering heated air and exiting heated air flowing through each heat exchange tube. The heat exchange tubes include common fins which encase banks of the tubes, with the fins on the banks of tubes being aligned with each other to provide passage for flow of crushed oil shale therethrough. A separating device is connected to the cracking and distillation zone to withdraw hydrocarbon vapors released from the shale and to condense the hydrocarbons. Additionally, the retort apparatus includes a device associated with the separating device for maintaining a predetermined operating pressure in the preheat and waste heat recovery zones to prevent separated hydrocarbon vapors from leaking to the atmosphere. "Process for Treating Waxy Shale Oils," Timothy L. Carlson and John W. Ward - Inventors, Union Oil Company of California, United States Patent 4,600,497, July 15, 1986. Waxy shale oil feeds containing organonitrogen and/or organosulfur components are contacted with a catalyst comprising a group vib metal component on a support containing a crystalline aluminosilicate zeolite of the ZSM-5 type and a porous refractory oxide under conditions of elevated temperature and pressure and in the presence of hydrogen so as to simultaneously reduce its pour point and its organosulfur and/or organonitrogen content. "Process for Oil Shale Retorting Using Gravity-Driven Solids Flow and Solid-Solid Heat Exchange," Robert L. Braun, Arthur E. Lewis, Richard C. Mallon, and Otis R. Walton - Inventors, United States Department of Energy, United States Patent 4,601,811, July 22, 1986. A cascading bed retorting process and apparatus in which cold raw crushed shale enters at the middle of a retort column into a mixer stage where it is rapidly mixed with hot recycle shale and thereby heated to pyrolysis temperature; The heated mixture then passes through a pyrolyzer stage where it resides for a sufficient time for complete pyrolysis to occur. The spent shale from the pyrolyzer is recirculated through a burner stage where the residual char is burned to heat the shale which then enters the mixer stage. "Oil Shale Retorting Process," Ardis L. Anderson and James R. McConaghy, Jr. - Inventors, Conoco Inc., United States Patent 4,601,812, July 22, 1986. An oil shale retorting process in which oil shale particles are separated into fines and large particles. The large particles are preheated and combined with hot spent shale from a combustor and introduced into a retorting vessel. The fines are introduced into the disengaging section of the retorting vessel. Retort vapors are processed to produce an upgraded syncrude. The portion of the retort vessel where the oil shale and spent shale are introduced has a smaller diameter than the retorting section.

2-56 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 'Method and Catalyst for Removing Contaminants from Hydrocarbonaceous Fluids Using a Copper-Group Via Metal- Alumina Catalyst,' Quang N Le, Daniel J. Neuman, and Stephen M. Oleck - Inventors, Mobil Corporation, United States Patent 4,601,998, July 22, 1986. There is provided a method and catalyst for removing catalyst poisonin g impurities or contaminants such as arsenic, iron and nickel from hydrocarbonaceous fluids, particularly shale oil and fractions thereof. More particularly there is provided a method of removal of such impurities by contacting the fluids with a copper-group via metal-alumina catalyst. For example, a copper-molybdenum--alumina catalyst may be used as a guard bed material in a step preceding most refining operations, such as desulfurization, denitrogenation, catalytic hydrogenation, etc.

2-57 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS

COMMERCIAL PROJECTS

AMERICAN SYN-CRU DE/IN DIANA PROJECT -- American Syn-Crude Corporation and Stone & Webster Engineering (S-5) American Syn-Crude Corporation proposed a project to produce 4,160 barrels per day of shale oil and 10.3 million standard cubic feet per day of pipeline gas. They plan to use the "Petrosix" technology a surface retort, developed by Petrobras of Brazil. The project was scheduled to commence with mine site preparation during the fourth quarter of 1986, with plant completion and start-up to occur during the second quarter of 1989. Both a loan guarantee and price guarantee were requested from the United States Synthetic Fuels Corporation under the third solicitation. The project was denied financial assistance by the SFC in October 1983. The Kentucky Energy Cabinet and American Syn-Crude completed Kentucky oil shale evaluation tests in June 1983 at Petrobras' pilot plant in Brazil with no process difficulties encountered. The project sponsors have reduced capacity of the project by 50 percent and have moved the project to an Indiana site. A proposal was submitted to the SFC under the fourth general solicitation, and on January 15, 1985 the SFC Board of Directors determined that the project is a "qualified project." However, Congress abolished the SFC on December 19, 1985 before assistance could be awarded to the project. Project Cost: $225 million (1982 dollars) CATHEDRAL BLUFFS PROJECT -- Cathedral Bluffs Shale Oil Company: Occidental Oil Shale, Inc., and Tenneco Shale Oil Company MS, R96W, 6PM) (S-b) Federal Oil Shale Lease Tract C-b, located in Rio Blanco County in the Piceance Creek Basin of northwestern Colorado, is managed by the equal-interest partnership between Occidental Oil Shale, Inc., and Tenneco Shale Oil Company, doing business as Cathedral Bluffs Shale Oil Company. On October 16, 1985 Tenneco Shale Oil Company granted to Occidental Oil Shale, Inc. a two year option to acquire its 50 percent interest in Cathedral Bluffs. During the option period Occidental is the operator for the project for Cathedral Bluffs. A modified detailed development plan for a 57,000 barrels per day modified in situ plant was submitted in March 1977 and subsequently approved in April 1977. The EPA issued a conditional Prevention of Significant Deterioration (PSD) permit in December 1977 which was amended in 1983. Project reassessment was announced in December 1981 in view of increased construction costs, reduced oil prices, and high interest rates. The project sponsors applied to the United States Synthetic Fuels Corporation (SFC) under the third solicitation in January 1983 and the project was advanced into Phase II negotiations for financial assistance. On July 28, 1983 the SFC announced it had signed a letter of intent to provide up to $2.19 billion In loan and price guarantees to the project. However, Congress abolished the SFC on December 19, 1985 before any assistance could be awarded to the project. A "first draft" of the project's detailed development plan was submitted to the Bureau of Land Management Oil Shale Projects Office and other agencies in February 1984. Draft revisions are being planned. Three headframes—two concrete and one steel—have been erected. Four new structures were completed in 1982: control room, east and west airlocks, and mechanical/electrical rooms. The power substation on-tract became operational in 1982. The ventilation/escape, service, and production shafts were completed in Fall 1983. An interim monitoring program was approved in July 1982 and extended through April 1986 to reflect the reduced level of activity. Water management in 1984 was achieved via direct discharge from on-tract holding ponds under the NPDES permit. Environmental monitoring has continued since completion of the two-year baseline period (1974-1976). Project Cost: Not Disclosed CLEAR CREEK PROJECT - Chevron Shale Oil Company (70 percent) and Conoco, Inc. (30 percent) (TSS, R98W, 6PM) (8-20) Chevron and Conoco successfully completed the operation of their 350 tons per day semi-works plant during 1985. This facility, which was constructed on property adjacent to the Chevron Refinery in Salt Lake City, Utah, was designed to test Chevron Research Company's Staged Turbulent Bed (STB) retort process. Information obtained from the semi-works project will allow Chevron and Conoco to proceed with developing a commercial shale oil operation in the future when economic conditions so dictate. Project Cost: Semi-Works - Estimated at $130 million

2-58 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

COLONY SHALE OIL PROJECT —Exxon Company USA (T5S, R95 W, 6PM) (5-30) Proposed 47,000 barrels per day project on Colony Dow West property near Parachute, Colorado. Underground room-and-pillar mining and Tosco II retorting was originally planned. Production would be 66,000 TPD of 35 OPT shale from a 60-foot horizon in the Mahogany zone. Development suspended 10/4/74. Draft EIS covering plant, 196- mile pipeline to Lisbon, Utah, and minor land exchanges released 12/17175. 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 was changed to Casper, Wyoming, and Final EIS supplement was completed. Work on Battlement Mesa community commenced summer 1980. Colorado Mined Land Reclamation permit was approved October 1980. Site development was initiated. C.F. Braun awarded contract 12/80 for final design and engineering of Tosco II retorts. Brown & Root was to construct the retorts. Stearns-Roger awarded contract 2/81 for design and construction liaison on materials handling and mine support facilities. DOE granted Tosco $1.1 billion loan guarantee 8/81. On May 2, 1982, Exxon announced a decision to discontinue funding Its 60 percent share of the present Colony Shale Oil Project. Tosco responded to the decision by exercising its option to require Exxon to purchase Tosco's 40 percent interest. Exxon has completed an orderly phasedown of the project. Construction of Battlement Mesa has been completed and operation is continuing on a reduced scale. An Exxon organization will remain in the Parachute area to perform activities including reclamation, some construction, security, safety, maintenance, and environmental monitoring. These ongoing activities are designed to maintain the capability for further development of the Colony resource when economics become attractive. Project Cost: Estimated in excess of $5 -$6 billion CONDOR PROJECT - Central Pacific Minerals -50 percent; Southern Pacific Petroleum -50 percent (S-31) Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L. (SPP/CPM) announced the completion on June 30, 1984 of the Condor Oil Shale Joint Feasibility Study. SPP/CPM believe that the results of the study support a conclusion that a development of the Condor oil shale deposit would be feasible under the assumptions incorporated in the study. Further investigations are required before the actual project scope is settled, however. Under an agreement signed in 1981 between SPP/CPM and Japan Australia Oil Shale Corporation (JAOSCO), the Japanese partner funded the Joint Feasibility Study. JAOSCO consist of the Japan National Oil Corporation and 40 major Japanese companies. The 28 month study was conducted by an engineering team staffed equally by the Japanese and Australian participants and supported by independent international contractors and engineers. From a range of alternatives considered, a project configuration producing 26.7 million barrels per year of sweet shale oil gave the best economic conclusions. The study indicates that such a plant would involve a capital cost of $US2,300 million and an annual average operating cost of $US265 million at full production, before tax and royalty. (All figures are based on mid-1983 dollars.) Such a project was estimated to require 12 years to design and complete construction with first product oil in Year 6, and progressive build-up to full production in three further stages at two-year intervals. Under the terms of the 1981 agreement, JAOSCO had the exclusive right to negotiate an agreement with SPP/CPM for the next stage of development. Preliminary talks have commenced for this purpose. Specific areas of the Joint Study included: The exploration drilling program determined that the Condor main oil shale seam contains at least 8,100 million barrels of oil in situ, measured at a cut-off grade of 50 liters per ton on a dry basis. The case study project would utilize only 600 million barrels, over a nominal 32 year life. The deposit is amenable to open pit mining by large face shovels, feeding to trucks and in-pit breakers, and then by conveyor to surface stockpiles. Spent shale is returned by conveyor initially to surface dumps, and later back into the pit. Following a survey of available retorting technologies, several proprietary processes were selected for detailed investigation. Pilot plant trials enabled detailed engineering schemes to be developed for each process. Pilot plant testing of Condor oil shale indicated promising results from the "fines" process owned by Lurgi GmbH of Frankfurt, West Germany. Their proposal envisages four retort modules, each processing 50,000 tons per day of shale, to give a total capacity of 200,000 tons per day and a sweet shale oil output, after upgrading, of 82,100 barrels per day. Raw shale oil from the retort requires further treatment to produce a compatible oil refinery feedstock. Two 41,000 barrels per day upgrading plants were incorporated into the project design.

2-59 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

All aspects of infrastructure supporting such a project were studied, including water and power supplies, workforce accommodation, community services and product transportation. A 110 kilometer pipeline to the port of Mackay is favored for transfer of product oil from the plant site to marine tankers. The study indicates that there are no foreseeable infrastructure or environmental issues which would impede development. If a design and construction schedule of 12 years were chosen, allowing a steady but progressive build-up to full production, then an on-site peak construction and operations workforce of up to 3,000 people would be required. Operation of the plant would need 1,700 on-site people at full production. Market studies suggest that refiners in both Australia and Japan would place a premium on Condor shale oil of about $1354 per barrel over Arabian Light crude. Thus a selling price of about $US33 FOB Mackay was assumed. Average cash operating cost at full production is estimated at $US20 per barrel of which more than $1359 per barrel represents corporation taxes and royalty. Capital costs were estimated to an accuracy of +/- 25 percent, mainly by independent international engineering companies. Of the total estimated capital costs of $US2,300 million, almost $US1,700 million is accounted for equally by the three major elements—mining, retorting, and upgrading. The remainder covers supporting plant, infrastructure, administration, and various allowances and contingencies. SPP/CPM stress that all figures are subject to change after the Joint Venturers have had the opportunity to review the final study results. During July 1984 SPP, CPM, and JAOSCO signed an agreement with Japan Oil Shale Engineering Corporation (JOSECO). JOSECO is a separate consortium of thirty-six Japanese companies established with the purpose of studying oil shale and developing oil shale processing technology. Under the agreement, SPP/CPM mined 39,000 tons of oil shale between August and November, 1984 from the Condor oil shale deposit at the site of the previous bulk sample. The oil shale was crushed to produce 20,000 tons of material sized from 15 millimeters to 120 millimeters. This material was railed to Towensville and shipped to Japan on December 12, 1984. Project Cost: $2.3 billion (mid-1983 U.S. dollars) EDWARDS ENGINEERING — Edwards Engineering Corporation (5-33) Edwards Engineering Corporation is proposing a project to be located in Utah or Colorado (Green River, Piceance, Uintah, Sand Wash, or Washakie Basins) to produce an unspecified amount of oil from shale using the Edwards Anaerobic Metal Surface Retort with heat recovery, a completely new patented retorting process. Development work is continuing at Edwards' expense on the further improvement of the Edwards retort, which the project representatives feel possesses very favorable features. The recent operation of the pilot plant has proven that the many desirable features of the Edwards retort are real: low capital cost, a high quality product (API gravity 25-260, pour point 25° to 45°F) no air pollution, heat recovery system resulting in low energy cost, no water required. Continued development work and test runs by Edwards on the pilot plant have been carried out successfully. The process has turned out to be more promising than originally anticipated. Heat transfer rates and production have also been better than anticipated. As a consequence, a small commercial retort producing 1,000 to 2,000 barrels of oil per day could operate profitably at present oil prices. The process can readily be scaled upward in capacity. The next step is the erection of a commercial installation. Edwards intends to continue work on the process. Patents have been granted on the process and additional patents are pending. Edwards will discuss the use of the process with any company exhibiting a qualified serious interest in a small commercial project. A new proposal was submitted to the SFC for evaluation under the fourth general solicitation that closed June 29, 1984. Project Cost: Not Disclosed GARY REFINERY -- Gary Refining Company (5-35) Gary Refining Company operates a refinery in Fruits, Colorado at the southwestern edge of the Piceanee Basin. The Gary oil refinery was constructed in 1957 by the American Gilsonite Company to process gilsonite, a solid hydrocarbon ore that is mined in Northeastern Utah. Gary Energy acquired the refinery in 1973 after American Gilsonite discontinued the refining of gilsonite. Over the past ten years the refinery has been expanded and upgraded into a modern facility capable of processing a wide variety of raw materials into finished transportation fuels. Recent modifications were made to the refinery to process shale oil. Gary Refining now has a contract to purchase 8,600 barrels per day of hydrotreated shale oil from the commercial Union Oil facility. A contract has also been signed with the Defense Fuel Supply Center to provide 5,025 barrels per day of shale-derived military jet fuel (JP-4) to the Air Force over a four year period.

2-60 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

The processing scheme that Gary will use to process the shale oil is geared toward maximizing the yield of JP-4. The blocking operation is due to the Air Force requirements that JP-4 be produced solely from a shale oil feedstock. Therefore, the crude, vacuum, and hydrocracking units will be blocked out, each with a separate operating cycle. Without this Air Force requirement, the shale oil would normally be processed commingled with conventional crude oil. Upgraded shale oil will be delivered to the refinery via a pipeline from the Parachute upgrading facility to Gary's site. JP-4 product will be transported by rail to tankage in Salt Lake City, Utah. Other shale-derived products such as gasoline and No. 2 diesel will be commingled with similar crude-derived products produced at the Gary facility and sold in local markets. In early March 1985 Gary Refining Company shut down the refinery and filed for protection from creditors under Chapter 11 of the United States Bankruptcy Code. The United States Bankruptcy Court approved the company's Reorganization Plan in July 1986. Under the Plan, payments to creditors will begin after delivery of shale oil from the Union Oil plant. Project Cost: Not Disclosed KIVITER PROCESS - Union of Soviet Socialist Republics (3-38) The majority of Baltic oil shale (kukersite) found in Estonia and the Leningrad district in the Soviet Union is used for power generation. However, over 6 million tons are retorted to produce shale oil and gas. The Kiviter process, continuous operating vertical retorts traditionally referred to as gas generators, is predominantly used in commercial operation. The retorts have been automated, and have throughput rates of 200 to 220 tons of shale per day. In the gas generators, low temperature carbonization of kukersite yields 75 to 80 percent of Fischer assay oil. The yield of low calorific gas (3,350 to 4,200 KJ/cubic meters) is 450 to 500 cubic meters per ton of shale. The first 1,000 ton-per-day gas generator was constructed at Kohtla-Jarve, Estonia USSR, and placed in operation in 1981. The new retort employs the concept of crosscurrent flow of heat carrier gas through the fuel bed, with additional heat added to the semi-coking chamber. A portion of the heat carrier is prepared by burning recycle gas. Raw shale is fed through a charging device into two semi-coking chambers arranged in the upper part of the retort. The use of two parallel chambers provides a larger retorting zone without increasing the thickness of the bed. Additional heating or gasification occurs in the mid-part of the retort by introducing hot gases or an oxidizing agent through side combustion chambers equipped with gas burners and recycle gas inlets to control the temperature. Near the bottom of the retort is a cooling zone where the spent shale is cooled by recycle gas and removed from the retort. Oil from kukersite has a high content of oxygen compounds, mostly phenols. Over 50 shale oil products (non-fuel) are currently produced. These products are more economically attractive than traditional fuel oil. The low calorific gas produced as by-product in the gas generators has a hydrogen sulfide content of 8 to 10 grams per cubic meters. After desulfurization, it is utilized as a local fuel for the production of thermal and electric power. Project Cost: Not disclosed

MEANS OIL SHALE PROJECT - Central Pacific Minerals, Bravo Corporation, and Southern Pacific Petroleum (S-36) Southern Pacific Petroleum, Central Pacific Minerals, and Dravo Corporation are joint sponsors of a project proposed to the United States Synthetic Fuels Corporation to extract oil from eastern shale. The Bravo Circular Grate Retort technology is to be used to produce a projected 13,690 barrels of upgraded shale oil plus approximately 20 megawatts of electric power per day. Full operation of the plant, located in Montgomery County, Kentucky is scheduled for the second quarter of 1989. The project passed the SFC Phase I evaluation of maturity and strength in September 1983 under the third solicitation. In April 1984, the sponsors announced that they had withdrawn the project from the SFC's third solicitation and were applying for financial assistance under the fourth solicitation. Both price and loan guarantees were requested from the United States Synthetic Fuels Corporation. The companies are also seeking suitable joint venture arrangements with United States companies. Morgan Stanley and Company is financial advisor to the project. The project was dropped from further consideration under the fourth solicitation on January 15, 1985. Of the companies' leases of 15,000 acres, it is proposed to mine 4,000 acres, containing approximately 140 million barrels of shale oil, over 25 years at the rate of 66,000 short tons daily (of which 50,000 short tons will be retorted). Gas by-product of retorting is to be used to fuel various project facilities and a power cogeneration plant which will produce sufficient power for the Project together with a surplus for sale to local utilities.

2-61 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

Dravo is the Project's Development Engineer and is continuing a full range of engineering activities related to design and feasibility. Dravo completed retorting and upgrading pilot plant tests in June 1983 with no process difficulties encountered. Level Il/Ill engineering satisfying SFC criteria was complete by August 1983.

Project Cost: Approximately $1 billion MOBIL PARACHUTE SHALE OIL PROJECT - Mobil Oil Corporation (T6S, R95W, 6PM) (S-40) Mobil is proceeding with development plans for its shale property located on 10,000 acres five miles north of Parachute. Currently, construction is planned to begin in the late 1980s for initial production of 10,000 to 25,000 barrels per day in the 1990s with an incremental buildup to 100,000 barrels per day after the year 2000. The United States Bureau of Land Management has completed an Environmental Impact Statement preparatory to future permit applications. A Corps of Engineers Section 404 permit application has been submitted and is currently being processed. Mobil is currently performing preliminary engineering work. Project Cost: Estimated $8 billion for 100,000 BPD production MOROCCO OIL SHALE PROJECT-- ONAREP; Science Applications, Inc. (5-55) During 1975 a drilling and mining survey revealed 13 oil shale deposits in Morocco including three major deposits at Tirnandit, Tangier, and Tarfaya from which the name T3 for the Moroccan oil shale retorting process was derived. In February 1982, the Moroccan Government concluded a $4.5 billion, three phase joint venture contract with Royal Dutch/Shell for the development of the Tarfaya deposit including a $4.0 billion, 70,000 barrels per day plant. However, the project faces constraints of lower oil prices and the relatively low grade of oil shale. No significant activity is underway except the resource evaluation and conceptual design studies for a small demo plant. Construction of a pilot plant at Timandit has been completed with a funding from the World Bank in 1984. System press test and the plant acceptance test have also been completed in 1984. During the first quarter of 1985, the plant has gone through a successful shakedown test, followed by a preliminary single retorting test. The preliminary test produced over 25 barrels of shale oil and proved the fundamental process feasibility of the T 3 process. More than a dozen single retort tests have been conducted so far to prove the process feasibility as well as to optimize the process conditions. Single retort parametric tests will continue through 1985 and the double retort T3 process tests will start in early 1986. The pilot plant utilizes the t3 process developed jointly by Science Applications, Inc., and the Office National de Recherche at d'Exploitation Petrolieres (ONAREP) of Morocco. The T3 process consists of a semi-continuous dual retorting system in which heat from one vessel that is being cooled provides a portion of the energy that is required to retort the shale in the second vessel. The pilot plant has a 100 tons of raw shale per day capacity using 17 OPT shales. The design of a demonstration plant, which will have an initial output of 280 barrels per day, rising to 7,800 barrels per day when full scale commercial production begins, has been deferred until the pilot plant operation is completed in 1985. A commercial scale mine development study at Timandit is being conducted by Morrison-Knudsen. The T3 process will be used in conjunction with other continuous processes in Morocco. In 1981/1982, Science Applications, Inc., conducted for ONAREP an extensive process option studies based on all major processes available in the United States and abroad and made a recommendation in several categories based on the results from the economic analysis. An oil-shale laboratory including a laboratory scale retort, computer process model and computer process control, has been established in Rabat with assistance from Science Applications, Inc. Project Cost: Not disclosed

PACIFIC PROJECT - Cleveland-Cliffs -20 percent, Sohio - 60 percent, and Superior - 20 percent ('ItS, R98W, 6PM) (S-GO) Sohio, Superior, and Cliffs are continuing to conduct pre-construction work for development of the Pacific Shale Project. The project will be located approximately 10 miles north of DeBeque, Colorado, in Garfield County. The major project components will be developed on approximately 12,600 acres of land that is owned by the venture partners. Commercial feasibility studies and environmental baseline studies were completed for the project in 1983. In December 1984, the Bureau of Land Management completed the preparation of an environmental impact statement to assess project impacts prior to the sale and lease of federal lands that are necessary to the project. Project Cost: Development schedule and project cost are not available.

2-62 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

PARACHUTE CREEK SHALE OIL PROGRAM - UNOCAL 76 (5-70) In 1920 Unocal began acquiring oil shale properties in the Parachute Creek area of Garfield County, Colorado. The 20,000 acres of oil shale lands Unocal owns contain about 1.6 billion barrels of recoverable oil in the high-yield Mahogany Zone alone. Since the early 1940s, Unocal research scientists and engineers have conducted a wide variety of laboratory and field studies for developing feasible methods of producing usable oils from shale. In the 1940s, Unocal operated a small 50 ton per thy pilot retort at its Los Angeles, California refinery. From 1955 to 1958, Unocal built and operated an upflow retort at the Parachute site, processing up to 1,200 tons of ore per day and producing up to 800 barrels of shale oil per day. Unocal began the permitting process for its Phase 1 10,000 barrel per day project in March 1978. All federal, state, and local permits were received by early 1981. Necessary road work began in the Fall 1980. Construction of a 12,500 short ton per day mine began in January 1981, and construction of the retort started in late 1981. Concurrently, work proceeded on a 10,000 barrels per day upgrading facility, which would convert the raw shale oil to a high quality syncrude. Construction concluded and the operations group assumed control of the project in the Fall 1983. Several plant start-ups have occurred, with valuable data being gathered. As a result, modifications have been made to the retort and shaft cooling system. In July 1981, the company was awarded a contract under a United States Department of Energy (DOE) program designed to encourage commercial shale oil production in the United States. Unocal's contract with the DOE calls for delivery of 3,000 barrels per day of military aircraft turbine fuel and 7,000 barrels per day of diesel to the Department of Defense (DOD) commencing with shale oil production. The price will be the market price or a contract floor price. If the market price is below the DOE contract floor price, indexed for inflation, Unocal will receive a payment from DOE to equal the difference. The total amount of DOE price supports Unocal could receive is $400 million. To date, Unocal has received no price support funds despite having invested over $800 million of Its own funds. The DOE Phase I contract has been amended to include a maximum of an additional $500 million in loan and price guarantees from the United States Department of Treasury, successor to the United States Synthetic Fuels Corporation. The Department of Treasury assistance will be utilized to support the Incorporation of a fluidized bed combustor into the existing Phase I facility. The augmentation phase of the project involves modifying the existing Phase I "B" retort to incorporate the "Unishale C" technology. This new technology would replace the current cooling system with a fluidized bed combustor. The combustor would recover more energy by burning the carbon residue on the retorted shale. The company tentatively plans to complete engineering of the fluidized bed in 1986. Operations would commence in 1989. Production of shale oil would remain at 10,000 barrels per day if Unocal elects to proceed with the augmentation program. Project Cost: Phase I - Approximately $650 million PARAHO-UTE SHALE OIL FACILITY - Paraho Development Corporation; Raymond Raiser Engineers, Inc.; The Signal Companies; Texas Eastern Synfuels, Inc. (T95, R25E, Sec. 32, SLM) (S-80) Paraho Development Corporation and its private industry sponsors are currently pursuing the development of the Paraho-Ute Project to be located on over 5,500 acres of oil shale lands dedicated to the project in Uintah County, Utah. The project, as originally proposed, would utilize a Paraho aboveground retort to produce approximately 14,000 barrels per day of hydrotreated shale oil. By-products of retorting include ammonia, sulfur, and electricity from excess low-BTU gas. A 14,000 barrels per day hydrotreating facility was to be constructed during Phase I. All permits required for construction have been submitted with approval already granted or pending. Paraho is requesting loan and price guarantees for the project from the United States Synthetic Fuels Corporation's third solicitation. The project passed both the SFC's project maturity and strength evaluations and has SFC approval on the key financial and business terms. Pending the mutually satisfactory completion of a final award between the project and the SFC, construction on the project could possibly get underway in 1986 with production beginning In 1988-1989. In November 1985, the SFC announced that the sponsors had proposed a down-sized project that would produce 4,500 barrels of shale oil per thy. However, Congress abolished the SFC on December 19, 1985 before any assistance could be awarded to the project. Project Cost: Not available

2-63 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (continued)

PETROSIX - Petrobras (Petroleo Brasileiro, S.A.) (5-90) A nominal 2,200 tons per day Petrosix semi-works retort, 18 foot inside diameter, is 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 United States patent has been obtained on the process. This plant operating on a small commercial basis since 1981, currently produces 800 barrels per day of crude oil and 14 tons per day of sulfur. A 36 foot inside diameter retort, called the industrial module, is being constructed and will produce 2,950 barrels per day of oil, 40 tons per day of LPG, and 60 tons per day of sulfur in the beginning of 1988. Project Installed Costs: $68.4 (US) Million RAMEX OIL SHALE GASIFICATION PROCESS—Ramex Synfuels International, Inc. (S-95) On May 6, 1985 Ramex announced the start of construction of a pilot plant near Rock Springs, Wyoming. The plant will be located on property leased from Rocky Mountain Energy, a subsidiary of Union Pacific Railroad. In addition to the one section leased for the pilot plant, Ramex also has options on ten additional sections. This site was selected because of the accessibility for potential customers, and the abundance of available oil shale reserves. The pilot plant will consist of two specially designed burners that will burn continuously in an underground oil shale bed. These burners will produce an industry quality gas (greater than 800 BTUs per standard cubic foot) and liquid condensate, consisting of about 45 percent gasoline, 25 percent kerosene, 30 percent light oils. The pilot facility was expected to be in operation by July 1985. The data and products produced from this plant will be available for testing and evaluation by companies interested in the process and potential users of the products. Universal Search Technologies (Unitec) of Salt Lake City, Utah is assisting with the first phase of funding and management for the project. Project Cost: Approximately $1 million for the pilot tests. RIO BLANCO OIL SHALE PROJECT - Rio Blanco Oil Shale Company (wholly owned by Amoco Corporation) (T2S, R99W, 6PM) (S-leo) Proposed project on federal Tract C-a in Piceance Creek Basin, Colorado. Bonus bid of $210.3 million to acquire rights to tract; lease issued 3/1/74. Completed four-year modified in situ demonstration program at end of 1981. Burned two successful retorts. First retort was 30' x 30' x 166' high and produced 1,907 barrels of shale oil. It burned between October and late December 1980. Second retort was 60' x 60' x 400' high and produced 24,790 barrels while burning from June through most December of 1981. Program cost $132 million. Company still prefers open pit mining-surface retorting development because of much greater resource recovery of five versus two billion barrels over life of project. Cannot develop tract efficiently in that manner without additional federal land for disposal purposes and siting of processing facilities. In August 1982, the company temporarily suspended operations on its federal tract after receiving a 5 year lease suspension from the United States Department of Interior. The project is still in suspension until a lease can be obtained. Federal legislation has been enacted to allow procurement of off-tract land that is necessary if the lease is to be developed in this manner. An application for this land was submitted to the Department of Interior In 1983. Based on the decision of the director of the Colorado Bureau of Land Management an environmental impact statement for the proposed lease for 84 Mesa is being prepared by the Bureau of Land Management. Rio Blanco submitted a MIS retort abandonment plan to the Department of Interior in Fall 1983. Partial approval for the abandonment plan was received in Spring 1984. The mine and retort are currently flooded but were pumped out in the Spring 1985 in accordance with the plan approved by the Department of the Interior. Data from the pumpout are being evaluated. Stringent monitoring is continuing. Rio Blanco operated a $29 million one to five TPD Lurgi pilot plant at Gulf's Research Center in Harmarville, Pennsylvania until late 1984 when it was shut down. Data analysis is currently underway. This $29 million represents the capital and estimated operating cost for up to 5 years of operation. Engineering and planning for open pit-surface retorting development are being continued. The company has not as yet developed commercial plans or cost estimates. On January 31, 1986 Amoco acquired Chevron's 50 percent interest in the Rio Blanco Oil Shale Company, thus giving Amoco a 100 percent interest in the project. Amoco has no plans to discontinue operations. Project Cost: Four-year process development program cost $132 million No cost estimate available for commercial facility.

2-64 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

RUN DLE PROJECT -- Central Pacific Minerals/Southern Pacific Petroleum (50 percent) and Esso Exploration and Production Australia (50 percent) (5-110) The Rundle Oil Shale deposit is located new Gladstone in Queensland, Australia. In April 1981, construction of a multi-module commercial scale facility was shelved due to economic and technical uncertainties. Under a new agreement between the venturers, which became effective in February 1982, Esso agreed to spend A$30 million on an initial 3 year work program that would resolve technical difficulties to allow a more precise evaluation of the economics of development. During the work program the Dravo, Lurgi, Tosco, and Exxon retorting processes were studied and tested. Geological and environmental baseline studies were carried out to characterize resource and environmental parameters. Mine planning and materials handling methods were studied for selected plant capacities. Results of the study were announced in September 1984. The first stage of the project which would produce 5.2 million barrels per year from 25,000 tons per day of shale feed was estimated to cost $645 million (US). The total project (27 million barrels per year from 125,000 tons per day of shale feed) was estimated to cost $2.65 billion (US). In October 1984 SPP/CPM and Esso announced that they have commenced discussions about possible amendments to the Rundle Joint Venture Agreement signed in 1982. Those discussions were completed by March 1985. Revisions to the Joint Venture Agreement now provide for: • Payment by Esso to SPP/CPM of A$30 million in 1985 and A$12.5 (contingent on maintaining satisfactory title over the Rundle resource) in 1987. • Each partner to have a 50 percent interest in the project. • Continuation of a Work Program to progress development of the resource. Cost of this program in 1985 was A$7.5 million. • Esso funding all work program expenditures for a maximum of 10 years, and possible funding of SPPJCPM's share of subsequent development expenditures. If Esso provides disproportionate funding, it would be entitled to additional offtake to cover that funding. Project Cost: See above TOSCO SAND WASH PROJECT —Tosco Corporation (T95, R21E, SLM) (S-120) Proposed 49,000 BPSD project on 17,092 acres of State leases in Sand Wash area of Uintah Basin near Vernal, Utah. A State-approved unitization of 33 non-contiguous leases required $8 million tract evaluation, which has been completed. On-site environmental assessments have been completed and applications for right-of-way permits for roads, water pipeline, inter-block conveyors, power lines, underground mine access tunnels and product pipeline were submitted to Bureau of Land Management in April 1981. Final EIS for the project was issued on February 1983. The Federal PSD permit was issued on December 10, 1981 and the Utah air quality permit was approved in March 1983. All permits for commencement of construction of the first mine shaft have been filed. Tosco has completed a core-hole drilling program and a final design for a 16 foot diameter mine shaft and related facilities. Construction of this initial development shaft and experimental mine would enable confirmation of (1) the geologic and geotechnical basis for the mine design, (2) estimated mining costs, and (3) the basis for enhancing projected mining recovery ratios for the commercial project. The second phase of the Project will consist of the construction of one 11,000 tons per day TOSCO II pyrolysis unit and related oil upgrading facilities which would produce 11,200 barrels per stream day of hydrotreated shale oil. During the third phase, Tosco will expand the facility to six pyrolysis units and a 66,000 tons per day mine, producing a nominal 50,000 barrels per day of shale oil. Contemporaneous development of Phases 1 and 2 is being considered. The definitive design of the single train facilities has been completed. Project Cost: $820 million in second quarter 1982 dollars (excluding interest) R&D PROJECTS

BAYTOWN PILOT PLANT - Exxon Research and Engineering (S-135) During 1984 a $14 million pilot plant to test the recovery of oil from shale began operation at Baytown, Texas. The pilot program follows several years of research aimed at developing a more efficient, lower-cost method of retorting shale. It uses fluidized bed technology, building on Exxon's experience with the use of fluidized beds in

2-65 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) K & D (Continued)

petroleum refining. With a capacity of five tons of shale per day, the plant is testing Exxon's retorting process on different shales under a wide range of conditions. Project Cost: See above DUO-EX SOLVENT EXTRACTION PILOT PROJECT - Duo-Ex (a wholly owned subsidiary of Solv-Ex Corporation) and United States Department of Energy (5-152) Duo-Ex has submitted a proposal in response to a Department of Energy solicitation to perform test work to establish the commercial, technical and economic feasibility of a new approach to shale oil recovery. The Solv-Ex approach will convert kerogen to bitumen and lighter products in a solvent extraction medium. Efforts of other companies to date to utilize shale oil resources have centered around retorting and in situ processes with limited success. Solv-Ex has developed a technology that it believes will be environmentally acceptable, cost effective, have shorter lead times from project commitment to production and will use smaller scale facilities than retorting and in situ processes. Experiments with the Solv-Ex process would be conducted at the bench level and then in a continuously fed unit processing up to 10 pounds of tar sands per hour, complete with recycle, product recovery and solid separation steps. The program is based on previous work by Duo-Ex in a batch reactor and prior engineering studies. The project will determine recoveries of oil, produce scale-up data and a quantity of raw shale for upgrading studies. Project Cost: $1,064,000 GELS ENKIRCHEN-SCHOLVEN CYCLONE RETORT PROJECT -- Veba Gel Entwicklungs-Gesellschaft mbH (S165) Veba is developing a cyclone retorting process. They are building a pilot plant at Gelsenkirchen-Scholven. This program is subsidized b7 the German government and the European Economic Community. Retorting is done in a cyclone at 5000 to 550 C and atmospheric pressure. The heat is obtained from recycled gas at 650 0 to 700°C. Hydrocarbons remaining in the spent shale are burned in a fluidized bed at 800° to 850 C. The flue gases from this bed are used to heat the recycle gas to provide the necessary heat for retorting. Plant startup is scheduled for mid- 1986. Project Cost: Not Disclosed GEOKINETICS, INC. - (see Seep Ridge) JAPANESE RETORTING PROCESSES — Japan Oil Shale Engineering Company, Ltd. (JECO) (S-170) Japan Oil Shale Engineering Company, Ltd. (JOSECO) was organized in July 1981 under the guidance of the Ministry of International Trade and Industry and the Japan National Oil Corporation. A 5 year R & D plan was formulated, however this original plan has been recently revised to a 7 year plan due to budgetary control. JOSECO was financed by 36 Japanese companies in various industrial fields including iron and steel, heavy machinery, mining, cement, plant engineering, and oil refining. Three types (a vertical shaft, a circular grate, and a new cross flow type) of retorts were built at a scale of about 3 tons per thy. These were designed and constructed in 1982 and were operated through August 1983 on oil shales from the United States, Australia, China, and Morocco. In the shaft type retort, oil shale descends continuously from the retorting zone to the residual carbon combustion zone. To prevent flow of gas from the combustion zone to the retorting zone, a seal zone is provided between the two zones to separate them. Operation of the pilot plant was generally smooth, and the yield of shale oil was approximately equal to Fischer assay. The main feature of this type of plant is the high thermal efficiency obtained by the vertical counterflow of the oil shale and gas. With the circular grate retort, oil shale is charged onto the circumferentially moving grate and passes through preheating,retorting, combustion and cooling zones, being contacted by the gas which flows downward through these zones. Oil yield obtained from several kinds of oil shale was approximately equal to Fischer assay. The main feature of this type of plant is that the process can be adapted to the properties of different oil shales because the size of each zone can be set arbitrarily. The cross flow retort is completely separated from the combustion furnace. Oil shale flows down the inside surfaces of louver walls and is contacted by the heating gas which flows horizontally between the walls in several passes. In

2-66 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986)

R & D (Continued)

the pilot plant, oil yield was approximately equal to Fischer assay. The retorted oil shale is crushed to pieces smaller than 6 millimeters and sent to a fluidized bed for combustion of residual carbon. The main features of this type of plant are the low pressure loss in the retorting zone and the high carbon utilization ratio obtained with the fluidized bed. JOSECO is further planning a large pilot plant. The process to be used for the pilot plant was discussed by the advisory committee on the basis of results of the experiments on the three small-scale plants, and then determined to consist mainly of a vertical shaft type retort. The pilot plant is expected to have the capacity of 300 tons per day and to be constructed in Kitakyushu, Japan by 1986. For the operation of the pilot plant, a few kinds of oil shale will be imported to Japan. For one of the samples for the pilot plant test, approximately 42,000 tons of Condor oil shale ore were excavated, crushed, and screened in 1984 under the agreement between SPP/CPM, JAOSCO, and JOSECO. Approximately 20,000 tons of crushed and screened oil shale ore were transported to Japan and stored at the pilot plant site during December 1984 to January 1985. The construction of the pilot plant was started in the middle of February 1986 and will be completed by the end of the year.

Project Cost: .Approximately SUS 60 million

ISRAELI RETORTING DEVELOPMENT - PAMA (Energy Resources Development) Inc. (5-175) Israeli oil shale development is being coordinated by PAMA (Energy Resources Development) Ltd. PAMA was founded by several major Israeli corporations with the support of the government. PAMA launched a multi-year program directed toward commercial utilization of Israel's oil shale. The initial feasibility stage was set for 3 years and entails expenditures around $US20 million. Oil shale can be utilized by retorting to produce shale oil, or by direct combustion to generate power. PAMA has been pursuing both possibilities, and preliminary engineering for two demonstration plants began in late 1984. The main goal is to determine the feasibility of oil production by one of the retorting processes that have reached an advanced state of development. PAMA has conducted several series of retorting tests, utilizing oil shale from the Rotem deposit, in pilot plants representing advanced processes. In more than one case, the retorting pilots have performed well with Israeli oil shale producing oil and gas at reasonably good efficiencies. PAMA plans the construction of a semi-works demonstration plant of sufficient scale for resolving technical and economic issues. The size of the demo will fall in the range of 1,000 to 2,000 tons per day of raw oil shale. The investment required is estimated at around $13525 to $US30 million. PAMA selected the Paraho technology for testing in the demonstration plant. The workplan and schedule call for detailed design and construction of the demo plant by March 1987. The main goal of the PAMA oil shale combustion program is to develop capability to burn oil shale directly on a large scale. They are also studying the feasibility of industrial cogeneration of steam and power for factories adjacent to the oil shale deposits. Although PAMA is studying the feasibility of burning Israeli oil shale in conventional pulverized flame boilers, work to date indicates that fluid bed combustion suits Israeli shale better. Several series of combustion tests have been run in pilot plants, in Israel and abroad. One drawback of fluid bed combustion lies in the size of the boilers that represent the state-of-the-art today. To develop capability to burn oil shale on a large scale, PAMA has concluded that it is necessary to construct a demonstration plant delivering 50 to 100 tons per hour of steam. The timetable for this project is identical to that for the retort pilot plant. The design of the demo plant for direct combustion will be based on data being generated in PAMA's own small pilot plant. It was designed for a nominal burning capacity of 1 ton of oil shale per hour. The fluid bed combustor is 60 centimeters inside diameter. The pilot plant program aims at large capacities. There is also an opportunity for near-term use of commercial boilers to serve industrial customers in the vicinity of the shale deposits. There are boilers in the world, mostly fluid bed, which have seen service in combustion of low-grade coal, and should be suitable for oil shale. PAMA examined two such boilers with encouraging results. PAMA has begun preliminary engineering toward the construction of the two demonstration plants, the first for produciton of oil, and the second for production of power by direct combustion of the oil shale. The demonstration plant for production of oil shale shall be based on the Paraho technology. PAMA has just completed construction of an experimental unit for retorting oil shale in fluidized- and entrained-bed retorts.

Project Cost: Not disclosed

2-67 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

JULIA CREEK PROJECT - CSR LIMITED (5-180) A preliminary study was conducted in 1980 to determine feasibility of a large scale extraction of oil from the Julia Creek deposit of northwestern Queensland, Australia. The project concept involves surface mining, above-ground retorting, and on-site upgrading to produce either a premium refinery feedstock or marketable fuels, particularly kerosene and diesel. The project developer is CSR Ltd. and partners to be selected. The project has proven reserves of shale amenable to open-cut mining containing about 2 billion barrels of crude shale oil. The average oil content of the shale is approximately 70 litres per dry tonne. Work is being carried out jointly by CSR and CSIRO on the development of a new retorting process based on spent shale ash as a recirculating solid heat carrier. A staged development is planned, with the timing determined by the anticipated price of oil and improvements In project economics. Project Cost: Yet to be determined NAVAL OIL SHALE RESERVE (NOSE) DEVELOPMENT - United States Department of Energy (5-200) Naval Oil Shale Reserve No. 1 (NOSR-1) was established by President Wilson in 1916. NOSR-1 is located north of the Colorado River in GaFflhld County, Colorado. NOSR-3, which borders NOSR-1 on the east and on the south, was established by President Coolidge in 1924. NOSR-1 contains 18 billion barrels of oil in place. An estimated 2.3 billion barrels of recoverable oil could be produced from shale with a yield of over 30 gallons per ton. This would be enough to feed a 100,000 barrels per day plant for 70 years. NOSR-3 contains essentially no oil shale, and Its designation as a reserve was considered necessary to obtain access to the Colorado River for water requirements, and areas for spent shale disposal during the ultimate anticipated development of NOSR-l. NOSR-2 is an oil shall reserve of 90,400 acres located in Carbon and Uintah Counties, Utah. NOSR-2 has an estimated 4 billion barrels of oil in place. No estimate of recoverables has been made as the shale beds are thought to be too thin to be economically recoverable. In June 1977, the federal government called for preparation of a Master Development Plan for Naval Oil Shale Reserves 1 and 3. A contract was awarded June 22, 1978 to a team composed of CF Braun & Company, Gulf Research & Development Company, Tosco Corporation, TRW, and Williams Brothers Engineering Company, Comparative analysis of NOSR-1 and eight other Piceance Creek basin properties has been completed. A final Environmental Impact Statement (EIS) was issued August 1982. In addition, resource, technology, and environmental baseline characterizations have been completed. The program produced over 40 technical reports. The Anvil Points Facility, located on NOSR-3 near Rjap, Colorado, was a testing and research facility providing information on facility design, and it also provided sufficient quantities of shale oil for laboratory research and refinery tests. After one-half a century in off-and-on operation, the test facility has outlived its usefulness and original purpose. A decision was made in 1984 to dismantle the facility and to restore the site to its natural condition. Demolition work began in the summer of 1985. Demolition was completed in January 1986. Habitat restoration will be completed in 1986. The Department of Energy's oil shale research program at NOSR-1 and 3 has been discontinued and the facilities have been dismantled and the site returned to its natural state, to the extent possible. Project Cost: $10 million through September 30, 1986 RAPAD SHALE OIL UPGRADING PROJECT -- Japanese Ministry of international Trade and Industry (S-205) The Research Association for Petroleum Alternatives (RAPAD), supported by the Japanese Ministry of International Trade and Industry, has adopted shale oil upgrading as one of its major research objectives. Developmental works are being conducted on pretreating technology, two hydrorefining processes using fixed-bed type and ebullated-bed type reactors, high-performance catalysts for those processes, and a two-step treating system. Research and development work is being conducted on pretreating for the removal of clay minerals by an electric desalting system and on demetallizing catalysts. It has been found that a catalyst prepared by supporting molybdenum on alumina carrier showed high activity for the removal of arsenic.

2-68 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since June 1986) COMMERCIAL PROJECTS (Continued)

Using fixed-bed type and ebullating-bed type hydrorefining bench-scale plants, catalysts of excellent performance were developed, reaction conditions were examined, and product oils were analyzed. The effect of arsenic compounds on the life of catalysts, and the effect of admixed sulfur compounds on denitrogenation activity were examined. A two-step hydrotreating system is under study. For the first stage, an ebullated-bed reactor was employed, and shale oil was partially hydrorefined. In the second stage, under conditions of hydrotreating processes performed at existing petroleum refineries, mixtures of hydrorefined oil (syncrude) fractions and corresponding fractions of petroleum crude oil were hydrotreated. A large bench-scale plant (1.5 barrels per day) was built in early 1986 and has been in operation for collecting engineering data.

Project Cost: Not Disclosed TRIAD DONOR SOLVENT PROJECT -- Triad Research Inc. (S-215) Triad Research Inc. is developing a liquid donor solvent process for extraction of oil from low-grade shales. The process is said to be capable of producing oil yields of as much as 200 to 250 percent of Fischer Assay. The new process, named the H-E process, utilizes a fraction of the oil derived from the shale as the hydrogen donor solvent. Laboratory experiments to date have shown that oil yields from Sunbury shale samples equivalent to more than 200 percent of Fischer Assay are achieved at operating pressure as low as 15 to 20 atmospheres. The sponsors are 94 percent complete with the design, engineering, procurement, and construction of a pilot plant facility.

Project Cost: Not Disclosed

YAAMBA PROJECT - Yaamba Joint Venture (Beloba Pty. Ltd., Central Oil Shale Pty. Ltd., and Peabody Australia Pty. Ltd.) (5-220) The Yaamba Oil Shale Deposit occurs in the Yaamba Basin which occupies an area of about 57 square kilometers adjacent to the small township of Yaamba located 30 kilometers (19 miles) north-northwest of the city of Rockhampton, Australia. Oil shale was discovered in the Yaamba Basin in 1978 during the early stages of a regional search for oil shale in buried Tertiary basins northwest of Rockhampton. Exploration since that time has outlined a shale oil resource estimated at more than 2.8 billion barrels extending over an area of 32 square kilometers within the basin. The oil shales which have a combined aggregate thickness of over 300 meters in places occur in 12 main seams extending through the lower half of a Tertiary sequence which is up to 800 meters thick toward the center of the basin. The oil shales subcrop along the southern and southwestern margins of the basin and dip gently basinward. Several seams of lignite occur in the upper part of the Tertiary sequence above the main oil shale sequences. The Tertiary sediments are covered by approximately 40 meters of unconsolidated sands, gravels, and clays. Partners in the Yaamba Joint Venture are Peabody Australia Pty. Ltd., with 50 percent interest, Central Oil Shale Pty. Ltd., with 40 percent interest, and Beloba Pty. Ltd., a fully owned subsidiary of Southern Pacific Petroleum N.L. and Central Pacific Minerals N.L., with 10 percent interest. Peabody Australia manages the Joint Venture which now holds two "Authorities to Prospect" for oil shale in an area of approximately 1,080 square kilometers in the Yaamba and Broad Sound regions northwest of Rockhampton. The "Authorities to Prospect" were granted to the Yaamba Joint Venture by the government of the State of Queensland for a five year term commencing May 1983. In addition to the Yaamba Deposit, the "Authorities to Prospect" cover a second prospective oil shale deposit in the Herbert Creek Basin approximately 70 kilometers northwest of Yaamba. Drilling in the Herbert Creek Basin is still in the exploratory stage. A Phase I feasibility study, which focused on mining, waste disposal, water management, infrastructure planning, and preliminary ore characterization of the Yaamba oil shale resource, has now been completed. Environmental baseline investigations were carried out concurrently with this study. A Phase II study aimed at determining methods for maximum utilization of the total energy resource of the Yaamba Basin and optimization of all other aspects of the mining operation is currently in progress. Further environmental baseline investigations are also being carried out. This study is anticipated to extend over a five year period. Project Cost: Not disclosed

2-69 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL. SHALE PROJECTS (Underline denotes changes since June 1986) R & V (Continued)

YUGOSLAVIA INCLINED MODIFIED IN SITU RETORT -- United Nations (S-230) Oil shale deposits in Yugoslavia are mainly located in the eastern part of the country, almost entirely in the Republic of Serbia. The best geologically evaluated oil shale deposit is located near the town of Aleksinac, in the lower Juzna Moravica River valley. Oil shale dips from the surface at an angle of 300 to 400 up to a depth of 400 meters where it then levels. An experimental 3.5 tons per day gas combustion retort was built and tested in 1955 to 1962. In addition, retorting in an indirect retort was carried out in Sweden on 100 tons of Aleksinac oil shale in 1957. A joint effort by several UN consultants from the United States and Yugoslavia national staff produced the Inclined Modified In Situ (IMIS) Method to cope with the dipping oil shale seams characteristics of the Aleksinac Basin. To achieve the appropriate void formation 23 percent of the shale rock would be mined. Design criteria for the IMIS retort include an oil shale yield of 115 liters per ton, and a retort height of 100 meters. The retort injection mixture would be 50 percent air and 50 percent steam. Eight modules of IMIS retorts would be in operation at a time, producing 15,700 barrels per day of oil. Surface retorts would produce 4,470 barrels per day of oil, making the total capacity at Aleksinac 20,000 barrels per day at full production (about I million tons per year). For the mined shale, interest has been expressed in adapting the T3 retort system under development in Morocco. The overall resource recovery rate would be about 49 percent. Construction time for a 20,000 barrels per day facility is estimated to be 11 years. The estimated project cost was about $650 million (US). The estimated shale oil net production cost was $21.00 (US) per barrel and the the upgrading cost was estimated to be $7.00 (US) per barrel. In the mined brown coal area, the coal mine workings can provide access to the oil shale for an initial pilot module. Go-ahead for a full-scale 20,000 barrels per day operation would be given only after the results of the pilot module are known. The pilot module is now under design by Energoproject, Belgrade, as general contractor with UNDP support. Establishment of the IMIS experiment is expected in 1988. Project Cost: See above

2-70 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 COMPLETED AND SUSPENDED PROJECTS

Project Sponsors Last Appearance in SFR

BX In Situ Oil Shale Project Equity Oil Company March 1984; page 2-52 Cottonwood Wash Project American Mine Service March 1985; page 2-73 Cives Corporation Deseret Generation & Transmission Coop. Poster Wheeler Corporation Davy McKee Magic Circle Energy Corporation Direct Gasification Tests Tosco Corporation September 1978; page 9-4 Exxon Coloradc Shale Exxon Company USA March 1985, page 2-73 Laramie Energy Technology Center Laramie and Rocky Mountain Energy June 1980; page 2-34 Company Logan Wash Project Occidental Oil Shale Inc. September 1984; page 5-3 Naheolite Mine #1 Multi-Mineral Corporation September 1982; page 2-40 Oil Shale Gasification Institute of Gas Technology; December 1978; page B-3 American Gas Association Paraho Oil Shale Full Size Paraho Development Corporation December 1979; page 2-35 Module Program Silmon Smith Kellogg Corporation March 1995, page 2-72 Shale Energy Corporation of America United States Bureau of Mines Shaft Multi-Mineral Corporation; United States December 1983; page 2-52 Bureau of Mines United States Shale United States Shale Inc. March 1985, page 2-72 Unnamed In Situ Test Meeco, Inc. September 1978; page 8-3 Unnamed Fracture Test Talley Energy Systems September 1978; page 8-4 White River Shale Project Phillips Petroleum Company March 1985; page 2-72 Standard Oil Company (Ohio) Sun Oil Company

2-71 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SHALE PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name American Syn-Crude Corporation American Syn-Crude/Indiana Project 2-58 Amoco Coporstion Rio Blanco Oil Shale Project (C-a) 2-64 Beloba Pty. Ltd. Yaamba Project 2-69 Cathedral Bluffs Shale Oil Company Cathedral Bluffs Project (C-b) 2-58 Central Oil Shale Pty. Ltd. Yaamba Project 2-89 Central Pacific Minerals Condor Project 2-59 Means Oil Shale Project 2-61 Rundle Project 2-65 Yaamba Project 2-69 Chevron Shale Oil Company Chevron Clear Creek Project 2-58 Cleveland-Cliffs Iron Company Pacific Project 2-61 Conoco Inc. Chevron Clear Creek Project 2-58 CSR Limited Julia Creek Project 2-66 Dravo Corporation Means Oil Shale Project 2-61 Duo-Ex (Solv-Ex Corporation) Duo-Ex Solvent Extraction Pilot Project 2-66 Edwards Engineering Company Edwards Engineering 2-60 Esso Australia Ltd. Rundle Project 285 Exxon Company USA Colony Shale Oil Project 2-59 Exxon Research and Engineering Baytown Pilot Plant 2-65 Gary Refining Company Gary Refinery 2-60 Geokinetics, Inc. Seep Ridge (Wolf Den and Agency Draw Projects) 2-66 Japanese Ministry of International RAPAD Shale Oil Upgrading Project 2-68 Trade and industry Japan Oil Shale Engineering Company Japanese Retorting Processes 2-86 (JOSECO) Mobil Oil Corporation Mobil Parachute Oil Shale Project 2-82 Occidental Oil Shale, Inc. Cathedral Bluffs Project (C-b) 2-58 Office National de Recherche et Morocco Oil Shale Project 2-2 d'Exploitation Petrolieres (ONAREP) PAMA Inc. Israeli Retorting Development 2-07 Paraho Development Corporation Paraho-Ute Shale Oil Facility 2-63 Peabody Australia Pty. Ltd. Yaamba Project 2-69 Petrobras Petrosix 2-64

2-72 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name

Ramex Synfuels International Ramex Oil Shale Gasification Process 2-64 Raymond Kaiser Engineers, Inc. Paraho-Ute Shale Oil Facility 2-63 Rio Blanco Oil Shale Company Rio Blanco Oil Shale Project (C-a) 2-64 Science Applications, Inc. Morocco Oil Shale Project 2-62 Signal Companies, The Paraho-Ute Shale Oil Facility 2-63 Solv-Ex Corporation Duo-Ex Solvent Extraction Pilot Project 2-66 Southern Pacific Petroleum Condor Project 2-59 Means Oil Shale Project 2-61 Rundle Project 2-65 Yaamba Project 2-69 Standard Oil Company (Indiana) Rio Blanco Oil Shale Project (C-a) 2-64 Standard Oil Company (Ohio) Pacific Project 2-62 Stone & Webster Engineering American Syn-Crude/Indiana Project 2-58 Superior Oil Company Pacific Project 2-62 Tenneco Cathedral Bluffs Project (C-b) 2-58 Texas Eastern Synfuels, Inc. Paraho-Ute Shale Oil Facility 2-63 Tosco Corporation Tosco Sand Wash Project 2-65 Triad Research Inc. Triad Donor Solvent Project 2-69 Union Oil Company of California Parachute Creek Shale Oil Program 2-63 Union of Soviet Socialists Republics Kiviter Process 2-61 U.S. Department of Defense Naval Oil Shale Reserve Development 2-68 U.S. Department of Energy Duo-Ex Solvent Extraction Pilot Project 2-66 Naval Oil Shale Reserve Development 2-68 United Nations Yugoslvania Inclined Modified In Situ Retort 2-70 Veba Get Entwicklungs-Gesellschaft Gelsenkirchen-Scholven Cyclone Retort Project 2-66 Yaamba Joint Venture Yaamba Project 2-69

2-73 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 tfl)4 ir.til PROJECT ACTIVITIES

EaCH CONDITIONALLY APPROVES PHASES 7-10 14.25 sections of land located adjacent to the existing OF THE ESSO COLD LAKE PROJECT six phases and within the CLPP development area. Details of the expansion are as follows: As described on page 3-3 of the March 1986 Pace Synthetic Fuels Report, on December 6, 1985 Esso • 420 wells will be directionally drilled in Resources Canada Limited applied to the Alberta 21 clusters each of 20 wells on 1.6 hectare Energy Resources Conservation Board (ERCB) for ap- spacing, and 160 wells in 4 clusters each of proval of Phases 7 through 10 of its Cold Lake Project. 40 wells, to evaluate the potential for improved On July 16, 1986 the ERCB issued Decision D86-6 ap- efficiency using 0.9 hectare spacing. proving the application, with a 3 year lapse clause. The Decision provides the following information regarding • The production of 6,000 cubic meters per day of the ERCB's analyses of Phases 7 through 10. bitumen will be maintained over the project life by drilling about 80 additional wells per year In September 1983 the ERCB approved the phased within the Phases 7 through 10 area. development of the Cold Lake Production Project • Central plant facilities will be constructed ad- (CLPP) and the eventual production of up to jacent to the facilities for Phases 3 and 4. 25,400 cubic meters per day of crude bitumen from the development area shown in Figure 1. By using modular • Total fresh make-up water requirements during phases of 1,500 cubic meters per phase, the project is steady-state operating conditions will be met to be fully developed in 18 phases. At present, approval within the limits of existing water withdrawal has been granted for the project's first six phases and licenses from Cold Lake and Ethel Lake. the production of up to 9,000 cubic meters per day of • Start-up period requirements for additional vol- crude bitumen. umes of fresh water will be obtained from a groundwater well system on the basis of a Phases 7 to 10 would produce 6,000 cubic meters per permit of a 3.5 year term issued by Alberta day (40,000 barrels per day) of crude bitumen from Environment.

FIGURE I COLD LAKE PROJECT DEVELOPMENT AREA

COLD LAKe •AOouctio,. •OJtCT OSYCLOPUENT A..A = PNA•fl I £ 2 DIUCLOPUINT AflA (I CIA) PHAllI I I 4 OIVILOPUICT ARIA 41 PC$AICS I & I DIVILOPMIMT ARIA (11112 = PHAllI 7 . 1 bIVILOPUENT AflA ChIli

3-1 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 • Additional bitumen transportation diluent re- economic advantage currently exists for natural gas as quirements of 2,800 cubic meters. the fuel source for the project. However, the ERCB also believes that the relative economics of natural gas • Initial on-site construction will require a peak versus coal as the fuel source for oil sands in situ of 800 to 900 workers, production operations operations in Alberta will eventually favor coal over work force to be expanded by 130 permanent natural gas. Hence, the ERCB recommended that jobs, and on-going construction and mainten- government research bodies (including the Alberta ance to generate 160 jobs. Office of Coal Research and Technology (AOCRT), AOSTRA, CANMET, and the private sector initiate The ERCB review of the details of the Phases 7 through coal-use technology demonstration programs with fund- 10 expansion found the development plans to be similar ing assistance. to those of the initial six phases. Changes proposed in the design and operation of the four-phase expansion relate to site-specific geological features of the oil Additional Water Start-Up sands formation and refinements of operating strategies that reflect experience gained from the earlier phases. In its application Esso contended that the overall The ERCB concluded that the program to implement steady-state water requirements of the first 10 phases the next four phases is sound and orderly. However, the of CLPP plus the Leming and May-Ethel experimental ERCB identified the following issues of public interest: pilot projects can be net through a combination of recycled produced water and approved fresh water • Make-up fuel source withdrawals from Cold Lake and Ethel Lake. During steady-state operations, recycled produced water • Additional fresh water make-up volumes re- would, as shown in Figure 2, provide 70 percent of the quired during the start-up period project water requirements. Also, licenses allow a • Property liens maximum withdrawal of 19,725 cubic meters per day (5.2 million gallons per day) of fresh water (17,808 and • General environmental concerns 1,917 cubic meters per day from Cold Lake and Ethel • Project cost/benefit analysis. Lake, respectively). The start-up period of Phases? to 10 would require u to Make-Up Fuel Source 4,000 cubic meters per day of additional fresh water over a 12 month period to supplement existing license In its assessment of alternate make-up fuels for use at limits. For this purpose, Esso has obtained a 3.5 year Phases 7 to 10, Esso re-examined previous anlayses that Temporary Permit for the use of up to 1.4 million cubic it had undertaken in 1978 and 1979 which compared meters of water from a groundwater well system natural gas, coal, and desulfurized gas oil as potential located in SW1/4-22-65-4 W4. fuels for steam generation at the proposed Cold Lake integrated production and upgrading mega-project. In A water supply pipeline from the North Saskatchewan its updated evaluation, Esso looked at the technological River with a holding reservoir near Tucker Lake has and economic aspects of using either natural gas or coal been proposed under Alberta Environment's Long Term specifically for Phases 7 to 10. Water Management Plan for the Cold Lake-Beaver River region. The objective is for the pipeline to be A major technical concern identified was the lack of operational by about 1991. Esso proposes to then industry experience in the design, construction, and change its source of fresh water for Cold Lake opera- operation of large coal-fired steam generators required tions to be consistent with the Plan. Because of this for commercial oil sands projects. Esso felt that the Plan, and because the Temporary Permit requires the only way to alleviate this concern would be to test monitoring of any effects of withdrawal on the aquifer, fluidized bed combustion at a capacity of •about the ERCB believes that Esso's proposed temporary use 350 gigajoules per hour (332 million BTU per hour). of groundwater is within the spirit of careful water use Esso also believes that the time required to resolve planning. potential operating problems and to engineer and construct commercial-scale fluidized bed combustors would delay the start-up of Phases 7 to 10 by at least Property Liens 2 years. A local landowner, Mr. Robert Strayer, filed a submis- From a technical standpoint, Esso concluded that sion with ERCB concerning builders' liens that had been natural gas has advantages over coal for raising steam. incorrectly filed against property surface rights rather From an economic standpoint, Esso projected that the than mineral rights. These liens were filed by subcon- net cost of using coal in place of natural gas for tractors against contractors involved in construction of Phases 7 to 10 would be C$200 million (1985 dollars) CLPP. using a 10 percent real discount rate. Its analysis included the proposed pilot testing of fluidized bed Because the matter of builders' liens is not within their combustors. jurisdiction, the ERCE is not in a position to initiate action to resolve the problem. However, if the present The ERCB reviewed the economic aspects of natural builders' lien legislation is creating problems, the ERCO gas versus coal as alternate fuels for Phases 7 to 10. promised that the matter will be brought to the atten- The ERCB found that the make-up fuel requirements tion of the responsible government authorities. for Phases 7 to 10 are relatively small, and a slight

3-2 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 2 COLD LAKE PROJECT TOTAL WATER BALANCE

70-

60 .5 50- E a CoZ ; 40-

a 7-10 CC i /74 k'd L4CENSED VOLUME 0 (COLD LAKE AND ETHEL LAKE)

0- I I 1986 987 1988 FRESH WATER DEMAND TOTAL WATER DEMAND V-W4 PRODUCED WATER SUPPLY

General Environmental Concerns

Mr. Strayer also experessed concern about the possibi- monitoring network. lity of contamination and injury to waterfowl who may land on lime sludge and landfill containment ponds, The ERCE determined that the environmental impact potential adverse effects on the water quality of Jack- of the first 10 phases of the Ease Cold Lake Phased fish Creek and Borque Lake, and the cumulative effects Project is below that which had previously been found of the combined oil sands development on air quality in acceptable for the integrated mega-project. Also, Faso the general Cold Lake area. Esso advised Mr. Strayer has an on-going environmental monitoring program that pond water contains no oil or hazardous chemicals which ensures compliance with the Clean Air and the and has a salt content less than that of sea water. Esso Clean Water Acts, and a Development and Reclamation also pointed out that oily wastes are stored in concrete Plan. pits that do no attract birds due to the solid nature of wastes. Regarding the proximity of facilities to water bodies, Esso advised that Land Surface Conservation Project Cost/Benefit Analysis Guidelines were used in establishing facility setbacks and additional preventative measures were taken in Esso initially proposed to begin construction of Phases 7 specific cases. to 10 by mid-1986 and scheduled the start-up of steam injection operations for the first quarter of 1988. It In response to air quality concerns Esso submitted that provided a cost/benefit analysis of the project based on total sulfur dioxide emissions from the 10 phases of the an April 1985 forecasts of crude oil and natural gas project would amount to only about 10 percent of that prices. The project was expected to net C$790 million which had been approved for the integrated mega- (1985 dollars), at a 10 percent real discount rate. Be- project. It noted that existing monitoring programs cause international oil prices have fallen dramatically would be continued to ensure compliance with air following the December 1985 application, Esso now quality standards. Also, Esso mentioned that discus- plans to limit activity to detailed engineering design sions had been initiated with other industries in the during 1986 and delay the start of construction by at Cold Lake region to establish an integrated air quality least one year.

3-3 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The ERCB stated that it is satisfied with the technical Phase I would also include primary development of and environmental merits of the expansion proposal. 14 sections with a maximum of 16 wells per section on However, it also believes that orderly and efficient 16 hectare (40 acre) spacing. The arrangement and development of the oil sands cannot be assured without spacing of primary wells would allow their use in future firm commitments to timely development by project thermal recovery operations. sponsors. Therefore, the ERCB decided that it is desirable to grant approval for Phases? to 10, but also PanCanadian expects Phase I recovery to average to introduce a lapse date in the approval for those 3,145 barrels per day of bitumen, with peak production phases. Thus, the approval includes a lapse period of at 4,403 barrels per day. Tentative plans call for about 3 years (up to December 31, 1989) after which Phase II operations starting up in 1990 with production the approval of phases? to 10 will be cancelled if to increase to 6,290 barrels per day by 1991. Phase Ill project construction has not commenced or the opera- would go into operation in 1992, and 300 new wells tor has not received approval to extend the date on the would be drilled on six sections. Production would basis of evidence respecting circumstances existing at increase to 12,580 barrels per day. that time. Phases It and Ill would be developed as thermal recovery projects. After cyclic steaming, the patterns would be converted to steamfloods or firefloods. All wells in these phases would be directionally drilled. PANCANADIAN'S LINDBERGH STEAM PROJECT MAY CONTINUE ON REDUCED SCHEDULE At this stage, PanCanadian feels that it will use steamflood in the thicker sands and a fireflood in the thinner PanCanadian Petroleum Ltd. applied early this year to sands. Both will use inverted seven-spot patterns on a the Alberta Energy Resources Conservation Board four hectare spacing unit. At the end of the project the (ERCB) for approval of Phase I of a proposed 3 phase company will have more than 600 development wells in commercial bitumen recovery project. The ERCB sche- the region. duled a public hearing for June, but since no interven- tions were filed no hearing was necessary. Approval by Although the schedule is likely to be reduced from that the ERCB is therefore expected. originally proposed to the ERCB early this year, the company indicates that it plans to keep the project The Phase I process, costing C$90 million, would alive. Overall, PanCanadian has reduced its capital involve development of primary and thermal recovery spending in 1986 to $235 million from $426 million in operations in the Elk Point, Frog Lake area of the 1985. Lindbergh Field in east-central Alberta. Many years ago, when the Canadian Pacific Railways Phase! operations would include 113 wells already built the country's first transcontinental rail line, it was drilled. Some of these existing wells would be used for given the rights to "all mines, minerals, coal, and primary production and eventually converted to thermal petroleum on lands that were within striking distance of operations as primary production declines. the railway."

Several other existing wells in the proposed project Consequently, its resource subsidiary PanCanadian area were drilled for pilot projects that PanCanadian Petroleum Limited, inherited an enormous amount of plans to continue. prime oil sands land in Western Canada, particularly in the Lindbergh Elk Point and Frog Lake areas. From its PanCanadian began experimental development at Lind- parent, PanCanadian received 100 percent working in- bergh in 1983 with a one well cyclic steam pilot terest in 55 net sections of land. The company also expected to recover 300,000 barrels of bitumen. In bought another eight sections of crown acreage, plus a 1984 the company began a 10 well project using steam 50 percent working interest in 17 more sections. The and carbon dioxide together. Three wells received company feels that it can invest in oil sands develop- steam, three received carbon dioxide, and four wells ment on a long-term basis. alternated carbon dioxide and steam. Late last year PanCanadian received approval for a 15 well cyclic steam project.

An additional 165 Phase I wells would be drilled over the project's 20 years life Of the 165 new wells, 84 DOME PETROLEUM PUTS LINDBERGH AND would be deviated with the remainder drilled vertically. PRIMROSE PROJECTS ON HOLD

PanCaaadian requested permission to develop two sec- During 1985 Dome Petroleum Limited announced two tions for steam stimulation of the Cummings sand new commercial oil sands projects in Alberta, Canada. formation. The wells would be drilled in a seven-spot The Lindbergh Commercial Project was to produce pattern on 4 hectare (10 acre) spacing. No more than approximately 12,000 barrels per day (15,000 barrels 60 wells would be drilled per section. Twelve deviated per day total including pilot projects in the same area) wells would be drilled from each drilling pad. PanCana- by 1989. Estimated capital cost of the project is dian expects to develop one-quarter section every two C$158 million. The Primrose Lake Project was to years. produce 25,000 barrels per day in 5,000 barrels per day stages over a five year period. Capital cost of the

3-4 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 project is C$1.2 billion, with annual operating costs of 430 feet. Two production stations have been estab- C$140 milion. Plans for both projects were approved by lished, one for each of two oil-bearing layers. Facili- the Alberta Energy Resources Conservation Board. ties to collect the oil and pump it to surface are (Refer to page 3-1 of the March 1986 issue of the Pace included in these production stations. Conventional Synthetic Fuels Report for a description of the Lind- surface production facilities including a heater treater, bergh Project, and to page 3-1 of the December 1985 tanks for storage of the oil, a service building, and a issue for the Primrose Lake Project.) mine shaft house are in place. In June both projects were put on hold by Dome due to A total of 120,000 feet of horizontal drilling is being the dramatic decline in oil prices that has occurred carried out to develop production from the two oil since the beginning of 1986. At the Lindbergh Project, layers. In this project oil is expected to flow freely drilling on the first phase was halted after 31 wells along the paths provided by the holes. were completed. These wells have been placed on primary production. Steaming, gathering, and pro- Production rate is expected to be on the order of cessing equipment was committed prior to the oil price 600 barrels daily. Satisfactory results from Unit A decline, and is being stored for use when the oil price could lead to follow-up development of a second pro- recovers. duction facility based around a second shaft on Unit B. This will be located in the same Sarnia-London Road With regard to the Primrose Lake Project, Dome has Field approximately 1 kilometer northwest of Unit A. postponed the proposed 1986 drilling program completely. The project will be re-activated when oil prices Development of Unit A is being financed by Devran and return to levels that make it economically viable. Shell Canada. Devran received a $450,000 grant from the Federal Ministry of Energy, Mines and Resources and a $100,000 grant from the Ontario Provincial government. Financing is also facilitated by the qualification of this project under federal government tax incentives encouraging investment in Canadian petro-- DEVRAN/SHELIJ PROJECT RECEIVES leum exploration. GOVERN MENT AID The Devran method of extracting oil from the ground Devran Petroleum Ltd. and Shell Canada Limited are has its roots in the work of Leo Ranney, a petroleum proceeding with a $6.3 million project to recover 2 mil- engineer born in Iowa who moved to Petrolia, Ontario in lion barrels of oil from a long-dormant oil field near the 1930. More recently, a Southwestern Ontario oil pro- - Southern tip of Ontario. The mining assisted oil recov- ducer, Charles Fairbank, Jr., revived Mr. Ranney's ideas ery project could have a significant long-term impact and technology. Mr. Fairbank is a step-grandson of the on the oil industry. inventor. Devran Petroleum operates the project which is located About 50 years ago, Leo Ranney pioneered and patented near Sarnia, Ontario. This is the heart of one of the an oil drilling process involving horizontal drilling historic areas in the modern oil industry and near major rather than the standard vertical recovery methods. oil markets, including the petrochemical center of His ideas were developed during World War II when the Sarnia. United States was concerned about oil supplies. The procedure developed and now being applied involves Devran Petroleum and Shell Canada jointly lease appro- three major steps. ximately 3,900 acres with 1,200 acres in the active field. Known as the Sarnia-London Road Field, the area • A mine shaft is sunk to the oil layer. was drilled by Imperial Oil from 1898 to 1901. Pub- lished records indicate at least 155 wells were drilled of A production station is excavated at the point which 68 have been verified. All are now abandoned where the shaft passes through or reaches the and the area returned to farmland. oil layers (the pay zone). • The production station becomes the site from Production rates from individual wells of two or three which holes are drilled horizontally in a radial barrels of oil per day were recorded, with some wells or "wagon wheel" pattern into the rocks holding reported to have initial producton rates of over 10 bar- the oil. rels per day. The Sarnia-London Road Field produced Each production station with its set of wells drains by for 25 years, yielding a significant amount of natural gravity several hundred acres. The oil flows through gas with the oil. the horizontal holes to be collected underground and then pumped to surface for treatment, storage, and In 1982 to 1984, Devran acquired the leases and drilled transport to refineries. The length of these horizontal seven exploratory wells from surface to verify the size wells is determined by the formation geometry and and configuration of the field and the amount of oil geological conditions. remaining in place prior to planning the program to develop new production. The Ranney technology was used for commercial pro- - duction beginning in 1946, in Pennsylvania, and con- Unit A is the first production project. This facility is tinued until the early 1960s at which time the operation designed to produce oil from an area of about was no longer economic at the then prevailing oil 600 acres. A shaft has been sunk to a depth of prices.

3-5 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Lambton County oil fields, where the project is sited, In August 1984, NTO began to rehabilitate the decline have been producing for more than 100 years. The area which was beginning to cave. The first 150 feet was around the appropriately named communities of Petro- removed and replaced with steel arches and lagging. At ha and Oil Springs lays claim to being the birthplace of approximately 450 feet, a crosscut was driven to the modern oil industry. The first North American oil 30 feet and a steeper decline driven to a point 15 feet well was put down in the area in 1857. This was ahead below the productive Middle Lakota. Two production of the more famous drilling in Pennsylvania in 1859. tunnels 400 feet and 500 feet long were driven north and south on strike. Drill stations were cut at 100 foot The Petrolia field is the largest in Ontario. With more intervals along the tunnels. than 200 million barrels of oil in the rock, it is a world- class field, but over the last century, fewer than New Tech Oil's original concept for Tisdale was to drill 25 million barrels have been removed. Shallowness and vertical and inclined wells from the drill stations. large volumes of reserves characterize the field. Using this concept, wells were to range in length from 50 to 300 feet. After drilling about 14,000 feet of hole under this concept, NTO was not satisfied with oil production NEW TECH OIL REPORTS FAVORABLE rates and felt it was the result of not having clean well PROGRESS WITH OIL MINING PROJECT bores. They concluded that longer wells in the Lakota sand would be more productive and cost effective. New Tech Oil Company of Kaycee, Wyoming reported in July that the status is "excellent" for its oil mining In September 1985, a new drill station was cut at the project. The North Tisdale Project is located on end and above the south drift. To cut the station NTO Tisdale Mountain in Johnson County near Kaycee, Wyo- ramped up into the lower Lakota and cut a 30 feet ming. New Tech Oil Company (NTO), was formed six diameter drill room. They then installed an electric years ago to develop oil mining technology. power Longyear 38 drill. As of July this unit had drilled approximately 12,000 feet of well bore. The first and NTO acquired the Lakota rights to the North Tisdale most serious problem encountered with this drill was field in 1984. This field has been operated by Conoco that of bit cost and penetration rate. The first bits Inc. as an oil mining research facility from 1978 to used gave a bit cost of $3.18 to $3.85 per foot. 1981. The project had a decline slope and also a vertical shaft. From each location six horizontal wells A bit which Huddy Hudrrycan designed especially for were drilled. At the time NTO took possession of the the project is now delivering bit costs of only $0.15 per property in July 1984 production was approximately foot of hole. 15 barrels of oil per day from each location. Due to the abrasiveness of the sand, the cost of drill The North Tisdale Field is located approximately steel is also at approximately $0.15 per foot. 70 miles north of Casper, Wyoming in the Powder River Basin. The conventional discovery well, drilled in 1953, The above costs indicate that drilling costs for long had an initial production rate of 24 barrels of oil per horizontal wells can be insignificant if the reservoir is thy at a depth of 210 feet. Typical of gravity drainage, such that a reasonable production rate can be achieved. conventional oil wells will exhibit low initial producing At this time, NTO expects an initial production rate of rates with a long producing life. A total of six 45 barrels of oil per thy from a 1,500 foot well with a producing wells was drilled from 1953 to 1962. The six decline to 25 barrels of oil per day after the first conventional wells had an average initial production month. Because of low initial pressure in the reservoir, rate of 8 barrels of oil per thy, and because of the low decline after the first month is very small. production rates, a water flood was attempted in 1961. The water produced only a slight response in the New Tech Oil now projects a development cost of less offsetting wells and it was stopped a short time later. than $2 per barrel of recoverable reserve. They feel By 1972 all but three of the Lakota wells were plugged. the concept and the project to be a success and are now planning additional projects in and outside the United In the mid-1970s, Conoco began a project to experiment States. with mining techniques to gain access to the Lakota sandstone and drill long horizontal drain wells into the reservoir. A decline, 985 feet in length, was driven and six drainage wells were drilled for a combined length of approximately 6,000 feet. PHASE 2 DESIGN OF WOLF LAKE Upon completion of the decline, Conoco sank a 14 foot SET AT 13,000 BPD diameter shaft approximately one mile south of the adit. The depth of the shaft was 235 feet. Six The Wolf Lake oil sands project is a joint venture of BP horizontal drainage wells were drilled from a room Canada and Petro-Canada. The first phase of the mined at the base of the shaft. Total footage drilled project started up in April 1985, and the design capacity from this location was also approximately 6,000 feet. of 1,000 barrels per day was achieved in the third Initial production from the decline and shaft was about quarter 1985. The article on page 3-2 of the December 100 barrels of oil per day each. By July 1981 produc- 1985 Pace Synthetic Fuels Report describes the tion quickly declined to about 12 barrels of oil per day sponsors' tentative plans for the Phase 2 expansion of each. the project.

3-6 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 When the proposed expansion was announced, the size bitumen from one of the tailings ponds and deliver it to of Phase 2 had not been determined. BP Canada and the extraction plant will improve production and reduce Petro-Canada subsequently decided that Phase 2 of the costs. Wolf Lake project will have a design production capacity of 2,000 cubic meters per day (13,000 barrels In addition to internal cost reductions, Suncor is bene- per day) over its 25 year life. It will require 336 wells fitting from declines in the prices of equipment, sup- to be drilled initially, located on 21 satellites. On plies and services. During the inflationary 1970s, key average, 32 additional wells will be drilled each year. items like drilling underwent rapid cost increases. The total number of wells to be drilled over the These increases are being rolled back under the pres- project's life will be 1,072. sure of lower oil prices. A decision on whether to proceed with construction of Phase 2 will be made before the end of 1986. #11 It#

ERCB PUBLISHES STATISTICAL HISTORY OF OIL SANDS PRODUCTION

The Alberta Energy Resources Conservation Board SUNCOR ACHIEVES NEW MONTHLY PRODUCTION published in May 1986 a statistical summary of the RECORDS Syncrude Canada Ltd. and Suncor Inc. oil sands production history. The publication belongs to the Suncor's oil sands plant attained daily average produc- Annual Statistical Series ERCB ST 86-43. tion of 7,890 cubic meters (49,648 barrels) in the first quarter 1986, up 36 percent from the comparable period Numerous production statistics are monitored. Some of of 1985 (Table 1). The increase was largely due to the highlights are given in Table 1. improved production reliability and milder weather than in the first quarter of 1985. In March, the plant (Table I S.e next pig..) established new monthly records for oil sands mining, bitumen extraction and distillate produced.

TABLE 1 DIATOMACEOUS EARTH PROJECT PUT ON SUNCOR FIRST QUARTER RESULTS STANDBY BY TEXACO Texaco has placed its Diatomite Project, located at Three Months Ended March 31 1985 1986 McKittriek in California's Kern County, in a standby condition. The Project will be reactivated when condi- Production-Synthetic Crude Oil(a) 5.8 7.9 tions in the industry dictate. Texaco stressed that the Project is not being abandoned, but is being put on hold Average Revenue-Synthetic Crude(b) 258 152 due to the current worldwide energy supply picture. Gross Production-Conventional Crude 2.4 2.2 The Lurgi pilot unit is being maintained in condition for Oil and Natural Gas Liquids(a) future Operations. Gross Natural Gas Sales(c) 1.9 1.8 Texaco estimates that the Project could yield in excess Refined Product Sales(a) 10.9 9.3 of 300 million barrels of 21° to 23 0API oil from the oil- bearing diatomite deposits which lie at depths up to (a) Thousand Cubic Metres Per Day 1,200 feet. The deposits will be recovered by open pit (b) Dollars Per Cubic Metre mining and back filling techniques. (c) Million Cubic Metres Per Day

Efforts are being made by management to conserve cash including reductions in capital spending and operating costs. Several hundred positions are being eliminated through early retirement and other voluntary programs, relocations, and terminations.

Significant measures are being taken to bring costs down. Staff reductions and other savings at the oil sands plant should reduce total cash costs by the end of 1986. Construction of facilities to recover low-cost

3-7 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1

OIL SANDS PRODUCTION HISTORY

1967- Product Units 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 Suncor Inc. Bitumen 106 m 3 28.2 3.4 3.6 3.3 3.9 2.5 2.9 3.8 3.6 3.1 Synthetic Oil 106 m 3 20.7 2.6 2.6 2.4 2.8 1.5 1.0 2.3 2.8 2.2 Distillate 106 in 3 21.3 2.8 2.9 2.7 3.0 1.9 2.1 2.9 2.9 2.6 Coke 106 tonnes 5.6 0.75 0.86 0.76 0.84 0.56 0.69 0.87 0.85 0.75 Sulfur 103 tonnes 654 98 99 94 104 64 57 95 108 88 Ore Sand 106 tonnes 262 32 31 29 33 23 27 36 36 30 Ore Grade Percent 12.2 12.8 12.3 12.8 12.4 12.4 11.9 11.5 12.0 Syncrude Canada Ltd. Bitumen 106 in 3 1.1 4.1 6.3 6.2 6.5 8.0 6.1 9.3 Synthetic Oil 106 in 3 0.6 2.9 4.7 4.7 5.0 6.3 5.0 7.4 Distillate 106 m 3 0.8 3.1 5.2 4.8 5.2 6.4 5.0 7.3 Coke 106 tonnes 0.1 0.36 0.65 0.62 0.65 0.77 0.60 0.89 Sulfur 103 tonnes 19 119 183 183 201 247 198 304 Ore Sand 106 tonnes 16 50 66 67 68 86 64 97 Ore Grade Percent 10.0 10.3 11.1 11.1 10.9 10.7 11.0 10.8

# ###

3-8 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 CORPORATIONS

UNIVERSAL ENERGY/OHS CORPORATION TEST ELECTROMAGNETIC STIMULATION Another field trial is planned in Brazil this year. OHS announced that an agreement has been reached with Universal Energy Corporation of Tulsa, Oklahoma an- Petrobras S/A, the Brazilian state oil company, to flounced in June an agreement with private investors install and test the OHS process. These operations will which will provide funding for Universal to reduce and be carried out by OHS in a joint venture with the firm restructure its debt. Shareholders have voted to change Azevedo and Travassos S/A of Sao Paulo. Azevedo and the company's name to Oil Recovery Systems (OHS) Travassos is an engineering, construction, and well Corporation. drilling company. The test will be conducted in the Potiguar Basin, which extends through the states of Universal Energy sponsored research and development Ceara and Rio Grande do Norte, and contains several at Illinois Institute of Technology on a single-wellbore oil fields with in-place reserves estimated by Petrobras electromagnetic stimulation technique for heavy oil. to be 4.4 billion barrels. Significant commercial The technique uses the well casing to induce an electro- development of these fields began less than 10 years magnetic field in the oil-bearing formation. Both radio ago. According to OHS, a high proportion of the heavy frequency and 60 cycle electric voltage are used. The oil in the Basin seems to exist at reservoir conditions radio frequency waves penetrate deeply into the forma- particularly suitable to electromagnetic stimulation, tion while the 60 cycle current creates resistive heat- but not amenable to other more orthodox methods such ing. as cyclic steam injection. The first field test of the process was completed last The OHS Development Corporation, subsidiary of Uni- summer. The first commercial well, producing about versal has tentatively reached agreement with Tenneco 20 barrels per thy, was put into production last Decem- Oil Company for a 260 acre farmout in the White Wolf ber in Texas, on property owned by Coastal Oil and Gas field, 25 miles south of Bakersfield, California. There Corporation. is an estimated 28 million barrels of 140 to 16° gravity oil in place in the farmout acreage. An attempt at Universal stated that permits have been received and cyclic steam stimulation in the field in the 1960s was stimulation started in a recently completed well in the an economic failure. As of December 1985, seven wells Lloydminster area in Alberta, Canada. This well was were on production, making 45 barrels per day. drilled gn Husky Oil Operations Limited acreage in the Wildmere Field. Primary production commenced on A test well is also being re-started in Tulsa County, March 16, 1986 and continued for about 60 days, during Oklahoma. which the well produced about 6 barrels per day of ll°API heavy oil. The well was then shut down to allow Universal Energy believes that total lifting costs using installation of the OHS electromagnetic stimulation its technology could be as low as $3 per barrel. unit. After power was turned on and pumping resumed on June 10, a sustained production of 20 barrels per day was achieved over the following 30 days. According to OHS, the productivity of the well is expected to increase somewhat more as the stimulation operations proceed. The economic parameters of the operation are said to be within the range expected. Additional developmental wells are expected in the near future at four separate fields in Alberta and Saskatchewan.

3-9 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 GOVERNMENT

BAUER LIKENS $10 OIL TO TROJAN HORSE FOR ENHANCED OIL RECOVERY

Remarks by D. L. Bauer, Acting Assistant Secretary for Fossil Energy, United States Department of Energy, at The message seems clear. . .whether oil is selling at $10 per barrel or $30: the future of the petroleum industry the Fifth Symposium on Enhanced Oil Recovery in Tulsa, Oklahoma April 21, 1986 focused on the future in the United States rests as much on overcoming technological constraints as on maintaining a viable potential of enhanced oil recovery in the United States. free market. He emphasized the importance of enhanced oil recovery (EOR) technology to future generations. . .to generations that will continue to rely on a stable, secure, and Bauer quoted a Department of Energy study on the cost steady flow of oil to maintain economic growth and of advanced energy technologies and their competitive- prosperity. ness once these technologies are ready for the marketplace. The study concludes that EOR offers the lowest The radical drop in energy prices in the first three cost option for the next increment of domestic liquid months of this year—from over $26 per barrel in fuels in the United States. January of this year to prices that at one point dipped below the $10 mark—put energy back on the front It may not be a cheap option nor one that eliminates pages for a while. This fall in oil prices has been a boon the need for all others, but it is based on a known to many oil consuming nations—in essence, a $400 bil- resource base. Over two-thirds of the oil discovered in lion tax cut. But the adverse impacts on the oil the United States—more than 300 billion barrels till industry are still untotalled. exists as a potential target for EOR technologies.

As Bauer put it, there is no doubt that, unless we are The study states that given the right investment clim- clearly conscious of the two faces of this precipitous ate, more than 14 billion barrels—the equivalent of drop in oil prices. . .unless we balance good economic about one-half current recoverable reserves—could be fortune today with the potential for reduced energy added to the domestic crude oil supply using current security tomorrow . . .we face a situation quite akin to EOR technology. The National Petroleum Council has those unknowing citizens of Troy three thousand years projected that future advances in technology could ago who opened their gates to that famous wooden more than double that amount. horse and then paid the consequences. He suggested that we must not be lured into govenrment intervention Bauer points out that even when prices were high—over that, experience tells us, can cause even worse pro- $30 per barrel—and in spite of a substantial investment blems. But we must use the tools available to us—the in lab and field work, EOR production has been limited. tools of common sense—to bring stability back to the At its peak it has accounted for only 6 percent of marketplace. United States oil production. . .just over 500,000 barrels per day. Virtually all of the EOR production to date In Bauer's view, new, advanced technologies—in all has come from uniquely favorable geology. . .thick pay zones with high oil saturation. . .geology that is the energy areas re vital to our future energy security. exception rather than the rule. We must not let today's climate detract from the inevitable role that advanced technologies like EOR must play in our energy future. The true oil wealth of the United States lies in less favorable settings with lower saturations, thinner pay He noted that oil production in the lower 48 states has zones, at greater depths, and with greater geologic decreased by more than one-fourth since 1970 despite diversity. These are the reservoirs that will be vital to many positive incentives, including the 1981 removal of the long-term future of the petroleum industry. the last oil price controls. Prudhoe Bay helped arrest that decline, but that geologic, occurrence is unlikely to Thus, fundamental research—sponsored by both govern- be duplicated. And now even that production giant has ment and industry—must open the door to processes passed its primary production peak and has entered that can be controlled, and performances predicted, in secondary recovery. By 1995, the United States may these non-ideal geological settings. lose another 25 percent of its production capacity due simply to the nature of the resource. Bauer offered as one possible approach the cooperative R&D venture pool that DOE has proposed for FY-87. Yet, the oil industry remains critical to the United The proposal, which has met some resistance in Con- States economic machine. As recently as 1984, United gress, would give industry a greater say in research in return for sharing its cost. The government would States drillers had bored 84 percent of the world's provide $12 million. producing wells and more than three-fourths of the world's new wells. But those wells only produced 16 percent of the world's oil. The average daily production from United States wells is just 15 barrels of oil Par well. The rest of the worl averages 258 barrels per well per day.

3-10 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 INCREASED ALBERTA BITUMEN PRODUCTION productive capacity and the proration plan was essen- RESULTS IN PRORATIONING OF LIGHT tially dormant. Beginning in 1985 the delivery capacity OIL PRODUCTION of the Interprovincial Pipe Line system became inadequate to transport all of the oil destined for Eastern During January to May 1986, shut-in production of light Canada and United States markets and the proration oil in Alberta averaged 109,000 barrels per day. The plan once again was called into service. Figure 1 gives peak month was April with a shut-in of 164,000 barrels a comparison of produtive capacity and demand for per day. Alberta light oil over the last 35 years.

The cause of the shut-in is insufficient pipeline delivery Prorationing only applied to Alberta light oil. Heavy oil capacity. Both the Interprovincial and TransMountain and pentanes plus were excluded in the initial plan systems have been operating at full capacity since because of their unique characteristics. Subsequently, November 1985. The Rangeland system has also been and for similar reasons, synthetic crude oil from oil utilized to its capacity in late spring. sands mining projects and bitumen from oil sands in situ operations were also excluded. Production from other provinces was also not subject to proration. Thus, the The Alberta Proration Plan Alberta light oil pools became the "swing" supply source from Western Canada. In 1950 industry requested the Alberta Energy Re- sources Conservation Board (ERCB) to prorate produc- The relative importance of Alberta light oil has been tion to market demand. The request was made because declining as shown in Figure 2. a series of major oil discoveries had resulted in productive capacity outstripping the capacity of the pipeline The proration plan involves the following procedures: system. Following a public hearing the Board adopted a proration formula and issued the first Market Demand • Purchasers file monthly with the ERCB their Order in December 1950. The formula was changed requirements (nominations) for Alberta oil for significantly in 1964. The plan was reviewed again in the following month 1975. • The ERCB determines the total market demand During most of the 1950s the growth in Alberta light oil and then subtracts the pentanes plus, synthetic productive capacity continued to outpace the expansion oil, heavy oil, and bitumen to determine the in the pipeline delivery system even though the market demand for light oil area increased rapidly. In the 1960s import restrictions imposed by the United States severely limited the • The light oil demand is allocated to pools demand for Alberta oil. according to the proration formula which is based on reserves adjusted for production During the 1970s, restrictions by the National Energy • The pool allocation is distributed to wells ac- Board on exports of oil from Canada had a similar cording to a prescribed formula designed to effect. Those restrictions were lifted in 1983 and protect the equity of all producers in the pool. subsequently demand was reasonably in balance with

FIGURE I RATIO OF ALBERTA PRORATED LIGHT OIL COMPARED TO TOTAL WESTERN CANADIAN SUPPLY 100

a. 40 -

0 I I I II I 1973 74 78 76 77 76 79 4960 81 62 83 84 86 i98•

3-11 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 2 PRODUCTIVE CAPACITY AND PRODUCTION OF LIGHT AND MEDIUM OIL ALBERTA 2000

p. '500

PRODUCTIVE CAPACITY U' 1000 SHUT-IN OIL

PRODUCTION 500 0 z

01947 1950 1960 t970 1980 1985

Because oil is a migratory resource and because recov- The volume of shut-in oil is dependent on three main ery is frequently affected by withdrawal rates, a "pro- factors; productive capacity, demand (primary plus sup- duction control" system is needed even in the absence plemental), and delivery capacity. Unfortunately, each of a proration plan. However, many light pools have factor changes almost every month, which leads to been placed on "good production practice" which means confusion. However, deficient pipeline capacity has that they can produce at the discretion of the operator been increasing in importance. It has been the major subject to certain basic requirements. The production cause of shut-in oil commencing in December 1985. from those pools is not affected by the proration plan. Because Alberta light oil is the "swing" supply source, the capacity of the Interprovincial system to deliver Recent Events Alberta light oil is dependent on production from other areas (Normal Wells, Saskatchewan), and production of In 1984 it became apparent that the delivery capacity other Alberta oils (pentanes plus, synthetic oil, conven- of the Interprovincial Pipe Line system would not be tional heavy oil, and bitumen). The more oil that is adequate to deliver all the oil likely to be tendered to produced from those other supply sources, the less it, and plans were made to increase its capacity. space is available for Alberta oil. During the last two Beginning in 1985 deficiencies began to occur from years there has been a dramatic increase in bitumen time to time and oil had to be shut in. In contrast, production from in situ oil sands operations. That there was unused capacity on the TransMountain system increase has had a much greater impact than just the because previous Canadian oil deliveries to the Puget increase in volumes because of its viscosity effects Sound area of the United States had been displaced by when injected into a line carrying light oil. According oil supplied from Alaska. to the ERCB, the current configuration of the Interpro- vincial system results in each additional barrel of On June 1, 1985 deregulation ended government in- bitumen transported displacing 2 to 3 barrels of Alberta volvement in price setting and the industry returned to light oil. a competitive pricing system. The initial price postings were apparently not attractive to refiners located on Bitumen production has increased as shown in the the periphery of the market area for Alberta oil. following table: During the first few months of price deregulation substantial volumes of Alberta oil were shut-in because Barrels of the reduced demand. In order to permit the purchase Per Day of oil that had been shut-in because of insufficient demand, ERCB implemented the Supplementary Sales May 1984 22,000 plan on October 1, 1985 which allowed sales of shut-in May 1985 46,000 oil at special prices if pipeline capacity were available. May 1986 87,000 The problem of inadequate pipeline capacity increased dramatically in 1986. During most of 1985 the defi- This increase in bitumen production during the last two ciencies were limited to the Interprovincial system. years has been the major cause of the reduction in ability to transport Alberta light oil.

3-12 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENERGY POLICY & FORECASTS

CANADIAN OIL MARKET REVIEW SHOWS year. The more rapid rate of decline in Quebec GROWING INFLUENCE OF HEAVY OIL continues a pattern that has been evident for several AND BITUMEN years. The share of oil in the province's total energy consumption has been dropping faster than the national "The Canadian Oil Market," a June 1986 publication of average, reflecting expansion of both natural gas and the Minister of Supply and Services Canada, sum- electricity as alternative energy sources. marizes the 1985 market year. On an individual product basis, the demand for motor gasoline reflected total product consumption, that is, Canadian Demand no change year-over-year in either the quarter or the total for the year. Demand for diesel remained strong Oil demand in the fourth quarter rose marginally in the fourth quarter, up almost 6 percent from a year (1.6 percent) from the year prior to 223,000 cubic me- earlier, to yield a growth rate of almost 3 percent for ters per day to yield an annual average of 214,000 cubic the year. Demand for turbo fuels for air transport was meters per day, the same level as 1984. On a sea- also up for the year. The relative strength in diesel sonally adjusted basis, the minor decline recorded in the fuel sales appears to reflect higher levels of industrial third quarter represented a small deviation from the activity but gasoline consumption continues to reflect slow but steady rate of growth since the historical low the improvement in total fleet fuel consumption as point in the fourth quarter of 1984 (Figure 1). older models are replaced by more efficient new auto- mobiles. On a regional basis, only British Columbia had a decline in demand (-2.8 percent) in the fourth quarter, and On a seasonally adjusted basis, the consumption of Quebec consumption remained flat on a year-over-year heavy fuel oil rebounded sharply, reflecting lower basis. Consumption in the Prairie and Atlantic regions prices in world markets following the end of the British both rose by 2 percent and Ontario's increased by coal miners' strike. Light fuel oil consumption re- almost 4 percent in the fourth quarter. mained relatively stable, even though average temperatures in Canada east of the Prairies, where most of For the year as a whole, the Atlantic region and British the home heating oil is consumed, were about 10 per- Columbia exhibited no change from 1984. Although cent colder than during the fourth quarter of 1984. consumption in Ontario and the Prairies rose by 2.1 per- Continuing trends to alternative fuels, more energy- cent and 3.5 percent, respectively, in Quebec it con- efficient furnaces, and improved insulation levels have tinued to decline, down by almost 6 percent over the all contributed to this lack of movement.

3-13 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Crude Oil Requirements for about three quarters of the gain. On a year-over- year basis heavy crude oil producibility rose almost Total crude oil received at Canadian refineries during 18 percent to 58,000 cubic meters per day mostly be- the fourth quarter of 1985 rose by 3.4 percent over the cause of the start-up and expansion of several bitumen same period a year earlier, to 230,000 cubic meters per day. and conventional heavy crude oil recovery projects (Figure 2). Many of the projects, which use in situ oil The pattern experienced during the previous two quar- recovery techniques, are located near the Saskatche- ters, when deregulation began, persisted; Canadian wan-Alberta border in the Cold Lake and Lloydminster crude oil, which had been used in eastern Canada the areas. Accelerated expansion of Esso Resources previous year, was displaced by foreign crude oil. Canada Limited's Cold Lake project contributed significantly to the increase in heavy crude oil producibility Canadian crude oil received at refineries dropped by during the second half of 1985. 5.5 percent from the previous year. Imported crude oil receipts rose 52 percent during the In contrast to growth in heavy crude oil producibility, fourth quarter to 52,000 cubic meters per day, yielding for the first time in several years conventional light oil an annual average of 47,000 cubic meters per day. As a producibility fell, by more than 1 percent, to result, imported crude oil represented almost 23 per- 167,000 cubic meters per day in the fourth quarter of cent of total crude oil received during the quarter, 1985 from the fourth quarter of 1984. For the entire pushing the annual share of imports to 19 percent. year, however, conventional light oil producibility grew Refined product imports, however, dropped almost marginally, by 2 percent. Since early 1985, producibi- 40 percent, reflecting the high spot prices paid offshore lity in Alberta, where more than 85 percent of during the fourth quarter. Canadian light crude oil production originates, has been falling with the natural decline of the reservoirs and the lack of significant new discoveries. Similarly, product exports rose sharply (74 percent) during the quarter to 23,000 cubic meters per day because of the opportunities created by the higher Throughout the fourth quarter, and for the entire year, prices in foreign markets and the need to dispose of both synthetic oil plants operated without major pro- product imbalances. blems. Production rose by over 5,000 cubic meters per day to 27,000 cubic meters per day during the period, yielding an annual average of 26,000 cubic meters per Producibility day for 1985. During most of 1985 the plants ran at more than 95 percent of estimated sustainable capaci- In the fourth quarter total capacity to produce crude oil ties (which accounts for maintenance time). and equivalent (producibility) rose by more than 7 percent, to almost 270,000 cubic meters per day, from the fourth quarter of 1984, and heavy crude oil accounted

3-14 SYNTHETIC FUELS REPORT, SEPTEMBER 1996 The availability of condensate continued to rise through the fourth quarter, and for the year was up about 9 percent, to almost 17,000 cubic meters per day. This increase was due to higher natural gas production. Thus, total producibility, in the fourth quarter was up almost 6.1 percent despite a drop in conventional light crude oil producibility. For the longer term, this phenomenon raises a dilemma for Canadian oil supply requirements: the producibility of light crude oil and equivalent may have peaked while heavy crude oil producibility continues to rise. Canadian refineries, however, are equipped to refined only limited amounts of heavy crude oil.

Production and Shut-in Total production in the fourth quarter was up by almost 4.3 percent from the same period a year earlier. The bulk of the increase was attributed to heavy crude oil, up 24 percent from the previous year, whereas light crude oil production fell. In both cases, production could have been somewhat higher except for pipeline capacity problems experienced in December. Although the capacity of the Interprovincial Pipe Line system had been expanded by almost 12,000 cubic meters per day at the beginning of the fourth quarter, this additional space was fully utilized by December.

Shut-in averaged more than 7,000 cubic meters per day In the fourth quarter, of which less than 1,000 was heavy crude oil. Because of the expense and difficulty associated with shut-in heavy crude oil production capacity, the industry had agreed that heavy crude oil should have a priority on available pipeline space. As capacity limits are pushed more frequently, some companies have questioned this practice.

Exports and Imports

The pattern of exports and Imports since deregulation continued during the fourth quarter of 1985, when crude oil exports increased faster (18 percent) than imports (11 percent), (Figure 3). During the fourth quarter, however, most of the increase in crude oil exports was In heavy crude oil, reflecting higher output from bitumen projects and the traditional seasonal reduction in domestic requirements for asphalt manufacture.

3-15 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ECONOMICS

ECONOMICS OF BEAVER-HEaTER EXTRACTION The type of contacting scheme may also be site- PROCESS REVEALED specific. Because of a high clay content, the contacting scheme for a planned demonstration plant at a The Herter process is a surface-mined solvent extrac- southern Oklahoma tar sand site will be a multistage, tion process which utilizes fatty acids as the solvent stirred contactor with a primary settler recycle stream (see Pace Synthetic Fuels Report, December 1985, involving agglomerating agents. page 3-24). The uniqueness of the Herter process is that it provides a low energy method of separating the After contacting and separation from the sand, the fatty acids from the recovered oil for subsequent solvated bitumen mixture containing fatty acids is recycling. The heart of this separation process is the saponified by reacting with an aqueous base which basic saponification (soap making) and desaponification causes the solvated mixture to separate into a hydro- reactions. The recovery and recycle of the fatty acid carbon phase and an aqueous acid soap phase. The solvent is the key to the process. The Herter process phases are then separated in a settler. The aqueous recovers the fatty acid by saponification, followed by soap phase is next sent to a desaponification reactor for migration of the soap to the aqueous phase, and then regeneration and recycle. desaponification of the resulting soap phase again followed by phase separation. The formation of a hydro- The desaponification reaction reacts the soap product carbon-soap-water emulsion limits the process unless at high pressure with carbonic acid or at low pressure carefully controlled by the addition of an alcohol cosol- with some other acid to reconstitute the fatty acid. vent. Addition of the short-chain alcohol limits emulsi- Since the fatty acid is immiscible in water, it may be fication and allows a meaningful separation to be phase separated and recycled back to the initial solvat- accomplished. The modified process is known as the ing step. Some solid or dissolved salts will be produced Beaver-Herter process. as by-product depending on the type of base used.

Process development work is being sponsored by Diver- The inherent economic advantage of the Herter process sified Petroleum Recovery, Inc. (DPR) of Little Rock, is the low energy separation process that occurs in the Arkansas. A benchscale model of the process has saponification and desaponification reactions. recently been completed as part of the research sponsored by DPR. The benchscale model, located at the In order to eliminate the formation of emulsions that Engineering Experimental Station in Fayetteville, has prevent phase separation a cosolvent such as a short- demonstrated the technical feasibility of the process. chain alcohol must be introduced to control micelle formation. DPR has designed a computer model to evaluate the economic feasibility of the process on a site specific A preliminary plant layout for the Beaver-Herter pro- basis. The key to the economic advantage of the cess is shown in Figure 1. The process is not capital process, as explained by R. E. Babcock of the Univers- intensive. Major equipment components for the chemi- ity of Arkansas is said to be its simplicity, as compared cal part of the process consist of saponification and to the present state-of-the-art. Most solvent and desaponification reactors, settling tanks, storage tanks, steam recovery processes require large capital invest- and a distillation column. These equipment compo- ments and substantial energy input in order to recover nents, exclusive of the storage tanks and the feed the heavy crude or tar sands. As a result, these preparation equipment, can be mounted on an 8 foot by processes may not be economically feasible at today's 40 foot trailer for the proposed 700 tons per day de- oil prices. The Herter process, in contrast, requires monstration plant. only a relatively small capital investment and very little energy input. This provides a secondary advantage of being economically feasible at a smaller scale. Site Selection Thus, much smaller deposits can be exploited. In reviewing potential sites for the demonstration plant, deposits in Oklahoma exhibited a number of favorable Process Description factors. Oklahoma has numerous small deposits which were mined for paving materials decades ago, but were Fatty acid is brought in contact with a tar sand source, abandoned when modern refineries entered the asphalt in a surface contactor scheme. This produces a sol- business. Thus, it is relatively easy to locate and vated bitumen mixture with reduced viscosity and im- examine these sites. proved mobility. Fatty acid blends are good bitumen solvents because they can prevent asphaltene precipita- Another advantage is the proximity to refineries and tion in addition to serving as a carrier for the addition other oil field related facilities. Due to the current of light hydrocarbon blending stock. Also, fatty acid economic conditions in the oil industry, local contrac- blends promote bitumen separation from clay fines by tors are readily available, at competitive prices, to serving as a carrier for agglomerating agents and Perform such tasks as mining and transportation. through activity on the clay surface. The particular fatty acid blend can be tailored to the site-specific tar A few of the deposits of interest are within an area sand resource. Recoveries in the range of 85 to designated as containing glass quality sand, thus provid- 90 percent are obtainable in a single stage contactor. ing the possibility of a secondary product for sale.

3-16 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 PLANT LAYOUT - SOUTHERN OKLAHOMA DEMONSTRATION PROJECT

Water Source

4 Send

4= Make-U Water

6 Caustic 15.000 gal. Product 6 200 bbl

Alcohol 500 Product ® 200 bbl P

a Salt Water HCI 16.000 gal. DIsposal

LEGEND

1 Feed Hopper 6 Sa ponification Reactor 10 Control Room p 2 Auger 8 Sa onification Settler II Generator 3 Countercurrent 7 Deaaponlflcatlon Reactor 0 8'x40' Trailer Contactor S ClassIfIer S Deeaponlftcallon Settler 0 Pump 4 Spent Sand Conveyor 9 Distillation Column 0 Valve

A potential site was located which indicated bitumen The key assumptions in the economic model are as content in excess of 11 percent and with good consist- follows: ency. A few tons were extracted from a location near an abandoned quarry and transported to a crushing plant in Arkansas, then to the Engineering Experiment Sta- Initial Project Cost, $ tion in Fayetteville for testing. 600,000 Expansion, $ 400,000 Average Bitumen, % In spite of the currently depressed price of crude oil 11.62 Bitumen Recovery, % 95 and asphalt products, DPR remains optimistic that the Barrels of Oil Per Ton of Tar Sand project will prove to be economically feasible. 0.63 Barrels Of Oil Per Day (Initial) 441 Barrels of Oil Per Day (Expanded) 1,103 Economic Analysis Selling Price of Product, $ 19.25 Production Efficiency (Reflects Down- 90 time of 10%), % DPR has carried out an analysis of the economic Initial Mining Rate, Tons Per Day feasibility of constructing and installing a 700 tons per 700 day demonstration project in southern Oklahoma. Expanded Mining Rate, Tons Per Day 1,750 Mining Cost Per Ton, $ 3.00

3-17 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1 TABLE 2 PROJECT SUMMARY SUMMARY OF EXPENSES

$ Revenue 29,753,234 Landowner Royalty 553,533 Direct Expenses Gross Revenue 29,199,701 Mining 7,356,290 Direct Expense 22,323,084 Chemicals 8,417,615 Indirect Expense 1,246,667 Utilities 5,518,475 Operating Labor 665,685 Total Expenses 23,569,751 Supervisory Labor 99,853 Gross Profit Before Royalty 5,629,949 Maintenance and Repairs 143,750 Patent Royalty 844,492 Operating Supplies 21,562 Laboratory Costs 99,853 Gross Profit to Partnership 4,785,457 Interest Expense 0 Sub-Total 22,323,084 Net Profit Before Tax 4,785,457 Indirect Expenses Non-Cash Deductions 3,389,508 Overhead 545,573 Net Income/(Loss) 1,395,948 Local Taxes 43,125 Taxes Due 939,297 Insurance 21,562 Tax Credits 939,297 Administrative Expense 136,393 Taxes Paid 0 Process Improvement 354,016 Other Expenses 145,998 Net Profit/(Loss) After Tax 1,395,948 Sub-Total 1,246,667 Expansion Capital 400,000 Limited Partners Cash Distribution 3,289,092 Total Expense 23,569,751 General Partners Cash Distribution 1,096,364

The analysis indicates a payback to investors of appro- Regardless of what happens in the near term with ximately two years (before reserve for expansion). Re- respect to prices or tax credits, DPR states that they sults are sumarized in Tables 1 and 2. are confident in the merit of continuing development of the process and in the long term economic feasibility. A key part of the analysis is the Alternate Fuels Production Tax Credit. Initiated as part of the Windfall Profits Tax Act, the credit was designed to provide a floor to the price received by producers developing tar sands resources.

Assuming the current rate of inflation, the credit will RTR DAP PROCESS EXHIBITS LOW average, during the projected 5 years, in excess of OPERATING COSTS $6.00 per barrel produced. The project, at the small scale proposed, will accumulate almost $8 million in tax DAP is a diluent assisted extraction process which was credit while utilizing less than $1 million. conceived by RTR S.A. It was originally developed for the recovery of oil from those tar sands in which the The single most important factor on which the econo- layer of connate water, that is the layer of water mic viability of the demonstration depends is obviously adhering directly to the sand grains, is substantially the same factor which is causing the current crisis in incomplete. Capital and operating costs estimates for the oil industry as a whole, the market price for oil. the process were presented at the Tar Sand Symposium With prices in the mid-$20s for the product, ample held in Jackson, Wyoming in July 1986. margin for error would exist to initiate the project. Should prices stay below the $20 level, economic feasi- As shown in Figure 1, the tar sand, crushed if neces- bility would be marginal. sary, is first fed to the Precondittoner, a rotating drum with an internal helix. Here it is initially heated with condensing steam from the Diluent Recovery Unit, and In spite of the current market conditions, the project then is mixed with a blend of diluent (normally a would likely be economic, if it could be assured that the middle-distillate) and recycle extract. The function of Alternate Fuels Product Tax Credit would not be elimi- the Preeonditioner is to dilute the bitumen matrix and nated by tax reform legislation. therefore to reduce its viscosity and specific gravity.

3-18 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The sand/hydrocarbon pulp from the Preconditioner movements of the sand grains together with the almost passes next to the Displacer where it is mixed with a total absence of fines, which could hinder coalescence, controlled ratio of alkaline water. The mixing action causes the formation of larger drops of extract which causes the progressive displacement of the hydrocarbon rise to the surface of the water layer. The extract- in the interstices between the sand grains by the water. containing fluid stream and the solids-rich pulp are fed This operation is carried out with a minimum of me- to two different sections of a gravity settler, the Sand chanical energy, so that a hydrocarbon-rich fluid and a Cooler, which is similar in design to the Desander. solids-rich pulp are present as two distinct phases Cold make-up water is injected near the bottom of this separated by a layer of water. The Displacer is a settler to scavenge heat from the sand. Extract is horizontal rotating drum with an internal helix, and has recovered at the top of the vessel. The middlings are two separate outlets for the two phases. The hydro- recycled to the Displacer and to the Desander. The carbon-rich stream is first directed to the Oil/Water reject sand is finally dewatered on a belt conveyor. Separator where the bulk of the extract is removed, and The sand is in a damp form and can be disposed of as a then it joins the solids-rich pulp before it reaches the solid. Desander. The Desander is a gravity settling unit with extract removed from the top, settled sand removed Another advantage of the process is that any clay from the bottom and process water ("middlings") re- agglomerates entering the Displacer are coated with moved from an intermediate outlet. The operating extract which protects them from the dispersing action conditions are set to remove the majority of the of alkaline water. This early removal from the process dispersed fines with the process water. For this reason, of a substantial part of the fines also facilitates the a stream of recycle water is added to the bottom of the clarification of the process water for recycle. Recov- vessel to ensure a proper upward water velocity. The eries of hydrocarbons are high and typically are above middlings are then sent to the Water Treatment Section 95 percent. for clarification. The immediate recycle of the process water eliminates The sand leaving the Desander still contains a small the storage of large volumes of hot water in a tailings amount of finely dispersed extract droplets which need pond and, together with the moderate process operating to be coalesced to be recovered. This action is temperatures, renders the process energy efficient. Performed in the Squeezer, another rotating drum with internal helix and two outlets, to which the sand is fed, The process can operate with a wide range of hydrocar- together with a stream of clarified water. The relative bon diluents in the kerosene boiling range or heavier.

3-19 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Process Piloting and Simulation TABLE 2 RTR built a continuous pilot plant in 1980 at Terni, Italy. The pilot plant, which has the capacity of I ton OPERATING COTS per day, operated almost continuously in the period 20,000 BPSD BITUMEN 1981 to 1985 for the processing of tar sands from (United States Thousand Dollars different countries. Experimental campaigns have been First Quarter 1986) carried out on tar sands from Madagascar, and from various locations in North America. The small scale of the pilot plant made necessary the construction of a Manpower 5,438 process simulation apparatus for scale up studies. The Utilities: process simulation equipment consists of a large rotat- Electricity 717 ing vessel (operated batchwise) and a static separator Steam (operated continuously). The critical dimensions of 2,982 Water 32 these two items of equipment are of the same order as Chemicals those foreseen for an industrial plant. NaOH 432 Demulsifier 195 Maintenance 1,128 Capital and Operating Costs Tailings 3,074 Diluent 1,056 Capital and operating costs have been developed for a plant to produce 20,000 barrels per stream day of Total 15,054 bitumen, as diluted bitumen extract, from a typical Athabasca tar sand having an average bitumen content of 12 percent weight and a fines content of about Cost Per Barrel (United States $) 2.69 14 percent weight (on mineral). Table 1 presents a summary of the capital costs for the plant. Recovery of the capital costs of the utilities generation system is included in the prices assumed in compiling Table 2, Summary of Operating Costs. The estimate of operating costs does not include capital recovery or the capital and operating costs for the mine and the general site preparation.

TABLE 1

CAPITAL COST 20,000 BPSD BITUMEN (United States Million Dollars First Quarter 1986)

Equipment: Recovery Section 12.9 Water & Fines Treatment 3.8 Extraction Treatment & Tanks 3.7 Tailings Disposal 6.5 Bulks and Common Systems 14.1 Mobile Equipment 2.1 Process Building and Structure 13.4 Central and Service Buildings 2.7 Feed Surge and Emergency Dump System 3.1 Total 62.3

3-20 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TECHNOLOGY

AIR FORCE PROGRAM TESTS PRODUCTION OF AVIATION TURBINE FUELS FROM UTAH S tIUIItI AND KENTUCKY BITUMENS

Some results have been made available from the United BITUMEN PROPERTIES States Air Force program to determine the costs, yields, physical characteristics and chemical properties of aviation turbine fuels, Grades JP-4 and JP-8, pro- Bitumen Property Kentucky Sunnyside duced from Kentucky and Utah bitumens. API Gravity 9.8 11.9 Specific Gravity, 60/60°F 1.0014 0.9868 The Fuels Branch (AFWAL/POSF) of the Acre Propul- Distillation °F, ASTM D1160 sion Laboratory at Wright-Patterson Air Force Base, Initial Boiling Point 508 214 Ohio awarded contracts to the Ashland Petroleum Com- 5% Recovered 590 449 pany, located in Ashland, Kentucky and to the Applied 10% Recovered 630 505 Research and Development Division (ARD) of Sun Re- 20% Recovered 713 587 fining and Marketing, located in Marcus Hook, Pennsyl- 30% Recovered 801 782 vania to conduct the research. The goal of the program 40% Recovered 898 877 was a commercially viable processing scheme to pro- 50% Recovered - 906 duce high yields of aviation turbine fuel, grades JP-4 Flash Point OF 350 215 and JP-8, with a minimum energy efficiency of 70 per- Pour Point OF 65 90 cent and net production of coke and residual materials Salt, IB/1,000Bbl 400 0.7 of no more than 10 percent. Carbon Residue, % 9.5 17.0 Carbon, % 85.45 84.04 The Air Force selected a pilot-scale produced Kentucky Hydrogen, % 10.56 10.78 bitumen, recovered by Westken Petroleum Company as Oxygen, % 1.18 1.02 part of the Kensyntar program. The bitumen was Sulfur, % 1.49 0.32 recovered via an in situ wet combustion process from Nitrogen: the Big Clifty deposit of Edmonson County, Kentucky. Total, % 0.40 0.79 The Air Force also selected a pilot-scale produced Utah Basic,% 0.21 0.64 bitumen, recovered by the Chevron/GNC joint venture. Ash,% 1.16 1.90 The tar sand was mined from the Sunnyside deposit and Trace Metal, ppm the bitumen recovered via a solvent assisted water Nickel 60 63 flotation process. Bitumen properties are presented in Vanadium 143 14 Table 1. Iron 813 1,600 Copper 63 19 Each contractor investigated a different processing Sodium 541 - scheme. Ashland's approach to processing the Kentucky Hydrocarbon Type, % bitumen (Figure 1) was based on established commercial Saturates 25.7 22.8 processing techniques used at their Cattletsburg, Ken- Aromatics 32.2 25.4 tucky refinery. Significant quantities of salt and Polar Compounds 17.6 27.1 metals were removed prior to processing. The bitumen Asphaltenes 24.5 24.7 was combined with a diluent, Light Cycle Oil (LCO), and salts were removed via a chemical desalting process. The bitumen (with diluent) was demetalized via the Asphalt Residual Treatment Process (ART). The LCO was removed by fractionation and the bitumen products were fractionated into naphtha, gas oil, and charged to the Ashland Reduced Crude Conversion vacuum residue streams. The naphtha and gas oil (RCC) pilot unit. The effluent from the RCC unit was streams were hydrotreated over a commercial nickel- fractionated into four JP-4 and JP-8 precursors, and molybdenum catalyst. The gas oil was hydrocracked hydrotreated over a commerical nickel-molybdenum over a commercial nickel-molybdenum catalyst. The catalyst. The products were caustic washed, clay hydrocracked product was fractionated into a naphtha treated, and redistilled to adjust end point (Figure 2). and a distillate stream. Naphtha and distillate streams were blended into JP-4 and JP-8 aviation turbine fuels Sun chose to process the bitumens using conventional and redistilled to meet boiling range requirements. refining processes (Figure 3). The Kentucky bitumen was mixed with toluèhe and chemically desalted. The toluene was fractionated off prior to downstream pro- Results cessing. The Utah bitumen/solvent mixture was subjected to chemical desalting and the salts and solids The objectives of this program were to determine the removed. The mixture was fractionated to remove the costs, yields, physical characteristics, and chemical hydrocarbon solvent and water that was present. The properties of aviation turbine fuel produced from tar desalted bitumens were charged to a stirred batch sands bitumen. Each contractor investigated three autoclave for hydrovisbreaking. The hydrovisbreaking product slates; a product slate which minimized the

3-21 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 ASHLAND'S APPROACH TO PROCESS KENTUCKY BITUMEN

IBP-330 I 330-430 BITUMEI DESALT ART aisriLi Iii] RCC DISTILL I 130-520 520-600 -

SALT A S LCO

(HYDRa- IBP, 520 I I CAUSTIC I - - 1TREAT P'j WASH '0ISTIiLf__.ø__4 j

IOP-600 IHYORO- _ICAuSTU I I - TREAT i 1 WASH 1DlSTIiL fr JP-8 -_I

cost of JP-4; a slate which maximized the production FIGURE 2 of JP-4; and a product slate which maximized the production of JP-8. ASHLAND'S APPROACH TO The Ashland Reduced Crude Conversion (RCC) process PROCESS UTAH BITUMEN produces naphtha as a primary product. Under current economic conditions, the cost of aviation turbine fuel is IBP-330 lowered as turbine fuel yields are reduced and gasoline 330-430 production increased. A product slate which maximizes the production of JP-4 but does not minimize the cost _ 430-520 SellRCC DISTILL I would have a volumetric yield of 50 to 60 percent. A 520-600 product slate which maximizes the production of JP-8 but does not minimize the cost would have a volumetric yield of 20 to 30 percent. The Sun hydrovisbreaking process produces naphtha and distillate. Naphtha yields can be increased by hydrocracking the distillate. JP-4 yields above 90 percent ISP-520 DISTILL and JP-8 yields above 60 percent are achievable with [TREAT I.._*FT1c good process economics. The processes all produced high quality JP-4 fuels (Table 2). Fuel samples produced by both Ashland and Sun from the Utah bitumen failed to meet the Reid Vapor Pressure specification. The fuel produced by Sun from the Utah bitumen also failed freezepoint. Adjust- ments to the distillation range will be necessary to meet these requirements.

The processes also produced high quality .JP-8 fuels (Table 3). Fuel samples produced by both Ashland and Sun from the Utah bitumen failed to meet the freezepoint requirement. Adjustments to freezepoint were

3-22 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 3 SUN ' S APPROACH TO PROCESS KENTUCKY AND UTAH BITUMENS NAPIITHA ______I BITUMEN I ______SOLVENT [ 0,1 HYDRO- I DISTILL I GAS OIL ______VIS6REAK I I I 0, VACCUWI RESIDUE 'P SOLVENT

NAPWflIk HYDRO- ______TREAT DISTILL JP-4

MSOIL ffi0- IIYDRO- frDISTILL ______JP-8 TREAT Cx 0,

TABLE 2 JP-4 FUEL SAMPLE PROPERTIES Properties MIL-T-56241. Kentucky Kentucky Utah Utah Limit Sun Ashland Sun Ashland Saybolt Color () 30 30 28 27 API Gravity 45.0-57.0 51.6 49.6 50.8 53.2 Density 0.7507-0.801? 0.7728 0.7813 0.7762 0.7664 Reid Vapor Pressure 2.0-3.0 2.0 2.5 1.8 1.2 D2887 Distillation OF Initial Boiling Point • 198 69 208 75 10% Recovered 242 170 257 147 20% Recovered 266 Max 266 215 280 197 50% Recovered 365 Max 325 308 350 287 90% Recovered 482 Max 400 411 420 419 End Point 518 Max 440 483 445 484 Freeze Point, OF (72) Max (76) (90) (62) (78) Copper Strip Corrosion IS Max Is lb la lb Total Acid Number, mgKOH/g 0.015 Max 0.011 0.004 0.010 0.002 Existent Gum, mgflOOmi 7.0 Max 1.0 1.6 1.0 2.0 Net Heat of Combustion, 18,400 Min 18,688 18,540 18,668 18,589 BTU/Lb Sulfur, Wt % 0.40 Max 0.00004 0.008 0.0001 0.001 Hydrogen Content, Wt % 13.6 Min 14.26 14.1 14.25 14.0 FIA Aromatics, Vol % 25.0 Max 5.4 2.2 6.2 14.2 FIA Olefins, Vol % 5.0 Max 0.0 0.7 0.0 0.5 Liq. Chrom Aromatics, Vol % - 8.2 5.7 8.6 15.3 To be reported - not limited

3-23 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 3

JP-8 FUEL SAMPLE PROPERTIES

Properties MIL-T-83133A Kentucky Kentucky Utah Utah Limit Sun Ashland Sun Ashland Saybolt Color (') 19 30 20 30 API Gravity 37.0-51.0 42.7 38.0 43.3 44.7 Density 0.7753-0.8398 0.8123 0.8348 0.8095 0.8030 02887 Distillation OF Initial Boiling Point • 313 259 316 275 10% Recovered 367 Max 338 332 349 350 20% Recovered • 357 364 376 385 50% Recovered • 401 408 419 421 90% Recovered • 469 475 459 461 End Point 626 Max 502 564 488 491 Freeze Point OF (58) Max (62) (69) (48) (31) Copper Strip Corrosion lb Max Is lb Is lb Total Acid Number, mgKOH/g 0.015 Max 0.019 0.002 0.017 0.013 Existent Gum, mg/lOOml 7.0 Max 1.0 11.8 1.0 15.2 Net Heat of Combustion, 18,400 Min 18,753 18,472 18,753 18,645 BTU/Lb Sulfur, Wt % 0.30 Max 0.00003 0.003 0.00003 0.002 Hydrogen Content, Wt % 13.5 Min 13.84 13.6 13.94 13.8 FIA Aromatics, Vol % 25.0 Max 8.0 4.2 8.0 20.6 VIA Olefins, Vol % 5.0 Max 1.4 1.0 0.0 0.5 Liq. Chrom Aromatics, Vol % - 8.2 5.7 8.6 15.3 Viscosity, cSt at -20°C 8.0 Max 4.8 5.9 6.1 4.7 'To be reported - not limited

attempted by adjusting the distillation end point, but In 1980 and 1981 Magnie obtained patents based also on limited success was achieved. A gas chromatographic the use of gas made from coal for additional oil analysis of the material indicated high concentrations recovery but emphasing the effects of hydrogen. of normal paraffins with carbon numbers between 11 and 14. Additional processing to crack these long chain Figure 1 shows that coal and heavy oil or tar sand normal paraffins will be required to produce specifica- deposits often occur in the same area. tion quality fuels. Figure 2 is a cross-sectional sketch of an oil reservoir showing the approximate positions of the major components of the gas early in the project and after enough gas has been injected (and sufficient time has elapsed) for a hydrogen-rich gas cap to be formed. HYDROGEN FROM UCG PROPOSED FOR HEAVY OIL In general terms, an ideal recovery system for high AND TAR SANDS EXTRACTION viscosity oil would be one that both: At the July 1986 Tar Sands Symposium sponsored by the • Reduces viscosity of the oil. United States Department of Energy, R. L. Magnie presented a concept for multiple resource extraction, • Provides a displacement fluid that will move oil utilizing gases from underground coal gasification to toward a producing well. enhance the recovery of heavy oil and tar sands which occur in the same area. Thus, two submarginal re- Hot, low-BTU gas (from underground coal gasification) sources could be combined in a new, economic, syner- could be used for transferring heat to the reservoir as gistic system in which the coal is utilized, additional well as providing a source of carbon dioxide. Heating heavy oil or bitumen is recovered, and a valuable of the oil and dissolution of the carbon dioxide will both hydrogen by-product is accumulated. serve to reduce the oil viscosity. However, carbon dioxide's high solubility and high compressibility are In 1974 Conoco research workers were granted a patent disadvantageous when it comes to building and main- on the use of gas made from coal for recovery of oil. taining a trapped gas effect. This is analogous to the Discussion in the patent points out the numerous in- sequence that occurs frequently in water flooding a stances in the United States where coal deposits and solution gas-drive reservoir where a beneficial trapped heavy oil reservoirs are coincident. gas saturation has been formed, but the high-solubility

3-24 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

FIGURE 1 COAL DEPOSITS IN RELATION TO TAR SANDS, AND HEAVY OIL RESERVOIRS IN U.S. AND CANADA

• Tar Sands dk,, ^tiiiii -r CANADA 7

£ Heavy Oil S in k. \ 41 1fltr

Osk. Coal Deposits in the United States j( UNITEI and Canada r IAT E N I C, th Anthyacit. .... NMn loi 'A

Subbilummoo, \t tignite and brovm rN. \'\ t ..,. -. r • 1\ 7 .,' I..,. y.

natural gas re-dissolves when the reservoir pressure is to a separation of the component gases, as they diffuse increased by water injection. through a reservoir, especially in reservoirs having substantial structural relief. Low-BTU gas (from coal) contains significant amounts of low solubility gases such as hydrogen, carbon mono- The different components will also have different tend- xide, and nitrogen. Such gases can maintain a trapped encies to adsorb on the reservoir rock. gas saturation when pressures are increased and thus aid in keeping the oil in the higher permeability flow Of the non-polar permanent gases, nitrogen is most channels. The low solubility gases will then provide the strongly sorbed, "owing to its large quadrapole mo- gas drive to move oil to producing wells. ment." It is possible that nitrogen in low-BTU gas may be preferentially adsorbed on some reservoir rock sur- The various components of low-BTU gas made from faces and that the extent of nitrogen adsorption may coal have significant differences in molecular weight, increase in areas where water saturation is lower solubility, and polarity. These differences should lead (hopefully, in the vicinity of the anticipated gas cap).

3-25 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Figure 2. In a widespread heavy oil or tar sand reser- FIGURE 2 voir, it seems possible that hydrogen and carbon monoxide could be gathered in a "cold" processing area and INJECTION OF COAL converted to methanol in a "hot" in situ combustion area. The methanol in turn could be used in solvent GASES INTO A RESERVOIR recovery of additional heavy oil or bitumen. (9 XUJECT GAS RACE FROM COAL

ALABAMA TAR SANDS UPGRADED BY PHYSICAL BENEFICIATION Tar sand deposits in the state of Alabama contain about 1.8 billion barrels of measured and 4.7 billion barrels of estimated in-place bitumen. Although these deposits ater are small compared to Utah tar sand deposits, they nevertheless represent a significant energy resource. a Hydrogen The major tar sand deposits are in the Hartselle sand- t Nitrogen stone formation and extend over the northwest part of • Carbon sonoxids the state. According to the Geological Survey of Alabama, richer tar sand deposits occur in west-central • Carbon dioxide Lawrence County and southeastern Colbert County. In PRODUCE ADDITIONAL OIL general, Alabama tar sands are lean, discontinuous and the bitumen content varies from deposit to deposit. The average thickness of oil impregnated zones is about STORE FUEL GAS lirE ROG 18 feet in the Hartselle sandstone formation. Alabama tar sands from Lawrence County and Colbert County are suitable for a surface mining operation. These deposits are easily accessible and moderately rich enough to be processed by surface mining techniques. Recently, the Mineral Resources Institute, a division of Wa tar the School of Mines and Energy Development, of the I Nitrogen University of Alabama, initiated a research program to • Carbon eeonoxide evaluate different processing techniques for the separa- • Carbon dioxide tion of bitumen from Alabama tar sands. According to M. Misra of the University of Alabama, the selection of a physical separation process depends on the following factors: Chemical Reaction Chamber • Bitumen viscosity Low-BTU gas made from coal could also provide an • Bitumen content ideal fuel gas for in situ combustion projects in need of • Sand size and composition additional fuel input, wider limits of flammability, and • Nature of sand/bitumen association. higher flame temperature. Also in those instances where temperatures in the reservoir exceed 350, it The requirements and the limitations of selected water seems reasonable to expect that some hydrogenation of based processes for some tar sands are given in Table 1. the heavy oil or bitumen could be expected if hydrogen A low shear hot water process can be applied to recover was present beyond the combustion zone. bitumen from low viscosity and high grade tar sands. For a moderate viscosity bitumen and oil wetted tar United States fuel demand is greatest for the hydrogen- sand, a high shear force field in conjunction with the rich natural gas and light crude oils which are in hot water process is required to separate the bitumen. shortest supply; whereas there is a plentiful supply in For a high viscosity bitumen and a lean tar sand the coal, shale oil, bitumens group. Low-BTU gas from deposit, such as the Alabama deposits, an ambient coal could provide the source for the hydrogen neces- temperature beneficiation process has been proposed. sary to move the lower hydrocarbon fuels up the scale. Tar sands from two different Alabama deposits, Lawr- It is interesting that the components for methanol ence County (Sample I) and Colbert County (Sample 10 (hydrogen and carbon monoxide) may be the surviving were studied in the investigation. diffusing gases if the carbon dioxide dissolves (in oil and water) and if the nitrogen is adsorbed. These gases Sized tar sand samples were wet ground in a rod mill at could be accumulated at the top of the reservoir as in 50 percent solids. Flotation experiments were eon-

3-26 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

TABLE 1

PHYSICAL SEPARATION PROCESSES FOR TAR SANDS

Processing Strategy Bitumen Phase Phase Tar Sand Viscosity Separation Disengagement Separation Source 90°C Efficiency (poise) Low shear, hot Gravity Athabasca, Canadian 2.5 Excellent water digestion settler High shear, hot Modified Asphalt Ridge 10 Excellent water digestion froth flotation High shear, hot Modified Sunnyside 100 Excellent water diluent froth addition flotation Liberation by Froth Sunnyside and Tar 100 Good size reduction flotation Triangle

ducted in a Galigher flotation machine at a standard TABLE 2 condition (6 percent solids, 900 rpm, air flow rate of 6 liters per minute) and with the addition of frother (MISC). If required, a collector (kerosene) was used. PROPERTIES OF TAR SAND BITUMENS The rougher concentrate was cleaned once. The process flow sheet, describing the beneficiation and upgrading steps is given in Figure 1. Alabama Canada Utah Sample Sample Atha- Asphalt Tar Sand Properties I II basca Rise Analysis indicated that the average bitumen content of Carbon, Wt % 82.1 83.4 83.4 85.2 Sample I and Sample!! were 8 and 6.2 weight percent, Hydrogen, Wt % 9.7 9.7 10.6 11.7 respectively. The water present in these samples was Nitrogen, Wt % 0.7 0.7 0.4 1.02 less than 0.1 weight percent. In the absence of mdi- Sulfur, Wt % 2.1 1.7 4.8 0.59 genous water, the bitumen is attached directly to the BTU/Lb 17,000 16,800 17,700 18,800 sand surface and does not fill the interstices. The sand-bitumen bonding and the nature of bitumen film are different between Sample I and Sample II. In Sample!, the bitumen film is thin and partially envelops the sand grains. In Sample II the bitumen phase is ties of both tar sand samples are an order of magnitude rather bulky and selectively localized in the voids and interstices. more than Athabasca (Canada) tar sand bitumen. Ex- posure of the bitumen to the atmosphere for an extended period of time has a large effect on its apparent Elemental analyses and the physical properties of Ala- viscosity. bama tar sand samples are given in Table 2. Alabama tar sand bitumens are similar to those of Athabasca and Alabama tar sands are low grade, high in bitumen Utah tar sands. viscosity and are oil wetted. In the absence of mdi- geneous water, bitumen is directly bonded to the sand Alabama tar sand samples have coarser sand size distri- particles. It thus appears that the ambient temperature bution than Sunnyside (Utah) tar sand. Greater amounts flotation technique that has been developed for Sunny- of fines in the feed material would be expected to have side (Utah) tar sands could be applied to Alabama tar detrimental effects on the processing and subsequent Sands. bitumen recovery. One of the critical requirements of the ambient tem- The bitumen viscosity of tar sand is of great import- perature flotation process is that the bitumen viscosity ance from the processing standpoint. Bitumen viscosity must be sufficiently high that the bitumen can be was estimated to be 1,000 poise and 10,000 poise for broken and released from the sand particles by mechan- Sample I and Sample II, respectively. Bitumen viscosi- ical fracture and dispersed as 'particulates" in the

3-27 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1

TAR SAND PROCESSING FLOW SHEET

TAR SAND

Ba REDUCTION

I MIDDLINGS GRINDINGROD MILL WATER RECYCLING I WATER I TAILINGS I RECYCLING FLOTATION SEDIMENTATION SAND REJECT I iaoounosf SEDIMENTATION CLEANER j

I CONCENTRATEBITUMEN I

FINAL UPGRADING

_DILLITIOP+4JLTRASONIC I MODIFIED I I I WATER PROCESS THERMAL TAILINGS TAILINGS (dlknnl r.cov.,y) CENTRIFUGE 1 FINAL CO Z7LF= BITUMEN PRODUCT I______

3-28 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

aqueous phase. Once the bitumen particulate is Sample I which has a lower viscosity and a thin bitumen liberated it can be separated by flotation techniques. coating over the sand grains, exhibits a different flota- Viscosity measurements suggested that Alabama tar tion behavior (Figure 3). In this case, the tar sand had sands might be a suitable material for such an ambient to be ground finer than Sample II. For example, grind- temperature beneficiation process. Further upgrading ing Sample I to 60 percent passing 50 microns resulted of the beneficiated concentrate can be accomplished by in a concentrate grade of only 15 weight percent. Fine dilution-centrifugation and/or thermal processes. grinding (95 percent passing 50 microns) increased the bitumen grade in the concentrate to 23 percent. The rate of bitumen flotation in Sample I was much slower Beneficiation than Sample II, and as a result a collector (fuel oil) was required to enhance the flotability of the bitumen Flotation recovery and the grade of the bitumen largely particles. depend on the extent of size reduction and liberation of bitumen from the sand-bitumen matrix. Bitumen recovery and the grade of the concentrate as a function FIGURE 3 of particle size are given in Figure 2. As the percentage of sand particles passing 50 microns increases, the BITUMEN RECOVERY recovery and the grade both increase, reach a maximum and then decrease. AND GRADE IN THE CONCENTRATE 'or 30 It was observed that extensive size reduction of tar sand particles, to 90 percent passing 50 microns, results SAMPLE I in a eoncommitant decrease in the hydrophobic char- 90- 5% BItumen • fl.cov.ry . 40 acter of the bitumen pahse. Entrapment and transport 0 Gr.d. Frother. 0.41blton of hydrophilic fine sand particles into the froth phase • Promoter. O.lIb/ton also lowers the grade of bitumen. It appears that a Sample II should be ground to 60 percent passing 50 - 30 I. 50 microns to achieve optimum grade and recovery. At 0 a 'a this condition, (60 percent 0 passing 50 microns, a C a 1.5 pounds per ton frother) more than 80 percent of the U bitumen can be recovered as a concentrate containing 10- 20 as much as 25 percent bitumen. a

•0 - I 0 FIGURE 2

BITUMEN RECOVERY AND '0 I I I 0 40 GRADE IN THE CONCENTRATE 20 00 00 '00 'cc PERCENT OF TAR SAND PARTICLES PASSING 50 MICRONS SAMPLE II • Rsc.v.q 0 G,.do 00 - 0.2% BIIum. n so Processing the Benefieiated Concentrate

rams. Rejection of bulk sand and bitumen enrichment of the IF 00 Prouder o.7

Two different upgrading approaches were tested. The dilution-centrifugation technique has been used for the so upgrading of the bitumen concentrate produced by the hot water process. An attempt was made to use a similar technique for the removal of sand from the 40 beneficiated Alabama concentrate. The beneficiated 0 20 40 00 00 '00 bitumen concentrate was mixed with kerosene for vis- PERCENT OF TAR SAND PARTICLES cosity reduction in an ultrasonic field. After 15 min- PASSING 60 MICRONS utes conditioning, the diluted bitumen was centrifuged at 2,000 rpm for 15 minutes. A two-stage dilution- centrifugation technique was used.

3-29 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 At a concentrate to diluent ratio of 1:3, more than Both types of residues are generally undesirable mater- 95 percent of the bitumen can be recovered as a diluted ials whose disposal creates a significant economic im- bitumen layer containing less than 0.5 percent sand pact. Utilization in asphalt blends might be the opti- particles and negligible amount of water. Of several mum solution. diluents tested, kerosene was found to be the most suitable. CANMET carried out a series of blending experiments which produced asphalt blends that meet the required specifications. Thermal Processing of Concentrate Thermal processing is usually energy intensive and Materials produces a high quantity of environmentally unaccept- able spent sand. If a major portion of the sand can be The hydroprocessing distillation residues were obtained rejected prior to thermal processing and at the same by distilling the synthetic crude oil to a boiling point of time bitumen content can be increased, thermal pro- +524°C. These residues (pitches) were then blended cessing may be an attractive process for lean tar sands. with various soft asphalts to produce blends having Furthermore, thermal processes will eliminate several desired penetration values. bitumen upgrading steps such as concentrate clean-up and solvent recovery. Preliminry experiments were The nitrogenous extracts from Syncrude and Suncor conducted to recover oil from the beneticiated concen- heavy gas oils were obtained by extraction with di- trate using a non-fluidized thermal retorting process. methylsulphoxide (DMSO) containing 6 percent water. Some of the results were given In Table 3. Tar sands yielding 10 gallons per ton oil were upgraded to an oil rich concentrate yielding approximately four times as Hydroprocessing Distillation Residues much oil per ton of feed to the pyrolysis unit. Accord- ing to the MRI workers, uniformity in particle size of Since the objective of hydroprocessing bitumen is usual- the concentrate and ease of water removal from the ly the maximization of synthetic crude oil distillate concentrate make such a combined process strategy yields, compatibility of the residue with conventional both energy and cost effective. asphalts may be low. In asphalt production, residual materials generally are TABLE 3 distilled until they meet desired penetration specifications. However, these pitch samples were obtained by CAN MET during development work on hydroprocessing PYROLYSIS OF TAR SAND PEED technologies and all distillable material had been re- AND BENEPICIATED CONCENTRA moved. Therefore, only the blending of +5240C pitches with soft asphaltic base stock was studied. Table 1 shows the physical properties of several residuals and of Oil Yield (Gal/Ton) two (A and B) soft commerical asphalts of 150 to 200 Sample Feed Concentrate penetration that were used for blending. They are arranged in order of increasing processing severity of Sample 1 14-15 38-46 light Arabian crude oil and Athabasca bitumen resi- Sample II 10-11 39-40 duals. The hydrogen content and solubility of the pitches decrease as a function of processing severity and they become more dense and harder. The softening point increases markedly. The pitches were blended with the two soft asphalts to produce road asphalt blends having 85 to 100 penetration. The amount of pitches that could be added varied from 8 to 14 percent depending on the levels of conversion of the pitch as shown in Table 2. The blends met the required specifications of this grade of asphalt except for ductility. SYNTHETIC CRUDE OIL PROCESSING RESIDUES USED IN ASPHALT BLENDS The amount of pitch that can be blended also depends on the nature of the asphaltic base stock. The amount The Energy Research laboratories of CANMET, Energy, of Saudi Light pitch which can be blended with topped Mines and Resources Canada, have studied the use of Athabasca bitumen decreases with increased topping two classes of synthetic crude oil processing residues in temperature. When the Saudi Light pitch from 76 per- asphalts. One class includes the distillation residues cent conversion was blended with Athabasca bitumen from hydroprocessing of bitumen/heavy oils/petroleum topped at 316°C and 371°C, blends with properties as residuals. The other includes solvent extracts contain- shown in Table 3 were obtained. In this case considering the bulk of nitrogenous components from synthetic ably more pitch could be added and all specifications crude gas oils. including ductility could be met.

3-30 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1

PHYSICAL PROPERTIES OF PROCESSED RESIDUES AND ASPHALT CEMENTS

Sample SL-23 SL-49 SL-76 Ath-80 SL-87 A B Specific Gravity 1.044 1.102 1.144 1.138 1.189 1.024 1.008 15/15°C Penetration 250C, 123 7 0 0 0 157 168 bOg, Ss Ductility, 25°C - - 0 0 0 128 130 Viscosity at 135°C Kn, 208 - - - - 217 205 cST Solubility inTrichloro- 98.4 96.8 98.1 98.4 93.6 99.9 99.9 ethylene, % Softening Point, °C 43 85 102 107 110 43 43 Flash Point (COC), °C 346 345 327 346 350 310 332

TABLE 2

WEIGHT PERCENT OF PROCESSED RESIDUE IN BLEND MIXTURES WHICH MEET 85-100 PENETRATIONS TABLE 3

Asphalt Cements ... ._...... PHYSICAL PROPERTIES OF ASPHALT BLENDS Processed Residue IN ATHABASCA BITUMEN Athabasca 80 8(87) 11(91) Saudi Light 23 too soft - 49% In 36% In Saudi Light 49 14(85) 14(87) Athabasca Athabasca Saudi Light 76 10(88) 10(86) 31 C 3710C Saudi Light 87 8(98) 11(91) Penetration Penetration is indicated in brackets 50C, 100g, 5s 12 8 25°C, 100, Ss 90 80 Ductility (25 C 5cm/mn) +150 -1.150 Viscosity at 1350C Rn, cST 166 217 Softening Point (R&B, °C) 41 44 Flash Point, °C (COC) 230 246 In the case of roofing asphalts the hardness of these Solubility in Trichloro- 99.7 99.3 pitches is very desirable. The addition of these hard ethylene, % pitches to roofing asphalts might be an alternative to TPOT (5h, 1630C) air blowing. Table 4 shows the blend compositions Original Pen, % 45.7 56.2 obtained with three different residues and three soft Loss on Heating, Wt % 2.35 0.74 asphalt base stocks to attain penetrations of 30 to 45. Temperature Susceptibility With the exception of softening points these blends PVN (1.7) (1.4) meet the specifications of type 1 roofing asphalts. P1 However, these softening points are not much below (0.6) (0.8) Predicted Cracking Tempera- (40) (37) specifications and undoubtedly with more investigation ture, °C could be formulated to attain this specification. Pos- sibly limited air blowing may be considered.

3-31 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 4 nitrogenous material as well as polynuclear aromatic components. The catalytic cracking yields of the raffinates were significantly higher than for the un- WEIGHT PERCENT OF PROCESSED RESIDUE treated gas oils, showing that the extractions were IN BLEND MIXTURE TO OBTAIN beneficial. While no economic feasibility studies have TYPE 1 ROOFING ASPHALT been made for the extraction process, it would be enhanced if the extracts had some value. This led to considering the incorporation of the extracts into asp- Asphalt Cement halts. (150-200) A B C Related work has been done at the Western Research Processed Residue Institute in Laramie, Wyoming. Basic nitrogenous con- centrates from shale oil were blended into asphalts and Saudi Light - 76% 29(38) 29(31) 29(35) the results indicated improved resistance to moisture - 25(32) Venezuela-87% 24(37) damage. IPPU - 80% 26(38) - - The extracts from Syncrude and Suncor coker gas oils Penetration Is indicated in brackets were obtained in 3.4 and 5.6 percent yields, respective- Venezuela - Residuals from Venezuela crude oil ly. The Suncor extract was a solid material whereas IPPL - Typical Western Canadian crude oil residuals that of Syncrude was a liquid at room temperature. These extracts contain only negligible amounts of saturates.

The extracts were mixed with various base materials to Nitrogenous Extracts produce blends with penetrations of 85 to 100. Since the Syncrude extract was a liquid it had to be blended Synthetic crude coker gas oils were extracted to re- with harder materials while the Suncor extract being a move the bulk of the polar materials which are largely solid at room temperature was blended with base mat- nitrogenous and obtain a raffinate with superior cataly- erials of the same penetration range as the desired tic refining qualities. About 5 percent of the gas oil blend. The properties of the extracts and blends are was extracted and contained about 75 percent of the shown in Tables 5 and 6.

TABLES

PROPERTIES OF ASPHALT BLENDS USING EXTRACT FROM SYNCRUDE GAS OIL

Materials Blends Crude Oil Source Extract Lloyd S. Sask Pen Grade 85-100 85-100 85-100 85-100 % N Concentration in Blend 100% 19% 5% 15% 8% Physical Properties Viscosity: Kinematic, 135°C, cSt 2.68 487 316 332 314 Absolute, 60°C, PaS 0.24 2,695 1,253 2,278 1,595 Ductility, 25°C, 5cm/mn na 56 150 61 150 Solubility, C1CHCC12, % 99.8 99.7 99.7 99.8 99.7 Heptane Insol, wt % 5.30 25.8 17.2 26.6 22.7 Flash Point, °C (COC) 172 242 285 243 274 Softening Point, °C na 48 44 46 46 Penetration, 250C, bOg, too soft 100 89 98 97 5s Thin Film Oven Test: Wt Loss, % (0.96) (0.81) (1.45) (0.90) Pen, 25°C, 100g, 5s 34 52 41 49 Original Pen, % 34 58 42 51 Temperature Susceptibility Pen-Viscosity Number +0.1 (0.7) (0.5) (0.6) Penetration Index +0.1 (1.6) (0.5) (0.5)

3-32 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 6

PROPERTIES OF ASPHALT BLENDS USING EXTRACT FROM SUNCOR COKER GAS OIL

Materials Blends Crude Oil Source Extract Lloyd S. Sask Pen Grade 85-100 85-100 85-100 85-100 % N Concentration in Blend 100% 5% 15% 5% 15% Physical Properties Viscosity: Kinematic, 135°C, eSt 68 311 269 309 285 Absolute, 60°C, PaS 512 1,226 585 1,275 944 Ductility, 25°C, 5cm/mn 32 28 52 43 Solubility, CICHCCl2, % 97.8 99.2 99.0 99.8 99.7 Heptane Insol, wt % 30.0 18.1 23.9 19.8 24.1 Flash Point, °C (COC) 192 314 306 311 298 Softening Point, °C 43 43 43 44 43 Penetration, 250C, lOOg, 84 97 122 89 111 5$ Thin Film Oven Test: Wt Loss, % (0.34) (1.18) 0.38 (1.14) Pen, 25°C, lOOg, 5$ 53 54 54 60 Original Pen, % 55 44 61 54 Temperature Susceptibility Pen-Viscosity Number (0.6) (0.6) (0.7) (0.7) Penetration Index (1.1) (1.5) (1.0) (1.5) (1.0)

In the thin film oven tests considerable loss in weight and lowering of original penetration values occurred for all blends and for the blends with the larger amounts of extract they exceed specifications. This is probably due to the small amount of light ends in the extracts that could be removed by limited topping. The major problem appears to be ductility. Blends with the larger amounts of Syncrude extract had ductilities below specifications whereas blends with small amounts had sufficient ductility values. In the case of the Suncor extract none of the blends had the required ductilities. One interesting observation is that the Suncor extract had a lower penetration than that of the base materials, yet the penetration of the blends increased with increasing extract contents. This may suggest that these extracts could have potential as an asphalt rejuv- enator.

3-33 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 INTERNATIONAL

STARTUP DUE FOR MULTI-NATIONAL The donor stream is hydrotreated in a typical distillate GULF DRB DEMONSTRATION hydrotreater, but at reactor liquid hourly space velocities significantly higher than normal. A portion of the October is the scheduled start-up date for a 450 barrels hydrotreated distillate is recycled as donor back to the per day demonstration of the Gulf Donor Refined cracking unit. Bitumen (DRB) process in France. The project will be carried out by a Joint venture consisting of Gulf DRI3 products from atmospheric and vacuum fractiona- Canada, Alberta Oil Sands Technology and Research tion are blended with the corresponding virgin material Authority, and ASVAHL, a Joint venture of three from the teed and may be hydrotreated if a high quality French companies (see Pace Synthetic Fuels Report, synthetic oil is required. The pitch may be burnt as March 1986, page 3-25. fuel for utilities, and the gas may be used as feed to a hydrogen plant.

DEB Process Typical yields from a DRB-based upgrader are shown in Table 1. For Athabasca bitumen at 70 mass percent The Gulf DEB process is a liquid phase hdyrocracking conversion of 504°C plus material in the feed, the yield process in which hydrogen is made available from a Of C4 to 524°C material after secondary hydrotreating donor rather than as high pressure gaseous hydrogen. is about 90 volume percent on bitumen. At 75 mass Donor liquid is circulated between the feed cracking percent conversion and a gas oil end point of 552 0C, the step and a re-hydrogenation step. The donor is a liquid yield rises to 95 volume percent on bitumen. distillate stream containing substituted tetralins. it is derived from the feedstock in sufficient quantity for the process to be self-sufficient in donor. Service Factor

Figure 1 shows a typical application of the process in an The history of existing upgrading plants in the in- upgrading application. The heavy feedstock is fed to a hospitable climate of Northern Canada indicates that typical atmospheric and vacuum unit, and the resulting service factor is of crucial importance. The DRB vacuum residuum blended with donor and fed to the process is expected to perform with high reliability DEB cracking unit. The cracking unit is comprised of a furnace and soaking drums not unlike a typical vis- because of the simplicity of the process, operation at breaker. The resulting products are fractionated, and moderate pressure (800 psi), and the use of uncompli- the exhausted donor recovered as a 2000 to 360°C cated off-the-shelf equipment. There is no solids boiling fraction. handling and no catalyst or solid additive in the feed

FIGURE 1 UPGRADER WITH GULF DRB

FUEL GAS

iJ!flik!st1—w ;w je_.H2 VACUUM 4 iLVW'J :i TOWER SOAKING I BOTTOMS DRUM I i PRODUCT

-a---tI POWER AND STEAM -I I TO PROJECT PITCH

3-34 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1 Demonstration The search for a suitable plant to demonstrate the DES PRODUCT YIELDS ON ATHABASCA BITUMEN process led to the 450 barrels per day ASVAHL demonstration plant located at Solaize, near Lyon, France. ASVAHL is the "Association Pour La Valorisation Des Volume Huiles Lourdes." The ASVAHL facility is a facility for Percent of the investigation of residuum upgrading technologies. Bitumen The plant was started up in 1983. Butanes 3.7 Piping permits various process configurations to be run. Naphtha, C5 - 204°C 30.7 There is extensive tankage for management of feed and Distillate 2040_ 360°C 21.3 product storage. The facility is located adjacent to a Vacuum Gas Oil, 360°- 552°C 39.3 sophisticated refinery which supplies feed, utilities, fuel, and hydrogen. The refinery also serves as a Total Liquid Yield 95.0 "home" for products and effluents from the ASVAHL demonstration plant.

Notes: The plant capacity is such that commercial design has Yields based on hydrotreated virgin plus ORB pro- been used for most equipment. For example, furnaces ducts are conventionally fired instead of being electrically heated. Thus, a demonstration of a process in this Conversion of 504°C plus is 75 mass percent facility will provide a sound basis for scale-up and making judgments regarding operability. A demonstration of the ORB process will take place at the ASVAHL plant in the last three months of 1986. cracking zone where metals, asphaltenes, and feed Athabasca bitumen for the demonstration was acquired minerals would cause problems. Because of the circu- from the Syncrude Ltd. plant in Fort McMurray, lating donor, the Conradson Carbon content of feed to Alberta. It was trucked hot to Edmonton, where it was the charge heater is significantly lower than that of a blended with a hydrotreated light cycle oil for ease of coker or visbreaker. Thus coke laydown should not be a handling and moved by rail car to Montreal. The blend problem. was transferred to a small (2,300 tonne) tanker and transported to a port near Marseilles. Finally, it was Another attractive reliability feature is the "storage" transferred to barges and moved up the Rhone river to of hydrogen in the donor. In the event of a hydrogen the ASVAHL plant. plant shutdown or upset, the hydrocracker section of the ORB can remain on-line using hydrotreated donor Most of the essential equipment for a ORB run was from storage. This would permit orderly shutdown of already in place. Units to be used are as follows: this section. For other hydrogen addition processes, which use gaseous hydrogen directly, loss of the hydro- • Atmospheric and vacuum units for feed prepar- gen supply even briefly means an emergency shutdown. ation • Hydrovisbreaker furnace to heat the mixture of Applications vacuum tower bottoms and donor • Product distillation column for separation of Engineering studies have been carried out comparing products and recovery of the exhausted donor the process with other upgrading processes in a commercial context. Scenarios chosen include a mineable • Distillate hydrotreater for regeneration of the oil sands plant (similar to Syncrude Ltd.) produing high donor. quality synthetic oil, and a small in situ plant. Pro- ceases in the comparison include high pressure hydro- New equipment to be installed includes soaking drums cracking and flexicoking. after the hydrovisbreaker heater and pumps for recirculation of the hydrotreated donor. Minor piping modifications will be carried out to permit full integrated At 70 percent conversion (of 504°C plus material), the operation in the ORB mode. DEB process was significantly better than coking and was competitive with the best of the hydrocracking Data provided by the demonstration will be used to processes. Preliminary evaluation at 75 percent con- develop the design for a commercial sized upgrader. version shows even more promising results. Also very attractive are combination schemes using DES with recovery of oil from the unconverted pitch by conventional solvent de-asphalting. No credit was taken in the evaluation for service factor differences in the processes.

3-35 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENVIRONMENT

FISH AND WILDLIFE TO DETERMINE ENDANGERED Pediocactus despalnil Is a small barrel-type cactus, 1.5 STATUS OF SAN RAFAEL CACTUS to 2,3 inches tall and 1.2 to 3.8 inches wide. Each areole or spine cluster contains no central spines and The United States Fish and Wildlife Service has pro- between 9 and 13 white, flattened, comb-like radial posed to determine the endangered status of the San spines that partially obscure the stein. The small Rafael Cactus. Although the only known occurrences flowers are about 1 inch across and are peach to yellow of the species do not appear to fall within the boundar- in color with a bronze tint. With its diminutive size and ies of the San Rafael Swell Special Tar Sands Area, peculiar habit of shrinking under ground for several nearby combined hydrocarbon leasing could be im- months a year during dry and cold seasons, it was only pacted. discovered In 1978.

There are two known populations ofPediocactus It is noticeably visible only for a short time in the despainli, about 25 miles apart and each containing spring when it is in bloom. Otherwise, even if the exact 2,000 to 3,000 individuals. Both occur in central Utah location of its population is known, it can be overlooked (Emery County), mainly In areas administered by the easily. Bureau of Land Management. This rare species Is being sought by cactus collectors, one population is heavily If the species is determined to be endangered, then the impacted by recreational off-road vehicles, and approx' Fish and Wildlife Service could define a critical habitat imately one-half of each population is in areas covered for its preservation. by oil and gas leases and/or mining claims for gypsum.

3-36 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 WATER

WATER QUALITY IN ALBERTA OIL SANDS AREA NOTED FIGURE 1 A 1985 report, L-85, from Alberta Environment, sum- AOSERP WATER QUALITY STUDY AREA marizes water quality constituents in the Athabasca River Drainage study area and examines relationships between these constituents and changes in land for- AREA mation, hydrology, and development. STUDY

Athabasca Oil Sands Area CA The Alberta Oil Sands Environment Research Program (AOSERP) study area encompasses about 28,400 square c:.:.h. kilometers in northeast Alberta (Figure 1). The area includes most of the mineable area of the Athabasca Wabiskaw-McMurray deposit of oil sands. The Suncor J Inc. and Syncrude Canada Ltd. oil sands mining and processing plants are both in the study area. Fort CU McMurray, located in the southern part of the study \fl area, is a major population center. Anzac, Fort Chipewyan, and Fort Mackay are small settlements. Increased demands on surface waters associated with mining development include recreational, domestic, and commercial uses. Despite these demands there is a concern to minimize impacts of development on water quality within the Athabasca Basin.

Regional Surface Water Quality - •IT,n Several specific water quality studies related to industrial development were initiated in 1916 throughout the AOSERP area. Sampling sites were selected in tour VP major regions of the study area including: I p. Tan • Mainstem Athabasca River • Tributaries • Lakes • Athabasca Delta. All recorded data were stored in the National Water Quality Data Bank (NAQUADAT). Water quality mon- 'I a - itoring activities have continued to the present, fo- cusing on the Athabasca mainstem and the Athabasca - ...... Delta. CA - The objective of the coordinated regional water quality Tat? program was to establish baseline data for aquatic resources in the AOSERP study area, thus providing a standard against which any impact could be measured. •1. Oil sands development, however, had already occurred: Suncor Ltd. (originally, Great Canadian Oil Sands Ltd.) began operations in 1967; Syncrude Canada Ltd. began operations in 1977. Because additional oil sands development was planned for several watersheds in the area, a broad regional data base was required. The The report includes: L-85 regional report is a summary of water quality constituents characteristic of watersheds associated with the Athabasca River in the north, east, west, and • Descriptions of regional baseline states south. • Identification of physical, chemical, and biological processes affecting surface water quality

3-37 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 • Identification of significant correlations be- Interaction With Groundwater tween water quality constituents and hydrology The Alberta Research Council conducted a regional • Evaluation of the significance of natural levels hydrogeological evaluation of the Athabasca oil sands of physical and chemical parameters to bio- area. A total of 75 observation wells were installed at logical communities 15 locations within the study area. It was estimated • When possible, an assessment of impacts of that groundwater contributions entering the Athabasca development on surface water quality. River between Fort McMurray and Embarras are negligible.

Drainage Systems The Athabasca (17.2 cubic kilometers per year) and Clearwater (4.3 cubic kilometers per year) rivers Watersheds in the AOSERP study area include the provide the major discharge inputs into the AOSERP following drainages as major components of the surface study area. The contribution of flows from tributary water drainage: streams is relatively minor. The mean annual inflow from the Athabasca River system to Lake Athabasca is • The Athabasca River enters the study area 23.9 cubic kilometers per year. from the southwest and extends to the Atha- basca Delta Several northern rivers drain directly into Lake Atha- basca, the largest of which is the Pond du Lee River • The Clearwater River, which originates in Sas- (9.4 cubic kilometers per year). The average outflow katchewan, enters the study area from the from Lake Athabasca and the delta to the Slave River southeast and joins the Athabasca River at Fort is about 45.3 cubic kilometers per year. McMurray • Major tributary streams south of Fort Mc- Hydrographs for streams in the area depict a snowmelt Murray Include the Horse, Hangingstone, and response beginning at the end of March and peaking in Christina rivers. The Horse River enters the mid-April. Estimated snowmelt runoff coefficients Athabasca River. The Hangingstone and Chris- (volume of runoff divided by volume of snowwater tina rivers are tributaries of the Clearwater equivalent on the ground) ranged from 18 percent (Mus- keg River) to 56 percent (Joslyn and MacKay rivers). • Major tributaries flowing from the east to the Athabasca River north to Fort McMurray in- Suspended materials follow a seasonally cyclical pat- clude the Steepbank, Muskeg, and Firebag tern, with high levels occurring during high now peri- rivers. The Richardson River originates in ods. The average annual sediment load upstream of Saskatchewan and enters the Athabasca main- Fort McMurray is 13,600,000 tonnes per year. The stem in the delta area average annual sediment load from the Clearwater • Major tributaries flowing from the west to the River is 90,000 tonnes per year. Athabasca River north of Fort McMurray In- clude the Beaver/Poplar, MacKay, and Ells. Most tributaries entering the Athabasca mainstem have Several smaller tributaries drain the east slopes characteristically stable channels. Little erosion of the of the Birch Mountains bank materials occurs within the basin because of dense vegetation cover and low runoff. Also, downstream • Water bodies associated with the Athabasca reaches are entrenched in bedrock. Erosion, however, delta include numerous lake distributary chan- is prevalent in streams draining the east slopes of the nels. Birch Mountains.

Surface Water Hydrology Impacts of 011 Sands Development on Hydrology Gauging stations on the Athabasca River above Fort Possible hydrogeologieal difficulties associated with oil McMurray and the Clearwater above Port McMurray sands development include groundwater depressuriza- have been in operation since 1957. The downstream tion, natural gas occurrence, saline water, and induced gauge at Embarras was installed in 1971. Short-term infiltration. records (since 1975) are available for most of the tributaries entering the mainstem. Oil sands development places increasing demands on water supply. Surface waters and groundwaters are Water is supplied by precipitation and lost through used in processing and are later discharged into water- runoff and evapotranspiration. Water also may remain ways. Groundwater associated with oil sands must be as surface or subsurface storage, but over the long- disposed of before the sands can be mined. This water term this component is assumed to be negligible. is highly saline and frequently toxic to aquatic organ- isms. In the AOSERP study area, evaporation has been found to account for 78 to 80 percent of precipitation; accor- Depressurization (reduction of pore pressure) and de- dingly, runoff accounts for 20 to 25 percent of pre- watering (removal of pore water) are required to ensure cipitation. This high evapotranspiration runoff ratio pit slope stability and dry pit conditions. Chemical results from high summer temperatures, long hours of characteristics of mine depressurization water include sunshine, low humidity, abundant vegetation, open high saline levels, range of heavy metals, and high water, and muskeg.

3-38 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 organic constituents. Natural gas has been produced the proposed plan to control salinity in the Dirty Devil from the basal McMurray aquifer and may present River will not adversely affect the environment. problems for depressurization. The proposed salinity control unit is part of the Color- ado River Water Quality Improvement Program in Athabasca Mainstem southern Utah. The study area encompasses the Dirty Devil River Basin including Muddy Creek and the Fre- The Athabasca River originates in the Columbia Glacier mont River which are tributaries to the Dirty Devil of Jasper National Park and flows unregulated River. The area of influence includes portions of 1,450 kilometers to Lake Athabasca via the delta Sanpete, Sevier, Piute, and Garfield Counties, but most distributaries. of the study is located in Wayne and Emery Counties.

The river reach upstream of Fort McMurray is gorge- The purpose of the Unit is to reduce salinity in the like with many meanders confined within steep banks Colorado River. The Dirty Devil River contributes and rapids. about 150,000 tons of salt per year to the Colorado River System. The study was conducted to find a Mean annual long-term discharge for the Athabasca practical means of reducing this annual salt load to the River at Embarras Airport Is estimated to be 766 cubic Colorado River. meters per second. Maximum mean monthly flow typically occurred in June and July, with flows ranging The recommended plan includes separate facilities to from 1,170 to 1,960 cubic meters per second. The collect flows below two saline springs (Hanksville Salt 1:10 year, 7 year drought condition for the Athabasca Wash and Emery South Salt Wash) and dispose of them River below Fort McMurray is 119 cubic meters per by deep-well injection into the Coconino Sandstone. second. Approximately 2.75 cubic feet per second would be injected, reducing the salt loading from the area by Seven water quality locations were monitored along the about 20,900 tons per year. Flows of the Colorado Athabasca River mainstem. It was found that there River would be reduced by about 2,000 acre-feet per was a consistent seasonal pattern In the water quality year. parameters. During low now periods (winter and fall) bicarbonate ions and phosphate were the parameters An injection well would be installed initially at Emery that differentiated sample sites. In addition, concen- South Salt Wash to characterize the receiving forma- trations of nickel were useful in distinguishing sites in tion. Once initiated, construction of the entire unit is winter (maximum values). During high now periods expected to be completed within 3 years. The overall (spring and summer), TOC, chloride Ions, nickel, and cost effectiveness of the recommended plan is esti- vanadium differentiated groups of sample sites. mated at $97 per ton of salt.

Changes in ion concentration were attributed to inputs The primary mineral resources in the area are coal, from either the Clearwater River or natural saline uranium, conventional oil and gas, and tar sands. The seepage rather than the industrial saline discharge via tar sands are found in the lower Dirty Devil River Poplar Creek. drainage in an area known as the Tar Sand Triangle. The National Park Service and the Bureau of Land Parameters which serve as markers for sewage ef- Management (BLM) released a Draft Environmental Im- fluents are phosphate, TOC and fecal coliforms. Muni- pact Statement on the potential development of this cipal wastes at Fort McMurray were continuously dis- resource. (See page 3-37 of the September 1984 Pace charged. The downstream effects of treated sewage Synthetic Fuels Report.) Preliminary tar sands pr8JT were limited to the mainstem upstream of the con- plans call for obtaining water directly from the Dirty fluence with the Muskeg River. Devil River. During formulation of the salinity control plan, Reclamation considered the potential use of saline The metals nickel and vanadium are associated with oil water in the development of tar sand resources. It was sands in the AOSERP region. The concentrations of concluded that this development was very speculative nickel and vanadium were higher at periods of increased because the world oil market is currently depressed and flow (spring and summer), indicating the significant extraction technologies to process the tar sands are effect of weathering of rocks. The major conclusion of only now being researched. Hence, Reclamation be- the study was that sites exhibiting elevated concen- lieves that saline water would not be needed for this trations of nickel and vanadium in surface waters were purpose in the foreseeable future. associated with the natural occurrence of bitumen in the river bank and valley wall rather than with indus- With regard to the synthetic fuels industry, Pace be- trial effluents. lieves that the importance of the Environmental Assessment lies not in the recommendation to collect and dispose of the saline water by deep-well injection INDUSTRY USE OF SALINE WATER NOT (thereby rejecting the concept of industrial use of the EXPECTED IN TAR SAND TRIANGLE water). Rather, the Environmental Assessment advances a concept that could be considered in future In July 1986 the Bureau of Reclamation released the proposals of projects that use large quantities of water results of an Environmental Assessment of the Dirty in the semi-arid Tar Sand Triangle. Obviously, many Devil River Salinity Control Unit. In its Finding of No technical problems would need to be overcome if saline Significant Impact (P01.151), the Bureau determined that water is to be used in an industrial facility. ## ##

3-39 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RESOURCE

COMPLEXITY OF SUNNYSIDE TAR SANDS Before each sample was analyzed with the scanning MAY INHIBIT RECOVERY electron microscope, the tar was extracted by a solvent wash, and this produced two important observations. A study of bitumen-bearing sandstones from Sunnyside, First, the extracted bitumen contained an appreciable Utah by C. J. Schenk and K. M. Pollastro of the United amount of mineral material that was removed from the States Geological Survey (USGS) points out some pro- pores along with the bitumen. The pore throats of the blems which may be (aced In attempting to develop this extracted samples were littered with mineral material resource. that was dislodged during the solvent extraction process. This suggests that attempts to chemically or The bitumen deposit in Eocene rocks near Sunnyside, thermally remove the bitumen will have to prepare for Utah is one of the largest in the United States, with flushing of various authigenic minerals along with the numerous studies reporting estimates of 2 to 6 billion bitumen, and for the plugging of pore throats and barrels of bitumen in place. The sandstones were possible loss of permeability due to pore plugging by deposited in fluvial and lacustrine environments as part dislodged mineral material. of a large fluvial-deltaic system along the margin of Eocene Lake Uinta. The surfaces of the framework grains after extraction illustrate another aspect that could serve to reduce The USGS study concerned the mineralogy and diagen- permeability, that of high surface areas due to authi- esis of the bitumen-bearing sandstones and intercalated genic mineral development or phases of dissolution. lithologies. The mineralogy of the sandstones will exert an important control on the success of any attempt at bitumen recovery, whether it be by mining or in situ Mineralogy and Diagenesis techniques. of Sandstones The Sunnyside deposit is located along the Roan Cliffs The primary mineralogy of the sandstones is complex northeast of the town of Sunnyside, in townships 11 and may consist of detritus from sedimentary and through 15 south, and ranges 13 through 17 east, Carbon crystalline source terranes. Most of the sandstones County, Utah. Most of the samples analyzed were that contain bitumen are sub-feldspathic and felds- taken from two cores in T13S, R14E (Figure 1). Sam- pathic arenite and contain variable quantities of lithic ples were studied in petrographic thin sections, with the carbonate fragments and mica. scanning electron microscope (SEM) coupled with energy-dispersive X-ray, and with whole-rock and clay Many of the samples exhibited evidence of framework fraction X-ray powder diffractions. grain dissolution. Feldspars were particularly suscept- ible to dissolution. The main effect of dissolution is to increase the surface area of the grain surfaces adjacent Bitumen Saturation to pores, and to provide ions for the growth of authigenic minerals in the pores. Both of them have a Bitumen saturations in both outcrop and core samples negative effect on permeability. of sandstones were found to be quite erratic between adjacent lithologies that exhibit textural changes. Probably the most important phase of dissolution occur- Commonly, the coarser grained sandstones contain red when carbonate cement was dissolved to produce more bitumen than finer rained sandstones. The secondary porosity. Many of the sandstones were intercalation of coarse-grained fluvial channel sand- cemented by dolomite that partially replaced and em- stones with overbank mudstones, lacustrine sandstones, bayed the edges of the detrital quartz and feldspars. and mudstones results in discontinuous sandstone bodies The cemented sandstones do not contain bitumen. whose geometries are difficult to predict, and there- However, sandstones with the same style of embayed fore, the overall extent of bitumen saturation is diffi- quartz and feldspar but no carbonate contain much of cult to predict. Most fine-grained sandstones, silt- the bitumen. The inference is that the carbonate stones, mudstones, and thin carbonates intercalated cement has dissolved to produce secondary porosity with the coarser grained sandstones do not contain prior to the introduction of the bitumen into the bitumen, indicating that sedimentology is the first- sandstones. The erratic distribution of secondary poro- order control on bitumen distribution. sity resulting from the dissolution of carbonate cements is well known. Bitumen saturation is also erratic on a smaller scale, such as between adjacent laminae. This indicates The bitumen-bearing sandstones have been cemented by diagenetic control of fluid-flow pathways and resultant a variety of authigenic minerals, and all of these bitumen distribution. In most of the sandstones, the minerals contribute to a loss of permeability or the bitumen does not completely fill the available inter- potential for formation damage during recovery. Much granular pore space and is commonly lining the edges of of the detrital framework is cemented by syntaxial the pores. quartz or feldspar overgrowths. The addition of the minute overgrowths adds to the surface area of the This lining of the edges of the pores, indicates that the grain facing a pore and will have a deleterious effect on bitumen has moved between and around the various Permeability. authigenic minerals that have grown there.

3-40 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 SUNNYSIDE TAR SAND DEPOSIT, UTAH A

. 800 Bituminous Sandstones - Silteton., Shals

FEET A r .-:

•c:t8

1.133 •'•c11 L3t

Location - W. _,c T.148

CARBON COUNTY

R. R.14E R.15E

OUTCROP Li 3 MILES

Clays form several of the most important cements in Several zeolite minerals were also found in the sand- the sandstones due to their behaviour, both chemically stones, but analcime was the most common and occur- and mechanically, during recovery processes. Many red in amounts as high as 25 weight percent of the studies have documented the negative effect of clays in whole rock. reservoir stimulation. Clay mineral assemblages in the Sunnyside sandstones are dominated by illite, but Carbonate cements in the Sunnyside sandstones in- mixed-layer ilute/smectite cements were found in cluded calcite, dolomite, ankerite, and siderite. These many samples. Pure or nearly pure smectite is also a minerals ranged from trace amounts in the sandstones common cement coating detrital grains and lining to greater than 90 weight percent of the thin carbonate pores. The presence of this expansive clay may be a beds. problem. Chlorite was also common as a cement. Vermicules of kaolinite replace feldspars or carbonate ëlasts and occur as pore-filling cements in most lithologies.

3-41 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 In summary Schenk and Pollastro conclude that many Surface-Mineable Crude Bitumen and minerals, which will have differing solubilities and Synthetic Crude Oil Reserves reactions to any fluids introduced into the sandstones, have grown authigenically in the sandstones. The The initial mineable in-place reserves of crude bitumen distribution of bitumen has been controlled either by for the surface-mineable area were determined using the distribution of authigenic mineralization or the isopach net pay maps of that part of the Athabasca erratic development of secondary porosity. This infor- Wabiskaw-Mc Murray deposit where total overburden mation should prove useful to those interested in plan- and top reject thicknesses do not exceed 75 meters. ning for bitumen recovery from these sandstones. Potentially mineable areas were identified by economic stripping-ratio criteria, a minimum saturation of 5 mass # it## percent crude bitumen, and a minimum saturated zone thickenss of 1.5 meters. Within the potentially mineable areas, the initial mine- ERCB UPDATES ESTIMATED RESERVES OF CRUDE able volume in-place of crude bitumen was established BITUMEN AND SYNTHETIC CRUDE OIL to be 11.9 billion cubic meters. After allowing for surface facilities (plant sites, tailings ponds, discard The Alberta Energy Resources Conservation Board pre- dumps), environmental protection corridors along major pares yearly updates of Alberta reserves of crude bitu- rivers, isolated mineable areas, and assuming a men and synthetic crude oil. The latest figures are as combined mining/extraction recovery factor of 0.78, of the end of 1985. the resulting initial established mineable reserve of crude bitumen is estimated to be 5.2 billion cubic meters as shown in Figure 1. Technological Initial In-Place Volumes of improvements, better placement of surface facilities in Crude Bitumen future projects, and improved price/cost economics could increase this estimate. Alberta's crude bitumen reserves are contained in designated deposits within the oil sand areas of Atha- The key for Figure 1 is given as follows: basca, Cold Lake, and Peace River. Oil Sand Area Orders (OSA Orders), issued in August 1984, for these • Initial Volume In-Place. Gross volume of crude areas provide an outline of the areal extent of crude bitumen established to exist within the surface bitumen occurrence and the specific geological zones mineable boundary. which have been declared as oil sands deposits. • Initial Mineable Volume In-Place. Volume of Initial in-place volumes of crude bitumen in each depos- crude bitumen calculated using minimum satur- it were estimated using drillhole data available to the ation and thickness criteria, and based on the end of 1985. The crude bitumen within the Cretaceous application of economic stripping-ratio criteria. sands was determined using a minimum saturationof • Initial Established Mineable Reserve. Volume 3 mass percent crude bitumen, a minimum saturated of crude bitumen established within category 2, zone thickness of 1.5 meters, and a "building block" but excluding mining, extraction, and isolated approach to identify the in-place volume. Each deposit ore losses, and areas unavailable due to place- was divided into 2,340 hectare (quarter-township) ment of mine surface facilities and environ- blocks and the initial in-place volume of crude bitumen mental buffer zones. in each block was determined using the average properties of the wells drilled in the block. Blocks not • Remaining Established Mineable Reserve. Vol- containing wells were assigned conservative values ume of crude bitumen established with categ- based on the lowest initial in-place volume of crude ory 3, less cumulative production. bitumen calculated for an adjacent block. The yield of synthetic crude oil through upgrading of The crude bitumen in-place volumes in the carbonate crude bitumen is dependent on the type of upgrading occurrences were determined on the basis of isopach technology employed, the use of any residual materials mapping rather than the building-block method. A produced, and the degree to which off-site energy minimum bitumen saturation of 30 percent of pore sources are employed. The Board has adopted a synthe- volume and a porosity value of 5 percent were used as tic crude oil yield factor of 0.80. This is an upward cut-offs in this evaluation. revision from the previously employed yield factor of 0.75. Using the 0.80 yield factor, initial established The total initial volume of crude bitumen in-place for reserves of synthetic crude oil for the surface-mineable the designated deposits at December 31, 1985 was esti- areas are 4.2 billion cubic meters. mated as 266.4 billion cubic meters. This represents a slight increase from last year's figure (265.6 billion), Mineable reserves defined as "reserves under active due primarily to additional drilling in the Cold Lake development" include only the approved Suncor and Clearwater Deposit. The initial in-place volumes for Syncrude projects. The estimated mineable crude bitu- individual deposits are presented in Table 1. men reserves under active development are given in Table 2.

3-42 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1

INITIAL IN-PLACE VOLUMES OF CRUDE BITUMEN

Oil Sands Area Initial Average Oil Sands Deposit Volume Pay Bitumen Overburden Depth/zone In-Place Area Thickness Saturation (m) (Million (Thousand (m) Pore Cubic Hectare) Mass Vol Meter,) - - Free Free ATHABASCA Wabiskaw- Mc Murray 0-20 6,750 93 34 0.101 20-40 10,640 135 38 0.098 40-80 6,820 95 35 0.094 80-120 2,470 28 41 0.097 80-750+ flj,Q0 4,329 19 0.069 Sub-Total 144,480 Upper Grand Rapids 150-450+ 4,140 334 9 0.062 Middle Grand Rapids 150-450+ 1,410 182 5 0.077 Lower Grand Rapids 150-450+ 1,220 173 6 0.051 Grossmont A 9,840 939 10 0.60 B 5,380 976 5 0.69 C 15,390 1,189 10 0.75 D 1919. 1,063 16 0.67 Sub-Total 50,500 Nisku 200-800+ 10,330 499 8 0.55 COLD LAKE Upper Grand Rapids 300-600 7,400 816 6 0.065 Lower Grand Rapids Cold Lake Area 11,847 741 12 0.069 Lindberg Area Sparky 45 7 4 0.074 Lower Grand Rapids 2 15 3 3 0.099 Lower Grand Rapids 3 40 4 5 0.085 Lower Grand Rapids 4 180 22 4 0.092 Lloydminster 275 10 12 0.102 Sub-Total 12,202 Clearwater 300-600 11,330 561 12 0.078 0.56 Wabiskaw-MeMurray, Cold Lake Area 3,165 582 6 0.057 Lindbergh Area Cummings 1 283 32 5 0.089 Cummings 2 235 25 5 0.089 McMurray 272 27 5 0.093 Sub-Total 3,955 PEACE RIVER Bluesky-Gething 300-700 500 187 4 0.081 0.57 Bluesky-ThilThead 300-750+ 11,500 800 14 0.045 0.42 Upper Debolt 500-800 1,580 60 13 0.61 Lower Debolt 500-800 4,310 96 32 0.70 Shunda 500-800 1 540 72 14 0.54 Total

3-43 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 For the drilled wells in the experimental schemes, an established reserve figure of 13.8 million cubic meters Is considered to be appropriate based on projected production to the completion date of each experimental scheme. Information from a total of 1,132 wells was used in determining the experimental scheme reserves figure. The Board's estimate of the established in situ crude bitumen reserves under active development is given in Table 3.

TABLE 3

IN SITU BITUMEN RESERVES UNDER ACTIVE DEVELOPMENT (Million Cubic Meters)

Initial Initial Number Volume Established of Development In-Place Reserves Wells Peace River Commercial Thrmal-Blucsky/Bul1head 14 5.6 216 Cold Lake Commercial Project Thermal-Clearwater 212 38.1 880 TABLE 2 Lindbergh Commercial Projects Primary-Cummings I &2 191 3.8 367 Other Mannville 195 0.2 35 MINEABLE CRUDE BITUMEN Thermal-Cummings I & 2 19 2.9 172 RESERVES UNDER ACTIVE DEVELOPMENT 'l',ermal-Other Mannville 6 1.0 49 (Minion Cubic Meters) Lindbergh Other Primary Cumu- Cummings 1 & 2 308 6.2 346 Initial Initial lative Remaining Other Mannville 626 0.6 98 Volume Estab- Pro- Estab- Experimental Schemes 163 13.8 Development In-Place lished duction lished AIM! Total 1,134 72.2 3,295 Suncor 192 140 58 82 Syncrude 252 248 48 200 Total 444 388 106 282

Established In Situ Crude Reserves The Board has also assigned established reserves for the commercial in situ projects and a combined total for all experimental field-demonstration projects. In addition, established reserves have been estimated for the primary production areas. The initial primary established reserve for the Lindbergh Area was estimated to be 10.8 million cubic meters based on a 2 percent average primary recovery factor for the Cummings sands, and an 0.1 percent average primary recovery factor for other Mannville sands. The initial established reserve for the Lindbergh thermal production areas was estimated to be 3.9 million cubic meters based on a 15 percent average recovery factor for the Mannville sands. For lands under thermal commercial development established reserves were assigned for the individual projects based on historical and current production.

SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RECENT OIL SANDS PUBLICATIONS/PATENTS

The following papers was presented at the 37th Annual Technical Meeting of the Petroleum Society of CIM held in Calgary, Alberta, Canada, on June 8, 1986:

J. P. Millour, "An Expanded Compositional Model for Low Temperature Oxidation of Athabasca Bitumen" Koichi Takamura, "The Physical Chemistry of the Hot Water Process" T. N. Near, "The Use of Flue Gas with Steam in Bitumen Recovery from Oil Sands" Kenneth E. Kisman, "A New Performance Indicator for Thermal Recovery Based on a Practical Economic Model" Gary E. Davis, "Waste Management for a Large Scale Drilling Project" Larry LeBlanc, "Optimized Drilling Through Use of Downhole Motors" Asfaha Lob, "Improved Analysis Techniques Quantitatively Determine Critical Organic Additives Simultan- eously in Cement Blends" J. Z. Bai, "An Exact Solution for Bottom Hole Assembly Analysis" R. A. McKim, "Cost Control for Offshore Petroleum Exploration" Gokhan Coskuner, "New Stability Theory for Designing Graded Viscosity Banks" Marty L. Proctor, "Steamflooding Light and Moderately Viscous Oil Reservoirs in Alberta" Frank F.J. Lin, "Laboratory Evaluation of Crosslink Polymer and Alkali-Polymer Flood" S. M. Farouq, "Tertiary Recovery of Two Alberta Oils by Miscellar Flooding" S. G. Sayegh, "Multiple Contact Phase Behaviour in the Displacement of Crdue Oil with Nitrogen and Enriched Nitrogen" B. Van Dort, "Lessons Learned in North Sea Oil Field Developments" John P. Dielwart, "Canadian Petroleum Prices and Demand - An Overview" J. L. Pasay, "The Cost of Finding Oil and Gas in Western Canada: Implications for Industry and Governments" Peter Sekera, "Oil Prices - 1921 to 2121 (Past, Present and Future)" G. R. Tomilson, "Production Loans - One Bank's Approach" Geoff Wright, "Application of Fluid Analyses to the Operation of an In Situ Combustion Pilot" M. B. Dusseault, "Monitoring In Situ Processes" Sandra Kok, "Total Dissolved Solids Removal from Water Produced During In Situ Recovery of Heavy Oil and Bitumen" Peter Bottomley, "Turnover Management at Esso C.L.P.P. land II" Dale Chenery, "The Damage Discussion: Its Effect on Well Flow" A. Settari, "Liquid CO2 Fracture Stimulation and Case Histories" Ottmar Hoch, "Heated Acids for Improved Stimulation Results" Greg Lancaster, "Liquid CO2 Fracturing - Advantages and Limitations" Derek Evans, "Fracture Execution - An Essential Part of Every Fracture Design" David K. Fong, "Solution of Numerical Problems Related to Gas Phase Appearance or Disappearance in IMPES Black Oil or Pseudo Miscible Simulation" Ben I. Nzekwu, "Mobility Control in Dynamic Gravity Segregation Flow Systems" Hans Vaziri, "Finite Element Analysis of Oil Sands Subjected to Thermal Effects" Hans Vaziri, "Mechanics of Fluid and Sand Production from Oil Sands Reservoirs" Hemanta K. Sarma, "An Experimental Verification of a Modified Instability Theory for Immiscible Displacements in Porous Media"

The following papers were presented at the 56th Annual California Regional Meeting on April 2, 1986 in Oakland, California:

3-45 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 E. Vittoratos, "interpretation of Temperature Profiles from the Steam-Stimulated Cold Lake Reservoir" S. G. Wood, "Steamflood Surveillance Using Temperature Observation Wells" T. R. French, "Use of Emulsions for Mobility Control During Steam flooding" A. H. Falls, "The Role of Non-Condensible Gas in Steam Foams" S. S. Mohammadi, "Steam-Foam Pilot Project in Guadalupe Field, California" D. E. K'Vella, "A Semi-Analytical Model for Hot Water Surfactant Flooding in a Linear Reservoir with Heat Losses" G. P. Wilthite, "Welibore Refluxing in Steam Injection Wells" P. Toma, "A New Sand Control Filter for Thermal Recovery Wells" A. Sacuta, "Stability of Nickel-Coated Sands as Gravel Pack Material for Thermal Wells" V. Reitman, "The Effect of Injected Fluid Volume on Heavy Oil Displacement In a Porous Medium" T.W.J. Frauenfeld, "The Effect of an Initial Gas Content on Thermal EOR as Applied to Oil Sands" K. C. Hong, "Steam flood Strategies for a Steeply Dipping Reservoir" M. 0. Onyekonwu, "Experimental and Simulation Studies of Laboratory In Situ Combustion Recovery"

S. W. Lee, at al, "Determination of Fuel Aromatic Content and its Effect on Residential Oil Combustion," Canadian Combustion Research Laboratory.

The following papers were presented at the United States Department of Energy Tar Sand Symposium held on July 7, 1986 in Jackson, Wyoming: J. S. Randall, "Tar Sands - The Opportunity" R. S. Harrison, "The AOSTRA-ARC Joint Oil Sands Geology Programs: Regional Resource Studies of the Alberta Oil Sands Deposits" D. M. Wightman, "Resource Characterization and Depositional Modelling of the Clearwater Formation, Cold Lake Oil Sands Deposit, East Central Alberta" H. R. Rltzma, "Structural and Stratigraphic Controls, Uinta Basin Tar Sand Deposits, Northeast Utah" C. J. Schenk, "Geologic and Petrophysical Aspects of Some Tar Sands Near Surinyside, Utah" A. 0. Tammam, "The Geology of the Syncrude Oil Sand Leases" R. L. Oliver, "Major Tar Sand Deposits of Utah, United States: Recent Field Investigations" S. D. Joshi, "A Review of Horizontal Well Technology" R. H. Trent, "The Status of an Oil Mining Project" J. D. Scott, "Measuremenets of Thermophysieal and Mechanical Properties of Oil Sands" E. B. Wilson, "Techniques for the Measurement of Fracture Toughness of Oil Sands" W. Y. Svrcek, "VIscosity Predictions for Gas-Free Alberta Bitumens Using the Corresponding States Method" J. C. Brown, "Cerro Nero Heavy Petroleum - Separation and Analysis of Acid, Base, Saturate, and Aromatic Fractions" S. A. Holmes, "Saturated Hydrocarbon Distributions in Bitumens and in Oils Recovered by Thermal Processes" R. H. Jacoby, "Phase Behavior and Properties of Mixtures of Light Hydrocarbons with Athabasca Tar or Heavy Crude with Applications for Recovery Processes" It. L. Magnie, "The Potential Role of Hydrogen from Low-BTU Gas in Heavy Oil and Tar Sands Extraction Technology" C. W. Ware, "An Advanced Thermal EOR Technology" R. G. Moore, "Comparison of the Effect of Thermal Cracking and Low Temperature Oxidation on Fuel Deposition During In Situ Combustion" T. N. Nasr, "Parametric Study of the Steam Injection Process for Heavy Oil Recovery" L. A. Johnson, "Comparison of Laboratory and Field Steamflooth in Tar Sand" P. Vaughn, "Mathematical Modelling for In Situ Thermal Recovery in Tar Sand: Model Description and Verification" James Warriner, "Acoustic Emissions for the Determination of Production Front Locations in Tar Sand"

3-46 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 L. J. Romanowski, "Laboratory Studies of Forward Combustion in Tar Sand (Tar Sand Triangle)? B. R. McMullin, "Application of Marine Geophysical Techniques for Monitoring Tailings Pond Development at the Syncrude Canada Ltd. Oil Sands Plant in Northeast Alberta" A. Majid, "Preliminary Assessment of Agglomeration Techniques for Bitumen Separation from Storage Tank Sludge from a Heavy Oil Project and a Sample of Centrifuge Rejects After Naphtha Recovery" T. W. Owen, "The Effect of Water Treatment Alternatives on Water Demands for In Situ Production of Bitumen" S. S. Barrell, "Administrative, Economic, Environmental and Legal Hurdles to Tar Sand Development in Wyoming: A Case Study" J. D. Seader, "Design and Economic Evaluation of an Energy-Integrated Thermal Process for Recovery of Oil from Tar Sands" L. C. Lin, "A Preliminary Mathematical Model of Bitumen-Impregnated Sandstone Pyrolysis in a Fluidized Bed" M.Misra, "Processing and Development of Alabama Tar Sands" Giuliano Porcari, "The TRA DAP Tar Sands Extraction Process" R. D. Daniel, "Demonstration Plant Design and Economics of the Beaver-Herter Extraction Process" S. B. Sprague, "Upgrading Cold Lake Bitumen Using the HSC-ROSE Process" F. W. Wenzel, "VEBA-Combi-Cracking (VCC), A Proven Technology for High Conversion of Heavy Bottoms" W. E. Harrison, Ill, "Production of Aviation Turbine Fuels from Utah and Kentucky Bitumens" Henry Sawatzky, "Utilization of Synthetic Crude Processing Residues in Asphalt Blends" J. W. Bunger, "Competing Reactions in the Upgrading of Residual Oils" John Ivory, "Development and Testing of a Synthetic Cold Lake Oil Sand" B. B. Maini, "Effects of Temperature on Heavy Oil-Water Relative Permeability of Sand" B. B. Maini, "On the Use of the Pulse Technique for Minimizing Damage During Core Tests in Heavy Oil Systems" P. Fransham, "Displacement of Heavy Oil Visualized by CAT Scan" Mori Y. Kwan, "Application of the Pulse-Decay Technique to the Measurement of Heavy Oil Core Fluid Mobilities and Porosity"

OIL SANDS - PATENTS "Method of Making Carbon Black Having Low Ash Content from Carbonaceous Materials," Wenjai R. Chen and Robert L. Savage - Inventors, United States Patent 4,590,0056, May 20, 1986. A partial combustion method of producing commercially acceptable carbon black containing less than approximately I percent ash from carbonaceous material taken from the group consisting of coal, lignites, tar sand, pitch, oil shale, and asphaltic substances, which comprises reacting the carbonaceous material with oxygen at a temperature of from 2,000°F to 3,000°F, the carbonaceous material having an average particle size of from 75 microns to 1,700 microns and wherein the oxygen to carbonaceous material weight ratio is no more than 0.4, and recovering the carbon black from the reaction. "Use of Ethers in Thermal Cracking," Partha S. Ganguli - Inventor, HE! Inc., United States Patent 4,592,826, June 3, 1986. A process for improving the upgrading/conversion of hydrocarbonaceous materials such as coals, petroleum residual oils, shale oils, and tar sand bitumens. In the process, the free radicals formed from thermal cracking of the hdyrocarbons are reacted with the free radicals formed by the thermal cracking of a free radical forming chemical reactant, such as dimethyl ether, to yield stable low molecular weight hydrocarbon distillate products. The hydrocarbonaceous feed material is preheated to a temperature of 600° to 700°F, and the hydrocarbon and the free radicals forming chemical, such as dimethyl ether, are passed through a now reactor at temperature of 750 0 to 9000F, pressure of 200 to 1,000 psi, and liquid hourly space velocity of 0.3 to 5.0 LHSV. Free radicals formed from the hydrocarbon feed material and from the ether material react together in the reactor to produce low molecular weight hydrocarbon liquid materials. The weight ratio of ether material to hydrocarbon feed material is between about 0.3 and about 2.0. "Conversion of High Boiling Organic Materials to Low Boiling Materials," Curtis D. Coker and Stephen C. Paspek, Jr. - Inventors, United States Patent 4,594,141, June 10, 1986. A process for the conversion of high boiling saturated organic materials is described. The method comprises contacting said high boiling organic materials at a temperature of at least about 300°C and at a reaction pressure of at least about 2,000 psi with an aqueous acidic medium containing at least one

3-47 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 olefin, and a halogen-containing comound selected from the group consisting of a halogen, a hydrogen halide, a compound which can form a halide or a hydrogen halide in the acqueous acidic medium under the process conditions, or mixtures thereof whereby the high boiling organic material and aqueous acidic medium form a substantially single phase system. Optionally the process can be conducted in a reducing atmosphere. The process of the invention is useful for producing and recovering fuel range liquids from petroleum, coal, oil shale, shale oil, tar sand solids, bitumen, and heavy hydrocarbon oils such as crude oil distillation residues which contain little or no carbon-carbon unsaturation. Preferably, the halogen compound Is at least one halogen or a hydrogen halide. "Two-Stage Tar Sands Extraction Process," James S. Patterson and William F. Wolff - Inventors, Amoco Corporation, United States Patent 4,596,651, June 24, 1986. A method for extracting bitumen from tar sands, wherein the tar sands contain at least 3 weight percent connate water, comprising initially contacting the bitumen with a specific solvent in a first extraction stage and thereafter contacting the bitumen with both a non-specific solvent and a specific solvent in a second extraction stage, whereby a bitumen product low in asphaltenes and fines is obtained. A method for extracting bitumen from tar sands, wherein the tar sands contain less than 3 weight percent connate water, comprising: (a) initially slurrying the tar sand with a non-specific solvent to dissolve a substantial portion of the available bitumen in a first extraction stage; (b) separating the bitumen-containing solvent from the slurry solids; (c) contacting the bitumen- containing solvent with a specific solvent to precipitate asphaltenes and fines in a second extraction stage; (d) separating the tines and asphaltenes from the bitumen containing solvents; and (e) recovering the bitumen from the solvents.

"Process for Breaking Emulsions Produced During Recovery of Bitumens and Heavy Oils," Marc-Andre Poirier (of Canada) - Inventor, Her Majesty Queen in Right of Canada Minister of Energy Mines, United States Patent 4,600,501, July 15, 1986. A process for breaking stable oil-in-water emulsions formed during recovery of bitumen or heavy oil consisting essentially of contacting the emulsion with a high-ash particulate agent having a particle size less than 60 mesh, containing at least 60 percent by weight of ash on a dry weight basis and selected from the group consisting of fly ash obtained from the coking of bitumen, red mud, and high ash coal rejects.

3-48 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS

COMMERCIAL PROJECTS

ATIJABASCA PROJECT - Solv-Ex Corporation and Shell Canada Limited (T-01) The project is a joint venture of Sotv-Ex and Shell Canada Limited to undertake the phased development of an open pit mine and extraction plant for bitumen on Shell's oil sands lease in Alberta, Canada. Phase I of the project includes a detailed engineering study and a 1,500 metric tonnes run of oil sands through the Solv-Ex pilot plant, located in Albuquerque, New Mexico. Pending successful results of the testing and acceptable economic forecasts, the construction of the mine and plant complex (Phase II) would begin, with completion targeted for some time in 1990. The mine will provide 16,275 tons of ore per day to the extraction plant, which will use the Solv-Ex technology. About 7,500 barrels of bitumen per calendar day are expected to be produced, the product to be sold as bitumen or upgraded to synthetic crude at additional cost. The Government of Alberta and the Alberta Oil Sands Technology and Research Authority have agreed to provide financial assistance to the project in the form of a loan guarantee for Phase II of 30 percent of costs up to C$85 million, plus capitalized interest, and a C$3 million grant for Phase I, respectively. Work on Phase I is already underway.

Project Cost: C$260 million (Phase II) C$10 million (Phase I) BI-PROVINCIAL PROJECT - UPGRADER FACILITY -- Husky Oil Operations Ltd. (T-35) Husky Oil is planning a heavy oil upgrader to be located near the Alberta/Saskatchewan border at Lloydrninster, Saskatchewan. The facility will be designed to process 54,000 barrels per day of heavy oil and bitumen from the Lloyd.ninster and Cold Lake deposits. The primary upgrading technology to be used at the upgrader will be H-Oil ebullated bed hydroeracking followed by delayed coking of the hydroeracker residual. Engineering and design of the plant was initiated in June 1984 under terms of an agreement between Husky Oil Operations Ltd. and the governments of Canada, Alberta, and Saskatchewan which provide loan guarantees and royalty concessions. In April 1986, Husky and the governments reviewed the terms of this agreement and established alternative conditions. Under the new agreement Husky will complete the design engineering for the project and prepare a definitive cost estimate as Phase I of the project. Following these Phase I activities the governments and Husky will review the cost estimate in March 1987 and will establish the financial terms for continuation of the project under Phase II, detailed engineering and construction. To date licensor engineering for the H-Oil and Hydrotreating Units has been completed. Licensor engineering for the Delayed Coking Unit will be complete by August 1986. Licensor engineering for the Sulfur Plant will be initiated in June 1986. Engineering contracts for each of the five process plants and for the Utilities and Offsites have been awarded as follows: Primary Upgrading Plant PCL-Braun-Simmous Ltd. Secondary Upgrading and Crude Plants Bantrel Group Engineers Ltd. Hydrogen Plant SNC/FW Ltd. Utilities and Offsites Partec-Lavalin Inc. Sulfur Plant (Phase I) Monenco Engineers and Constructors Inc. Delayed Coker Foster-Wheeler U.S.A. Corporation Work on Phase I activities is underway for all plants.

Project Cost: Upgrader Facility estimated at C$1.4 billion BURNT LAKE - Suncor Inc. (T-02) In early 1985 Suneor purchased oil sands leases and petroleum and natural gas leases from Dome Petroleum for $79 million. In October 1985 an application was filed for a commercial heavy oil project on a portion of these newly acquired leases (just north of Suncor's Fort Kent plant). As at Fort Kent the method of recovery will be cyclic steam injection.

349 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Total reserves on this lease are estimated to be approximately 1,455 million barrels of which about 200 million are recoverable. The project scope will result in an ultimate capacity of 25,000 barrels per day froma total of 2,000 wells. The project is planned in four stages. The Stage I phase of the program will involve 110 wells. These wells will be drilled in clusters of 25 to 30 within an area of about 150 feet in diameter. Individual clusters will be spaced about one per 5,5 acres. Total capital costs are estimated at $1.3 billion (1985 dollars). Project Cost: $1.3 billion CALIFORNIA TAR SANDS DEVELOPMENT PROJECT - California Tar Sands Development Corporation (T-06) California Tar Sands is developing a downholc hydraulic mining system whereby oil sands occurring at depths from 100 to 600 feet will be mined using a hydraulic mining tool. Bitumen will be extracted from the sand using a surface removal process. Operations will take place in California and Canada. Project Cost: $547 million CANSTAR - Nova - An Alberta Corporation, Petro-Canada (T-10) The recent decline in oil price has caused Petro-Canada and Nova to re-examine the appropriateness of continuing to invest in their joint venture company, Canstar Oil Sands Ltd. Canstar was formed in 1980 to investigate the feasibility of building and operating a mineable oil sands plant in northern Alberta. Economic and political pressures led to a severe curtailment of expenditures in 1982. Canstar has continued at this reduced level of activity since then. Nova and Petro-Canada have now decided to suspend further expenditures on Canstar. Canstar Oil Sands Ltd. will continue to exist as a corporate body, but resumption of work will depend on general economic conditions. COLD LAKE PROJECT - Esso Resources Canada Limited (T-20) In September 1983 the Alberta Energy Resources Conservation Board (AERCB) granted Esso Resources Canada Ltd. approval to proceed with construction of the first two phases of commercial development on Esso's oil sands leases at Cold Lake. Subsequent approval for Phases 3 and 4 was granted in June 1984 and for Phases 5 and 6 in May 1985. Shipments of diluted bitumen from Phases 1 and 2 started in July 1985. By the end of 1986, commercial bitumen production at Cold Lake will average 55,000 barrels oil per day. The AERCB has approved Esso's application to add another expansion of 6,000 cubic meters per day at an estimated cost of $400 million. Cyclic steam stimulation is being used to recover the bitumen. Processing equipment consists of a water treatment and steam generation plant and a treatment plant which separates produced fluids into bitumen, associated gas and water. Plant design allows for all produced water to be recycled. Project Cost: $600 million DAPHNE PROJECT - Petro-Canada (T-25) Petro-Canada is studying a tar sands mining/surface extraction project to be located on the Daphne leases near Fort McMurray, Alberta. The proposed project would produce 73,000 barrels per day. Based on mining studies by Loram International Ltd., engineering studies by Bechtel Canada Ltd., and continuing internal studies by Petro-Canada. The project is expected to cost $4.1 billion (Canadian). During the 1984/1985 winter 117 core holes were drilled at the site to better define the resource. Federal and provincial government agencies have been contacted to discuss reduced royalty and tax schemes, but no agreements have been reached. Petro-Canada has also discussed the project with other companies that may be interested in acquiring equity shares in the project. Project Cost: $4 billion (Canadian) DIATOMACEOUS EARTH PROJECT - Texaco Inc. (T-30) Texaco has placed its Diatomite Project, located at McKittrick in California's Kern County, in a standby condition. The Project will be reactivated when conditions in the industry dictate. The Company stressed that the Project is

3-50 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

not being abandoned, but is being put on hold due to the current worldwide energy supply picture. The Lurgi pilot unit is being maintained in condition for future operations. The Company estimates that the Project could yield in excess of 300 million barrels of 21 0 to 230API oil from the oil-bearing diatomite deposits which lie at depths up to 1,200 feet. The deposits will be recovered by open pit mining and back filling techniques.

Project Cost: Undetermined ELK POINT PROJECT-- Amoco Canada Petroleum Company, Ltd. (T-21) The Elk Point Project area is located approximately 165 kilometers east of Edmonton, Alberta. Amoco Canada holds a 100 percent working interest in 6,600 hectares of oil sands leases in the area. The Phase 1 Thermal Project is located in the NW 1/4 of Section 28, Township 55, Range 6 West of the 4th Meridian. The primary oil sands target in the area is the Lower Cummings sand of the Mannville Group. Additional oil sands potential is indicated in other Mannville zones including the Colony, Clearwater, and the Sparicy. Amoco Canada has several development phases of the Elk Point Project. Phase I of the Project will involve the drilling, construction, and operation of a 13-well Thermal Project (one, totally enclosed 5-spot pattern), a continuation of field delineation and development drilling and the construction of a product cleaning facility adjacent to the Thermal Project. The delineation and development wells are drilled on a 16.19 hectare spacing and are cold produced and/or huff-puff stimulated during Phase 1. Construction of the Phase 1 Thermal Project and cleaning facility was initiated in May 1985. The cleaning facility has been operational since October 1985. Further development of the Project to the planned second phase will depend on future heavy oil market demand and pricing.

Project Cost: Phase 1 - $50 Million (Canadian) FOREST HILL PROJECT - Greenwich Oil Corporation (T-26) Greenwich Oil Company is developing a project which entails modification of existing, and installaton of additional, injection and production wells to produce approximately 1,750 barrels per day of 10° API crude oil by a fire flooding technique utilizing injection of high concentration oxygen. Construction began in the third quarter 1985. Loan and price guarantees were requested from the United States Synthetic Fuels Corporation under the third solicitation. On August 21, 1985 the Board directed their staff to complete contract negotiations with Greenwich by September 13, 1985 for an award of up to $60 million. Contract was signed on September 24, 1985. Project is in the start-up phase with five injection wells taking 75 tons per thy of 90 percent pure oxygen. Project Cost: Estimated $42.5 million *FROG LAKE PROJECT -- PanCanadian Petroleum Ltd. (T-29) PanCanadian applied to the Alberta Energy Resources Conservation Board (ERCB) for approval of Phase I of a proposed 3 phase commercial bitumen recovery project. Approval by the ERCU is expected. The Phase I project, costing C$90 million, would involve development of primary and thermal recovery operations in the Elk Point, Frog Lake area of the Lindbergh Field in east-central Alberta. Phase I operations would include 113 wells already drilled. Several other existing wells in the proposed project area were drilled for pilot projects that PanCanadian plans to continue. An additional 165 Phase I wells would be drilled over the project's 20 years life. PanCanadian requested permission to develop two sections for steam stimulation of the Cummings sand formation. The wells would be drilled in a seven-spot pattern on 4 hectare (10 acre) spacing. PanCanadian expects to develop one-quarter section every two years. Phase I would also include primary development of 14 sections with a maximum of 16 wells per section on 16 hectare (40 acre) spacing. The arrangement and spacing of primary wells would allow their use in future thermal recovery operations. PanCanadian expects Phase I recovery to average 3,145 barrels per day of bitumen, with peak production at 4,403 barrels per day. Tentative plans call for Phase II operations starting up in 1990 with production to increase to 6,290 barrels per thy by 1991. Phase Ill would go into operation in 1992, and 300 new wells would be drilled on six sections. Production would increase to 12,580 barrels per day. Phases II and Ill would be developed as thermal recovery projects. After cyclic steaming, the patterns would be converted to steamfloods or firefloods.

3-51 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Although the schedule is likely to be reduced from that originally proposed to the ERCB in 1986, the company indicates that it plans to keep the project alive.

Project Cost - Phase I = C$90 Million LINDBERGH COMMERCIAL PROJECT -- Dome Petroleum Limited (T-32) Dome Petroleum received approval from the Alberta Energy Resources Conservation Board for a commercial project in Lindbergh. The project will cover five sections and and waslanpned to be developed at a rate of one section per year for five years. It will employ "huff-and-puff" steaming of wells drilled on 10 acre spacing, and will require capital investment of approximately $158 million (Canadian). The project is expected to encompass a period of 12 years and will result in peak production of 12,000 barrels of oil per day, which when coupled with production from two experimental plants and additional wells will raise the daily area production to about 15,000 barrels per day. Mm to the dinrnntle decline of oil orices. drillinif on the first ohase of the commercial project has been halted after

Project Cost: $158 Million LINDBERGH COMMERCIAL THERMAL RECOVERY PROJECT -- Murphy Oil Company Ltd. (T-33) Murphy Oil Company Ltd., is commencing a commercial thermal recovery project in the Lindbergh area of Alberta. Project development is planned in four separate phases over nine years, with a total project life of 30 years. The first phase of the commercial expansion is underway with the addition of 53 wells in 1985 and construction of an oil plant, water plant, and water source intake and line from the north Saskatchewan River. Startup has been postponed pending satisfactory oil pricing. Murphy has been testing thermal recovery methods in a pilot project at Lindbergh since 1974. Based on its experience with the pilot project at Lindbergh, the company expects recovery rates in excess of 15 percent of the oil in place. Total production over the life of this project is expected to be in excess of 12 million cubic meters of heavy oil. Experiments with follow-up production techniques, which may improve recovery rates even further, are continuing at the pilot project. The project will use a huff-and-puff process with about two cycles per year on each well. Production will be from the Lower Grand Rapids zone at a depth of 1,650 feet. Oil gravity is 11 0 &PI, and oil viscosity at the reservoir temperature is 100,000 centipose. As production from the initial wells declines, replacement wells will be drilled and brought on stream, to maintain production. An average of 18 new wells will be drilled each year. The wells will be directionally drilled outward from common pads, reducing the number of surface leases and roads required for the project. Capital costs of Phase I will be roughly $30 million (Canadian) for the initial installations, with about $6 million in capital additions for each succeeding year to drill and tie in the replacement wells. Operating expenditures will be in the order of $12 million per year. Development of future phases will be dependent on satisfactory performance in Phase I and successful production tests at the intended locations for these phases. A tentative schedule is to commence construction of Phase II in 1988, Phase Ill in 1990, and Phase IV in 1992. Total production from all four phases would be 10,000 barrels per day.

Project Cost: $30 million (Canadian) capita! cost $12 million (Canadian) operating costs plus $6 million capital additions annually

LLOYDMINSTER REGIONAL UPGRADER -- (See Bi-Provincial Project-Upgrader Facility) NEWGRADE HEAVY OIL UPGRADER - NewGrade Energy, Inc., a partnership of Consumers Co-Operative Refineries Ltd. and the Saskatchewan Government (T-35.2) Site work has been started for the $650 million upgrader project to be built adjacent to the Co-Operative refinery in Regina, Saskatchewan. The 50,000 barrels per thy heavy oil upgrading project was originally announced in August 1983. Co-Operative Refineries will provide 5 percent of the costs as equity, while the provincial government will provide 15 percent. The federal government and the Saskatchewan government will provide loan guarantees for 80 percent of the costs as debt.

SYNTHETIC FUELS REPORT, SEPTEMBER 1986 3-52 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Newcrade has selected process technology licensed by Union Oil of California for the upgrader which will provide 30,000 barrels per day of upgraded crude. Project Cost: $650 million PEACE RIVER COMMERCIAL EXPANSION --Shell Canada Limited (T-35.5) Shell Canada Limited is expanding the existing Peace River In Situ Pilot Project to an average production rate of 10,000 barrels per day. 'The expansion will be located adjacent to the existing pilot project, approximately 55 kilometers northeast of the town of Peace River, on leases held jointly by Shell Canada Limited and Shell Explorer Limited. The expansion, at an estimated cost of $200 million, will require the drilling of an additional 212 wells for steam injection and bitumen production, plus an expanded distribution and gathering system. Wells for the expansion will be drilled diectionally from eight common pads. The commercial project will also include an expanded main complex to include facilities for separating water, gas, and bitumen; a utility plant for generating steam; and office structures. Additional oft-site facilities will also be added. No upgrader is planned for the expansion; all bitumen extracted will be diluted and marketed as a blended heavy oil. The diluted bitumen will be transported by pipeline and initially would be exported to the northern tier refineries in the United States for asphalt production. An application to the ERCB received approval in early November 1984. Drilling began in February 1985. Construction began June 1985. The expansion is planned to be on stream late 1986. This expansion is only the first step of Shell's long-term plan to develop the Peace River oil sands. If successful, a further expansion could follow in the early 1990s. Additional phased expansion could occur over a 30 year period. Project Cost: $200 million PORTA-PLANTS PROJECT -- Porta-Plants, Inc. (T-36) Porta-Plants, Inc., is proposing a project near Roosevelt, Utah to produce 1,000 barrels per day of bitumen from high-grade Utah tar sands utilizing an optimized hot water disengagement and selective cohesion process. The first phase (for which SFC assistance was not requested) involves construction of a 10 barrels per day plant to be operational in 1987. Superior yields have been proven. A heavy oil upgrading process has not been chosen. Processes being considered include: Dynacracking, ART, and hydrotreating. Construction of the 1,000 barrels per day facility would follow on the same site, with start-up scheduled for October 1988. Price and loan guarantees were requested from the United States Synthetic Fuels Corporation (SFC) under Production costs will be $12.92 per barrel including operation and equipment.

Project Cost: 10 barrels per day Plant: $5,000,000 100 barrels per day plant: $10,000,000 1,000 barrels per day Plant: $27,500,000 PRIMROSE LAKE COMMERCIAL PROJECT - Dome Petroleum Ltd. (T-38) Dome has proposed a 25,000 barrels per day commercial project in the Primrose area of northeastern Alberta. Dome is earning a working interest in certain oil sands leases from Alberta Energy Company. Following extensive exploration, the company undertook a cyclic steam pilot project in the area, which commenced production in November 1983, and thereby earned an interest in eight sections of adjoining oil sands leases. The 41 well pilot was producing 2,000 barrels per day of 10°API oil in 1984. The agreement with Alberta Energy contemplates that Dome can earn an interest in an additional 225,000 acres of adjoining oil sands lands through development of a commercial production project. The project is estimated to carry a capital cost of at least $C1.2 billion and annual operating cost of $C140 million. Total production over a 30 year period will be 190 million barrels of oil or 18.6 percent of the oil originally in place in the project area. Each year for the first five years Dome will start a new 400 well, 5,000 barrels per day stage. Each stage will cover four sections with sixteen 26 well slant-hole drilling clusters. Each set of wells will produce from 160 acres on six acre spacing. The project received Alberta Energy Resources Conservation Board approval on February 4, 1986. Due to the dramatic decline in oil prices, the proposed 1986 drilling schedule has been postponed. The project will proceed when oil prices return to levels which make the project viable. In January 1984, Dome entered into an agreement with Pangaea Petroleum Ltd. and Canadian Hunter Exploration Inc., which permits those companies to earn a total of 25 percent of Dome's interest in the Primrose pilot recovery project and the proposed commercial production facility. Under this agreement, the two companies have reimbursed

353 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Dome for approximately $20 million of its costs for the pilot recovery project and will pay one-half of future expenditures on the commercial production project. The two companies also have the right to earn a 15 percent working interest in any subsequent projects for the recovery of bitumen from the Alberta Energy lands.

Project Cost: $1.2 billion (Canadian) capital cost $140 million (Canadian) annual operating cost SARNIA-LONDON ROAD FIELD MINING ASSISTED PROJECT-- Devran Petroleum Ltd. and Shell Canada Ltd. (T-39) Devran and Shell Canada are proceeding with a $6.3 million project to recover 2 million barrels of oil from a long- dormant oil field near the southern tip of Ontario. Devran operates the mining-assisted oil recovery project near Sarnia, Ontario. Devran and Shell Canada jointly lease approximately 3,900 acres with 1,200 acres in the active field. Known as the Sarnia-London Road Field, the area was drilled by Imperial Oil from 1898 to 1901. Production rates from individual wells of two or three barrels of oil per day were recorded, with some wells reported to have initial producton rates of over 10 barrels per day. The Sarnia-London Road Field produced for 25 years, yielding a significant amount of natural gas with the oil. Unit A Is the first production project, designed to produce oil from approximately 600 acres. A shaft has been sunk to a depth of 430 feet, and two production stations have been established, one for each of two oil-bearing layers. Facilities to collect the oil and pump it to surface are included in these production stations. Conventional surface production facilities including a heater treater, tanks for storage of the oil, a service building, and a mine shaft house are in place. A total of 120,000 feet of horizontal drilling in the two oil layers will allow oil to flow freely along the paths provided by the holes. Production rate is expected to be on the order of 600 barrels daily. Satisfactory results from Unit A could lead to follow-up development of a second production facility based around a second shaft on Unit B to be located approximately I kilometer northwest of Unit A. Unit A is being financed by Devran and Shell Canada. Devran received a $450,000 grant from the Federal Ministry of Energy, Mines and Resources and a $100,000 grant from the Ontario Provincial government. Financing is also facilitated by the qualification of this project under federal government tax incentives encouraging investment in Canadian petroleum exploration. The procedure being applied Involves three major steps. First, a mine shaft is sunk to the oil layer. Next, a production station is excavated where the shaft passes through or reaches the oil layers (the pay zone). Finally, the production station becomes the site from which holes are drilled horizontally in a radial or "wagon wheel" pattern into the pay zone. Each production station with its set of wells drains by gravity several hundred acres. The length of these horizontal wells is determined by the formation geometry and geological conditions. Project Cost No disclosed SCOTFORD SYNTHETIC CRUDE REFINERY - Shell Canada Limited (T-40) The project is the world's first refinery designed to use exclusively synthetic crude oil as feedstock, located northeast of Fort Saskatchewan in Strathcona County. Initial capacity is 50,000 barrels per day with the design allowing for expansion to 70,000 barrels per day. Feedstock is provided by the two existing oil sands plants. Products also include butane, propane, and sulfur. The refinery's petroleum products are gasoline, diesel and jet fuel and stove oil. Shell has 100 percent interest in the refinery and the benzene manufacturing facilities associated with the refinery are owned by Shell Canada Limited. Refinery and petrochemical plant officially opened September 1984.

Project Cost: $1.4 billion (Canadian) total final cost for all (refinery, benzene, styrene) plants. SELECTIVE CATALYTIC COHESION PROJECT - Porta-Plants, Inc. (see Porta-Plants project)

SUNCOR, INC., OIL SANDS GROUP - Sun Oil Company (72.8 percent), Ontario Energy Resources Ltd. (25 percent), publicly (2.2 percent) (T-50) Suncor Inc. was formed in August 1979, by the amalgamation of Great Canadian Oil Sands and Sun Oil Co., Ltd. In November 1981 Ontario Energy Resources Ltd., acquired a 25 percent interest in Suncor Inc. Suncor Inc. is comprised of three major groups: Resources Group, Sunoco Group, and Oil Sands Group. The Resources Group is sub-divided into three divisions: Exploration, Production, and Resources Development. The Sunoco Group refines and markets petroleum products. The Oil Sands Group is explained in the following paragraphs.

354 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Oil Sands Group operates a commercial oil sands plant located in the Athabasca bituminous sands deposit 30 kilometers north of Fort McMurray, Alberta. It has been in production since 1967. A four-step method is used to produce synthetic oil. First, overburden is removed to expose the oil-bearing sand. Second, the sand is mined and transported by conveyors to the extraction unit. Third, hot water and steam are used to extract the bitumen from the sand. Fourth, the bitumen goes to upgrading where thermal cracking produces coke, and cooled vapors form distillates. The distillates are desulfurized and blended to form high-quality synthetic crude oil, most of which is shipped to Edmonton for distribution. Current estimated remaining reserves of synthetic crude oil are 370 million barrels. The plant has received world price for its oil which has ranged from $17 to $45 (Canadian) per barrel over the last few years. Project Cost: Not disclosed SUNNYSIDE TAR SANDS PROJECT-- GNC Tar Sands Corporation (T-590) A 240 tons per day (120 barrels per thy) tar sands pilot was built by ONC in 1982 in Salt Lake City, which employs ambient water flotation concentration which demonstrated that tar sands could be concentrated by selective flotation from 8 percent bitumen as mined to a 30 to 40 percent richness. Chevron in 1983 built and operated a solvent leach unit that, when added in back of a flotation unit at Colorado School of Mines Research Institute in Denver, produced a bitumen dissolved in a kerosene solvent with a ratio of 1:3 which contained 5 percent ash and water. Chevron also ran a series of tests using the solvent circuit first followed by flotation and found it to be simpler and cheaper than the reverse cycle. Kellogg, in a series of tests during 1983/1984, took the product from the CSMRI tests and ran it through their Engelhard ARTCAT pilot plant in Houston and produced a 27 0API crude out of the 10 percent API bitumen, recycled the solvent, and eliminated the ash, water, and 80 percent of the metals, nitrogen, and sulfur. Today GNC has a complete process that on tests demonstrates 96 to 98 percent recovery of mined bitumen through the solvent and flotation units and converts 92 percent of that stream to a 27°API crude with characteristics between Saudi Light and Saudi Heavy. GNC has 2,000 acres of fee leases in the Sunnyside deposit that contain an estimated 307 million barrels of bitumen. It has applied to BLM for conversion of a Sunnyside oil and gas lease to a combined hydrocarbon lease. The company has contracted Morrison-Knudsen for mining and upgrading. The first commercial facility will be 5,000 barrels per thy. In response to a solicitation by the United States Synthetic Fuels Corporation (SEC) for tar sands projects that utilize mining and surface processing methods, GNC requested loan and price guarantees of $452,419,000. Construction would start in the third quarter 1986 with first production in the first quarter 1989. On November 19, 1985 the SPC determined that the project was a qualified candidate for assistance under the terms of the solicitation. On December 19, 1985, the SFC was cancelled by Congressional action. GNC is now attempting to finance independently of United States government assistance. Studies have been completed by M. W. Kellogg indicating feasibility, after the decline in prices beginning in January 1986 of a 7,500 barrels per day plant which converts the ART-treated bitumen to 31 percent gasoline and 69 percent diesel. The 7,500 barrels per day plant, with some used equipment, would cost $149 million. Project Cost: $149 million for 7,500 barrels per day facility

SYNCRUDE CANADA, LTD. - Alberta Energy Company (10 percent); Alberta Oil Sands Equity (16.74 percent); Canadian Occidental Petroleum Ltd. (13.23 percent); Esso Resources Canada Limited (25 percent); Gulf Canada Resources Inc. (9.03 percent); Dome Petroleum Limited (agent for HBOG Oil Sands Limited Partnership) (5 percent); PanCanadian Petroleum Limited (4 percent); Petro-Canada Ventures Inc. (17 percent) (T-60) Located near Ft. McMurray, the plant has an allowable production of 138,600 barrels per calendar thy; however, current capacity is 128,000 barrels per calendar day and has been in early stages of production since July 31, 1978. Mining—electric draglines; extraction—hot water flotation process; upgrading—two fluid cokers. Canadian Bechtel Ltd. was managing contractor. In 1979, 18 million barrels of synthetic crude were delivered. Production in 1980 was over 28 million barrels; production in 1981 was over 29.7 million barrels. The 1982 production figure was 31.32 million barrels, and 1983 was 40.8 million barrels, 1984 was 31.2 million barrels, and 1985 was 46.7 million barrels. All major equipment is in place and operational; four draglines and four bucketwheels working. Syncrude's staff is 4,200. A $1.2 billion capacity addition project and expansion now underway will increase synthetic crude oil production to 138,600 barrels per thy. The expansion is expected to be complete by 1989. Project Cost: Total cost $2.3 billion (1978 cost)

3-55 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

WOLF LAKE PROJECT— BP Canada Resources Ltd. and Petro-Canada (T-680) Located 30 miles north of Bonnyville near the Saskatchewan border, on 75,000 acres, the Wolf Lake commercial oil sands project (a joint venture between BP Canada Resources Ltd. and Petro-Canada) was completed and began production in April 1985. Production at designed capacity of 7,000 barrels per day was reached during the third quarter 1985. The oil is extracted by the "huff-and-puff" method. Nearly two hundred wells were drilled initially, then steam injected. As production from the original wells declines more wells will be drilled. Twenty-two wells were drilled in 1981 to determine a site for the plant. Application to the ERCB was approved in September 1982. An EPC contract for the Central Plant was awarded to Saturn Process Plant Constructors Ltd., in August 1983. Construction was complete in the first quarter 1985, 5.5 months ahead of schedule. Drilling of welts began October 15, 1983 and the initial 192 wells were complete in early July 1984, 7.5 months ahead of schedule. An estimated 720 wells were needed over the expected 25-year life of the project. Because the site consists mostly of muskeg, the wells will be directionally drilled in clusters of 20 from special pads. The bitumen is heavy and viscous (100API) and thus cannot be handled by most Canadian refineries. There are no plans to upgrade the bitumen Into a synthetic crude; much of it will probably be used for the manufacture of asphalt or exported to the northern United States. The project is going ahead largely due to tax and royalty concessions by both federal and provincial governments. In early 1983 the Canadian federal government announced that new oil sands and heavy oil projects would be exempted from the Petroleum and Gas Revenue Tax until capital costs have been recovered. The Alberta government has indicated that during the early years of the project the province will levy only a nominal royalty. This royalty initially could be as little as 1 percent, possibly increasing to as much as 30 percent of net profits once the project sponsors recover their investment. BP and Petro-Canada are now exploring options for future plants on the Marguerite Lake leases. During the winter of 1984/1985 an extensive delineation drilling program was carried out which identified possible areas for future

Wolf Lake Phase 2 would be followed by Phases 3 and 4 at one to two year intervals. SF's production target is 7,000 cubic meters per day in the 1990s (44,000 barrels per day). (Also see Marguerite Lake Phase A Pilot and Marguerite Lake B Unit Experimental Test.) Estimated Cost: $114 million (Canadian) (Additional $750 million over 25 years for additional drilling)

ABC COLD LAKE PILOT - Alberta Oil Sands Technology and Research Authority (AOSTRA), Bow Valley Industries Ltd., and Cold Lake Heavy Oil Ltd. (T-85) The project is operated by Bow Valley Industries Ltd. The process utilizes superheated steam, carbon dioxide, and chemicals to recover bitumen from the Clearwater formation. This technology was developed by Carmel Energy of Houston, and partially tested in heavy oil fields in the United States. The first phase involved drilling seven wells directionally from a single pad, in a hexagonal configuration. A possible second phase would encompass 18 additional wells. The project is located on a Gulf Canada lease in the Cold Lake area of Alberta, Canada on which Gulf operated a & well pilot several years ago. Bow Valley has a farm-in arrangement with Gulf and utilizes some of the surface facilities built for the Gulf pilot. Steam injection began in mid-January 1985. Steam, carbon dioxide, and other chemicals are injected and the well is left to soak for a period of time. Gas migrates out of the heated zone into the cold oil zone, goes into solution in the oil, reducing its viscosity. The well is then put on production with back pressure and the gas comes out of solution to provide a gas depletion drive mechanism. After the individual wells achieve "link-up" with this cyclic procedure, the pilot may be converted to a steam drive. Carbon dioxide is trucked in to the pilot facility. Project Cost: $15 million for the first phase

3-56 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

ANZAC PILOT PROJECT --(see GLISP Project) ASPHALT RIDGE TAR SANDS PILOT PLANT - Sohio Shale Oil Company (T-120) A surface mining project located on approximately 8,550 acres in Uintah County, Utah. Process selection and development work and economic feasibility studies are on hold, pending resolution of litigation and improvement in market. Several unpatented mining claims were patented. Application for federal combined hydrocarbon leases on remainder of unpatented claims has been made. Project Cost: Undisclosed ATHABASCA IN SITU PILOT PROJECT - Alberta Oil Sands Technology and Research Authority, Canterra Energy Ltd., Tenneco Oil of Canada, Ltd. (T-130) The Canterra/TECAN/AOSTRA steamflood pilot commenced operation during December 1981 in one of its two patterns. The first pattern consists of 6 producers, 7 injectors, 8 observation wells inside the pattern and 3 outside the pattern, 3 water source wells and 3 water disposal wells. A "modified" second pattern was started up in 1984. The modification consists of four new wells drilled to form a single 9-spot pattern with 8 producers and I injector. There are 2 observation wells inside the pattern and 4 outside the pattern. Results to date from the project have been encouraging. Tracers injected with the steam have been used to confirm reservoir fluid flow in the first pattern and a high rate gelled cold water free was used to establish fluid communication in the second pattern. The Alberta Oil Sands Technology and Research Authority (AOSTRA) has acquired a 25 percent interest in the project. Project Cost: $80 million (estimate) BATIRUM IN SITU WET COMBUSTION - Mobil Oil Canada, Ltd. (T-135) Mobil Oil Canada initiated dry combustion in 1965 and converted to wet combustion in 1978. This ongoing field project presently has nine burns and 133 production wells. Project Cost: Not disclosed BEAVER CROSSING THERMAL RECOVERY PILOT -- Chevron Canada Resources Limited. (T-140) The original project, a single-well experimental in situ project located at 36-61-2-W4M, was terminated in 1975. ERCO approval No. 2269 was issued April 18, 1977 for a 7-well cyclic experimental scheme for the recovery of crude bitumen from the Cold Lake Oil Sands Deposit. This approval was amended to locate the pilot in Section 31-61-1 W4. Construction began in early May 1977 with operation commencing in March 1978. Approval was further amended in November 1981 to convert to drive operation and extend expiration to 12/31/1984. Project consists of six producing wells, one steam injection well and eight temperature observation wells. A steam drive- producing well stimulation procedure is followed utilizing a 25 million BTU per hour generator. Ceased steam injection at end of 1984. Started heat scavenge phase in January 1985, by injecting all produced and make-up water. The project was finally shut-in October 1, 1985 and is presently in suspended status. Project Cost: $14 million (estimated) CAN MET HYDROCRACKING PROCESS - Canada Centre for Mineral and Energy Technology (CANMET), Petro-Canada, and Partec Lavalin Inc. (T-175) Based on the results of bench scale and pilot plant studies, a novel hydrocracking process has been developed at CANMET for the upgrading of bitumen, heavy oil, and residuum. This CANMET Hydrocracking Process is effective for the processing of heavy feedstocks with conversion of 90 weight percent of the pitch to distillate boiling below 524°C. (Pitch is defined as material boiling above 524°C.) An additive has been developed for the CANMET Hydrocracking Process which acts as a hydrogenating and coke-getting agent. High asphaltene conversions are achieved with the CANMET additive at comparatively moderate pressures and temperatures. Only moderate H2 consumption is required to achieve high levels of asphaltene and pitch conversion. This is attributed to the additive which primarily functions as a hydrogenating agent. Smooth and continuous pilot plant operations have been achieved with the CAN MET additive.

3_57 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

In 1979, Petro-Canada acquired an exclusive right to license the process. Petro-Canada formed a working partnership with Partec Lavalin Inc., a Canadian engineering company, for the marketing of the technology and the design and construction of a 5,000 barrels per stream day demonstration plant at the Petro-Canada refinery in Montreal. Following operation in hydro-visbreaking mode at 30 weight percent pitch conversion without additive since the fall of 1985, additive produced by a simplified method was introduced early in May 1986. While the original design levels of high conversion at design throughput have yet to be achieved, the current level of 80 percent conversion at somewhat reduced throughput Is considered to represent a substantial and encouraging achievement in the demonstration program. Design capacity of the unit at reduced conversion has also been achieved. The development program continues. Project Cost: Not disclosed CEDAR CAMP TAR SAND PROJECT - Enercor, Mono Power (T-190) Conceptual project to include a 50,000 barrels per day (maximum) tar sand processing plant associated with a surface mine in the PR Spring area. Modified hot water extraction would be employed. At present, reserves for a 20 year, 50,000 barrels per day plant are estimated, but not yet confirmed by an actual coring program. Project Cost: Not disclosed CELTIC HEAVY OIL PILOT PROJECT - Mobil Oil Canada, Ltd. (T-200) Mobil's heavy oil project is located in T52 and R23, W3M in the Celtic Field, northeast of Lloydmninster. The pilot consists of 25 wells drilled on five-acre spacing, with twenty producers and five injectors. There is one fully developed central inverted nine-spot surrounded by four partially developed nine-spots. The pilot was to field test a wet combustion recovery scheme with steam stimulation of the production wells. Air injection, which was commenced in October 1980, was discontinued in January 1982 due to operational problems. An intermittent steam process was initiated in August 1982. The fifth steam injection cycle commenced in May 1985 and operations are continuing. Project Cost: $21 million (Canadian) (Capital) CHARLOTTE LAKE PROJECT - Canadian Worldwide Energy Ltd., and others (T-205) Canadian Worldwide currently holds a 25 percent working interest in this 8,960 acre property located approximately 12 miles southeast of the town of Bonnyville. An agreement has been reached with Husky Oil Operations Ltd., to proceed with a $5 million pilot project to be completed by December 31, 1987. By completing this work, Husky will earn one-half of Canadian Worldwide's 25 percent interest. Two wells were drilled in late 1985, one of which was steamed and produced in early 1986, with encouraging results. The second well has been steamed, and is

Project Cost: $5 million CIRCLE CLIFFS PROJECT - Kirkwood Oil and Gas (T-220) Kirkwood Oil and Gas is presently forming a combined hydrocarbon unit to include all acreage within the Circle Cliffs Special Tar Sand Area, excluding lands within Capitol Reef National Park and Glen Canyon National Recreational Area. Project Cost: Not disclosed COLD LAKE STEAM STIMULATION PROGRAM - Mobil Oil Canada, Ltd. (T-230) A stratigraphic test program conducted on Mobil's 75,000 hectares of heavy oil leases in the Cold Lake area resulted in approximately 100 holes drilled to date. Heavy oil zones with a total net thickness of 30 meters have been delineated at depths between 290 and 460 meters. This pay is found in sand zones ranging in thickness from 2 to 10 meters. Single well steam stimulations began in 1982 to evaluate the production potential of these zones. Steam stimulation testing has subsequently expanded from three single wells to a total of eleven single welts in 1985. Various zones are being tested in the Upper and Lower Grand Rapids formation. The tests are scattered throughout Mobil's leases

3-58 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

in Townships 83 and 64 and Ranges 6 and 7. Some encouraging results have been observed and construction has begun on a central treating facility. Project Cost: Not disclosed DONOR REFINED BITUMEN PROCESS - Gulf Canada Limited, the Alberta Oil Sands Technology and Research Authority, and L'Association pour Is Valorization des Huiles Lourdes (ASVAHL) (T-247) An international joint venture agreement has been signed to test the commercial viability of the Donor Refined Bitumen (DES) process for upgrading heavy oil or bitumen. About 12,000 barrels of Athabasca bitumen from the Syncrude plant were shipped to the ASVAHL facilities near Lyon, France. Beginning in October 1986 tests will be conducted in a 450 barrel per day pilot plant through 1986 and the engineering and economic evaluations are to be completed by mid-1987. ASVAHL is a joint venture of three French companies—Elk Aquitaine, Total-Compagnie Francaise de Raffinage, and Institut Francaise du Petrole. The ASVAHL test facility was established to study new techniques, processes and processing schemes for upgrading heavy residues and heavy oils at a demonstration scale. The DRB process entails thermally cracking a blend of vacuum residual and a refinery-derived hydrogen-rich liquid stream at low pressure in the liquid phase. The resulting middle distillate fraction is rehydrogenated with conventional fixed bed technology and oft-the-shelf catalysts. Project Cost: Not disclosed *ELECTROMAGNETIC WELL STIMULATION PROCESS-- Uentech Corporation, A Subsidiary of ORS Corporation (T-252) Universal Energy Corporation of Tulsa, Oklahoma changed the company's name to Oil Recovery Systems (ORS) Corporation in June 1986. Through its subsidiary, Uentech Corporation, Universal Energy sponsored research and development at the Illinois Institute of Technology Research Institute (IlTRI) on a single-wellbore electromagnetic stimulation technique for heavy oil. The technique uses the well casing to induce an electromagnetic field in the oil-bearing formation. Both radio frequency and 60 cycle electric voltage are used. The radio frequency waves penetrate deeply into the formation while the 60 cycle current creates resistive heating. The first field test of the process was completed last summer. The first commercial well, producing about 20 barrels per day, was put into production in December 1985 in Texas, on property owned by Coastal Oil and Gas Corporation. In June 1986, ORS received permits from the Alberta Energy Resources Conservation Board, and stimulation started in a recently completed well in the Lloydminster area in Alberta, Canada. This well was drilled on Husky Oil Operations Limited acreage in the Wildmere Field. Primary production continued for about 60 days, during which the well produced about 6 barrels per day of 11°API heavy oil. The well was then shut down to allow installation of the ORS electromagnetic stimulation unit. After power was turned on and pumping resumed on June 10, a sustained production of 20 barrels per day was achieved over the following 30 days. The productivity of the well is expected to increase somewhat more as the stimulation operations proceed. The economic parameters of the operation are said to be within the range expected. Additional developmental wells are expected in the near future at four separate fields in Alberta and Saskatchewan. Another field trial is planned in Brazil in 1986. These operations will be carried out by ORS in a joint venture with the firm Azevcdo and Transvassos S/A of Sao Paulo. The test will be conducted in the Potiguar Basin, which contains several oil fields with in-place reserves estimated by Petrobras to be 4.4 billion barrels. ORS has also tentatively reached agreement with Tenneco Oil Company for a 260 acre ferment in the White Wolf field, 25 miles south of Bakersfield, California. There is an estimated 28 million barrels of 14 0 to 160 gravity oil in place in the farmout acreage. A test well is also being re-started in Tulsa County, Oklahoma. Universal Energy believes that total lifting costs using its technology could be as low as $3 per barrel Project Cost: Not disclosed ENPEX SYNTARO PROJECT - ENPEX Corporation, Texas Tar Sands, Ltd. (Getty Oil Company, Superior Oil Company, M. H. Whittier Corporation - Limited Partners; ENPEX Corporation and Ray M. Southworth - General Partners) (T-260) ENPEX Corporation has operated Texas Tar Sands, Limited's 400 barrels per day San Miguel tar sands recovery project. The project has been on-line since January 1984 and produced San Miguel tar at rates of above 500 barrels per day. The project utilizes a 50,000 pound per hour fluidized bed coal combustor to provide steam for a steam drive process. Daily production rates in excess of 500 barrels per day were achieved. Tar sales were approximately 150 to 200 barrels per day.

3-59 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

The plant is shut down due to current oil prices. The fluidized bed combustion system and oil processing unit are available for operations elsewhere.

Project Cost: Not disclosed ESSO COLD LAKE PILOT PROJECTS-- Esso Resources Canada Ltd. (1-270) 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. Esso has sold these data to several companies. Esso's Leming pilot is located in Sections 5 through 8-65-3W4 and currently produces 16,000 BOPD. The Leming pilot uses several different patterns and processes to test future recovery potential. Esso expanded its Leming field and plant facilities in 1980 to increase the capacity to 14,000 BOPD at a cost $60 million. A further expansion costing $40 million debottlenecked the existing facilities and increased the capacity to 16,000 barrels per day. By mid-1985, Leming had 483 operating wells. Approved capacity for all pilot projects is currently 3,100 cubic meters per day--i.e., about 19,500 barrels

Major prototype facilities for the commercial-scale Cold Lake Project will continue to be tested including three 175,000 pounds per hour steam generators, and a water treatment plant to convert the saline water produced with the bitumen into a suitable feedwater for the steam generators. (See Cold Lake in commercial projects listing)

Project Cost: $250 million EYEHILL IN SITU STEAM PROJECT - Canada Cities Service, Ltd., Canadian Reserve Oil and Gas Ltd. and Murphy Oil Company Ltd. (T-280) The experimental pilot is located in the Eyehill field, Cummings Pool, at Section 16-40-28-W3 in Saskatchewan six miles north of Macklin. The pilot consists of nine five spot patterns with 9 air injection wells, 24 producers, 3 temperature observation welts, and one pressure observation well. Infill of one of the patterns to a nine-spot was completed September 1, 1984. Five of the original primary wells that are located within the project area were placed on production during 1984. The pilot covers 180 acres. Ignition of the nine injection wells was completed in February 1982. The pilot is fully on stream. Partial funding for this project was provided by the Canada- Saskatchewan Heavy Oil Agreement Fund. The pilot was given the New Oil Reference Price as of April 1, 1982. The pilot has 40 feet of pay with most of the project area pay underlain by water. Reservoir depth is 2,450 feet. Oil gravity is 14.30API, viscosity 2,750 Cp at 70°F, porosity 34 percent, and permeability 6,000 nd. Project Cost: $15.2 million FT. KENT THERMAL PROJECT— Suneor, Inc. and Worldwide Energy Corporation (T-290) Canadian Worldwide Energy Ltd. and Suncor, Inc., have developed heavy oil deposits on a 4,960 acre lease in the Fort Kent area of Alberta. Canadian Worldwide holds a 50 percent working interest in this project, with Suncor as operator. This oil has an average gravity of 12.5 0API, and a sulfur content of 3.5 percent. The project utilizes huff and puff, with steamdrive as an additional recovery mechanism. The first steamdrive pattern was commenced in 1980, and a second was converted in 1984. Eventually most of the project will be converted to stearndrive. A total of 126 productive wells are included in this project, including an 8 well cluster drilled in late 1985. Five additional development well locations have been identified. The project has a productive capability of over 3,000 barrels per day; however, a number of low productivity wells are now shut-in We to low oil prices. Approximately 55 wells are now operating with production averaging 2,300 barrels per day. Further development work, including tying-in the 8 wells most recently drilled, has been suspended. Ultimate recoveries are anticipated to be approximately 21 percent. Because of the experimental work being carried out, this project qualifies for a reduced royalty rate of only 5 percent. Canadian Worldwide's share of the project costs to date is approximately $35 million (Canadian).

Project Cost: See Above FOSTERTON N.W. IN SITU WET COMBUSTION - Mobil Oil Canada Ltd. (T-295) Mobil operates a pilot in the watered-out Fosterton Northwest reservoir. The dry combustion scheme, commenced in 1970, was converted to wet combustion in 1977. The pilot has been expanded to two burns, and injection rates increased so that meaningful results can be obtained by 1988. Project Cost: Not Disclosed

3-60 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1988)

GLISP PROJECT -- Amoco Canada Petroleum Company Ltd., AOSTRA, and Petro-Canada Ltd. (T-297) The Gregoire Lake In Situ Steam Pilot (GLISP) Project is an experimental steam pilot located at Section 2-86-7W4. The participants are Amoco (12.5 percent), AOSTRA (75 percent), and Petro-Canada Inc. (12.5 percent). Other parties may participate by reducing AOSTRA's ownership. The lease ownership is shared jointly by Amoco (85 percent) and Petro-Canada (15 percent). Amoco is the operator. The production pattern will consist of a four- spot geometry with an enclosed area of 0.28 hectacres WAS acres). Observation wells will also be drilled. The process will test the use of steam and steam additives in the recovery of highly viscous bitumen (1 x 10 million cP at virgin reservoir temperature). In the absence of natural injectivity, a special fracturing technique will he used. Sophisticated seismic methods and other techniques will be used to monitor the in situ process. Reservoir selection, evaluation studies, and construction are complete. The project began operation in September 1985 and should be onstream in the Fall 1986.

Project Cost: $22 million (Canadian) GROSMONT THERMAL RECOVERY PROJECT-- UNOCAL Canada Limited (T-300) Since 1975, Union has operated seven in situ steam tests and two in situ combustion tests in the Grosmont formation of Alberta's carbonate heavy oil deposit. In 1982, a new single five spot pattern was tested using stimulation and drive processes in section 28-87-19 W4. At present 2 single well huff and puff pilots are still in operation. 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). At the pilot site, the Grosmont formation is a consolidated, highly porous dolomite of Devonian age.

Project Cost: Not disclosed IPIATIK LAKE PROJECT - Alberta Energy Company and Petro-Canada (T-330) This project is a multi-well exploration program operated by Petro-Canada under a farmout agreement with Alberta Energy Company. The project is located in a 195 section area of the North West Corner of the Primrose Bombing Range near Cold Lake, Alberta. Ninety-eight wells of a proposed 100 wells were drilled by the end of 1982. Heavy oil in place is estimated to be 1,000 x 10 million cubic meters. A thermal recovery pilot two kilometers north of this acreage started up in April 1982. Project Cost: Not disclosed KENOCO PROJECT - Kenoco Company (T-340) The Kenoco Company, the successor to the Kensyntar Company, is developing a heavy oil project in Edmonson County, Kentucky on a 19,000 acre lease. The principals of Kenoco acquired the interests of Pittston Synfuels, a partner in Kensyntar, in December 1984. The pilot was successfully operated from the summer 1981 through 1983 and produced over 6,400 barrels of heavy oil using a modified wet fireflood process. The operation was stopped before completion of the burn in 1983 to obtain core data on the test pattern. Sixteen core holes were drilled and analyzed. In parallel with the renewed pilot operation plans are being developed to expand the pilot initially to a 400 to 700 barrels per day multi-pattern operation, and over a period of 5 to 6 years to a 10,000 barrels per day operation. Commercial plans are not yet firm pending stabilization of oil prices.

Project Cost: No disclosed

KENSYNTAR PROJECT --(see Kenoco Project) LETC TS-1S, Steam Drive -- (see Tar Sand Research Program) LINDBERGH STEAM PROJECT - Murphy Oil Company, Ltd. (T-360) Experimental in situ recovery project located at 13-58-5 W4, Lindbergh, Alberta, Canada. The pilot produces from a 60 foot thick Lower Grand Rapids formation at a depth of 1600 feet. The pilot began with one inverted seven spot pattern enclosing 20 acres. Each well has been steam stimulated and produced roughly nine times. Steam drive from the center well was initiated in September 1980. Production rates from the seven-spot area have been encouraging to date, and a 9 well expansion was completed August 1, 1984, adding two more seven spots to the pilot. Oil gravity is 10°API and has a viscosity of 102,500 Cp at 700F. Porosity is 33 percent and permeability is 2500 md.

3-61 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

(Refer to the Lindbergh Commercial Thermal Recovery Project (T-33) listed in commercial projects.) Project Cost: $7 million to date

LINDBERGH THERMAL PROJECT -- Dome Petroleum Limited (1-370) Dome Petroleum Limited has completed a 56 well drilling program in section 18-55-5 W4M in the Lindbergh field in order to evaluate an enriched air and air injection fire flood scheme. The project consists of nine 30 acre, inverted seven spot patterns to evaluate the combination thermal drive process. The enriched air scheme involves three 10- acre patterns. Air was injected into one pattern to facilitate sufficient burn volume around the wellbore prior to switching over to enriched air injection in July 1982. Oxygenbreakthrough to the producing wells resulted in the shut down of oxygen inlection. A concerted finn or tp nm ctirn"intin finn ..t

When the oil price recovers, the two additional patterns will be ignited and blended to 100 percent pure oxygen. Project Cost: $22 million

MARGUERITE LAKE PHASE A PILOT -- Alberta Oil Sand Technology and Research Authority - 50 percent; BP Resources - 20 percent, Dome Petroleum Ltd. (formerly Hudson's Bay Oil and Gas) - 17.5 percent; PanCanadian Petroleum Ltd. -12.5 percent (1-390) BP Canada, Hudson's Bay Oil and Gas, and PanCanadian Petroleum entered into arrangements in 1977 whereby Hudson's Bay and PanCanadian joined BP in a pilot in situ project to produce 900 barrels per day bitumen from the Cold Lake heavy oil deposit of northeastern Alberta. The project, which is to last until 1988, involves the use of steam and combustion for bitumen recovery and is located at 7-66-R5-W4M. It is presently funded 50 percent by the Alberta Oil Sands Technology and Research Authority and 50 percent by BP Canada. At the end of 1985 the first phase of the project was completed. The current phase, which will last from 1986 to 1988, is planned to further develop the combustion process so that it can be taken into the Wolf Lake Project in the 1990s. 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 initially consisted of tour 5-spot well patterns with 5-acres per well spacing, plus four "out-of-pattern" test wells. Five infill wells were drilled in 1981 and five additional infill wells were drilled in 1984. Initial steam injection (Phase A) commenced in mid-1978 and continued through the mid-1980s. Preliminary testing of the in situ combustion stage began in several special test wells located immediately adjacent to the main pilot wells, using air. Oxygen injection was successfully tested on an experimental basis in March 1983, and the main pilot area was converted to oxygen injection in October 1983. Combustion will continue until 1988. (See Wolf Lake Project listed in commercial projects.) Project Cost: $50 million (Canadian)

MARGUERITE LAKE 'B' UNIT EXPERIMENTAL TEST -- Alberta Oil Sand Technology and Research Authority - 33-1/3 percent; BP Resources Canada Ltd. - 33-1/3 percent; Petro-Canada - 33-1/3 percent (T-395) BP Resources Canada Ltd. and Alberta Oil Sands Technology and Research Authority (AOSTRA) entered, into an agreement in 1982 whereby they would test the potential for producing bitumen from the heavy oil deposits in the Cold Lake area of northeastern Alberta. The project consists of one cyclic steam stimulation well and two observation wells in the 'B' unit of the Lower Grand Rapids Formation, and commenced in 1982. Initially only one cycle of steam stimulation was considered. The project deadline was extended to the end of 1986, consisting of four cycles. (See Wolf Lake Project listed in commercial projects.) This test has now been completed and the project has been suspended. No further testing will take place until oil prices recover.

Project Cost: $4.2 million (Canadian)

MEOTA STEAM DRIVE PROJECT (North Battleford Heavy Oil Project) -- Canterra Energy Ltd., Saskatchewan Oil and Gas Corporation, Total Petroleum Canada Ltd. (T-400) On July 8, 1986 Canterra Energy Ltd. announced that it will suspend operations at its North Battleford, Saskatchewan heavy oil pilot project for the immediate future. The operation was suspended as a result of the prevailing low oil prices and the fact that further development of the project is not supportable in the current economic climate.

3-62 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Canterra operates the pilot projet which is owned equally by Canterra, Saskatchewan Oil and Gas Corporation (Saskoil) and Total Petroleum Canada Ltd. The project has been in operation since 1974, and has allowed the participants to develop a significant technical data base for recovery of non-mobile heavy oils found in the North Battleford area. Nine oil production/steam injection wells on 2.5 acre spacing were drilled and subjected to cyclic steam stimulation between 1974 and 1980. The nine-spot was converted to an open pattern stea:ndrive in late 1980. A second phase of the pilot consisting of an additional twelve wells was added in 1981 and 1982 with initial cyclic stimulation of a new 4-five-spot pattern completed from 1981 to 1984 with subsequent conversion to stea:ndrive. Located 35 kilometers northwest of North Battleford near the community of Meets, the heavy oil pilot project tested a cyclic steam stimulation process followed by conversion to stea-n drive. The project produced an average of 642 barrels per day during 1985 and in June 1986 produced its millionth barrel. Canterra and partners invested $26.1 million after revenues in the project since its inception. Turndown of the operation commenced in mid-July and complete shutdown is expected by the end of September 1986. Project Cost $26.1 million after revenues (Canadian) MINE-ASSISTED PILOT PROJECT --(see Underground Test Facility Project) MORGAN COMBINATION THERMAL DRIVE PROJECT-- Dome Petroleum Company (T-420) Dome Petroleum Limited has completed a 44 well drilling program in Section 35-51-4 W4M in the Morgan field in order to evaluate a combination thermal drive process. The project consists of nine 30-acre seven spot patterns. Currently, 40 wells have been steam stimulated. The producers in these patterns have received multiple steam and Air/steam stimulations to orovide for oroduction enhancements and oil deoletion Drier to the initiation of burning

Project Cost: $20 million MURIEL LAKE PROJECT - Canadian Worldwide Energy Ltd. and others (T-435) Canadian Worldwide holds a 41 percent interest in this 7,040 acre lease, which contains an estimated 500 million barrels of oil in place, and assumed operatorship of the project in late 1982. A total of 17 wells were drilled and produced, using cyclic-steam stimulation. Due to an underlying water zone, oil production was insufficient to warrant a commercial operation. Consequently, operations were suspended in January 1984. The applicability of alternate technology through the involvement of other participants is being pursued. Project Cost: Approximately $10 million (Canadian) PCEJ PROJECTS -- Canada-Cities Service Ltd., Esso Resources Canada, Ltd., Japan Canada Oil Sands, Ltd., and Petro- Canada (T-460) Project is designed to investigate the extraction of bitumen from Athabasca Oil Sands using an in situ recovery technique. A three phase 15 year farmout agreement has been executed with Japan Canada Oil Sands, whereby Japan Canada Oil Sands could earn an undivided 25 percent in 34 leases covering 1.2 million acres in the in situ portion of the Athabasca Oil Sands by contributing a minimum of $75 million. Japan Canada Oil Sands has completed its interest earning obligation for Phase I by contributing $30.8 million. Phase II, designed initially to further test and delineate the resource,o is now underway. This phase includes a multi- cycle single well steam simulation test at 13-27-84-11 W4 now in its second production cycle and a second multi- cycle single well steam stimulation test at 16-27-84-I1 W4 in its first production cycle. Project Cost: Not disclosed PEACE RIVER IN SITU PILOT PROJECT -- Amoco Canada Petroleum Company Limited, AOSTRA, Shell Canada Limited, and Shell Explorer Limited (T-470) Shell Canada is continuing to operate a pressure cycle steam drive project about 55 kilometers northeast of Peace River, Alberta. The pilot consists of a conventional steam drive with added pressurization and blowdown cycles. This variation has been developed to fit the reservoir characteristics in the Peace River oil sands deposit where a thick, relatively high water saturation zone occurs at the base of the 27 meter thick oil zone at a depth of approximately 550 meters.

3-63 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

Initial water and steam injection to recover bitumen started October 31, 1979. The well pattern is a 7-7 spot with each pattern covering an area of 2.8 hetnrcs. The original project consisted of 24 production wells, 7 injectors and 12 observation wells. In 1983, four wells were added to the project to test the multisoak steam stimulation process preceding a pressure cycle steam drive. Steam injection to these wells commenced in October 1983 with bitumen production beginning in March 1984. Pilot costs to the end of September 1984 are $146 million. The partners in the initial project are: Shell Canada, 18.75 percent; AOSTRA, 50 percent; Shell Explorer, 18.75 percent; and Amoco, 12.5 percent. Shell has undertaken a 200 well expansion project that would increase bitumen production to 1,600 cubic meters per day from the pilot's 200 cubic ' p eters per day. An application to the ERCO received approval in early November 1984. Drilling began in February 1985. The expansion is planned to be on stream late 1986. Estimated capital cost is $200 million. 100 percent Shell participation. (See Peace River Commercial Expansion.)

Project Cost: $146 million (Canadian) for the pilot PELICAN-WABASCA PROJECT - Gulf Canada Corporation (T-480) Construction of fireflood and steamflood facilities is complete in the Pelican area of the Wabasca region. Phase I of the project commenced operations in August 1981, and Phase II (fireflood) commenced operations during September 1982. The pilot consists of a 31-well centrally enclosed 7-spot pattern plus nine additional wells. Oxygen injection into two of the 7-spot patterns was initiated in November 1984. Six more wells were added in March 1985 that completed an additional two 7-spot patterns. In AEjj 1986, the fireflood operation was shut down and the project converted to stea,n stimulation. Project Cost: Not Specified

PROVOST UPPER MANN VILLE HEAVY OIL STEAM PILOT PROJECT-- Noreen Energy Resources Limited (T-482) Noreen Energy Resources Limited has applied to the Alberta Energy Resources Conservation Board to conduct an experimental cyclic steam/steam drive thermal pilot in the Provost Upper Mannville B Pool. The pilot project will consist of a single 20 acre inverted 9 spot pattern to be located approximately 20 kilometers southeast of Provost, Alberta. An in situ combustion pilot comprising one 20 acre S spot was initiated in 1975. The pilot was expanded in 1982 to encompass seven 6 hectare 7 spot patterns. This pilot operation will continue under its current approval until December 31, 1986. All nine wells in the new steam pilot pattern will initially be subject to cyclic steam with conversion to a steam drive utilizing one central injector and eight surrounding producers as soon as communication is established between each well. All nine pattern wells were placed on primary production in February 1985. Primary production operations will be maintained at all but three wells until start-up of the permanent steam and production facilities in December 1985. Project Cost: Not Disclosed PR SPRING PROJECT - Enercor, Solv-Ex Corporation, and Triad Engineering Services Limited (T-485) The PR Spring Tar Sand Project, a joint venture between SoIv-Ex Corporation (the operator) and Enereor, was formed for the purpose of mining tar sand from leases in the PR Spring area of Utah and extracting the contained hydrocarbon for sale in the heavy oil markets. The project's surface mine will utilize a standard box-cut advancing pit concept with a pit area of 20 acres. Approximately 1,600 acres will be mined during the life of the project. Exploratory drilling has indicated oil reserves of 58 million barrels with an average grade of 7.9 percent by weight bitumen. The proprietary oil extraction process to be used in the project was developed by Solv-Ex in its laboratories and pilot plant and has the advantages of high recovery of bitumen, low water requirements, acceptable environmental effects and economical capital and operating costs. Process optimization and scale-up testing is currently underway for the Solv-Ex/Shell Canada Project which uses the same technology. The extraction plant for the project has been designed to process tar sand ore at a feed rate of 500 tons per hour and produce net product oil for sale at a rate of 4,663 barrels per day over 330 operating days per year.

3-64 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

In August 1993 the sponsors requested loan and price guarantees totalling $230,947,000 under the United States Synthetic Fuels Corporation's (SFC's) solicitation for tar sands mining and surface processing projects. On November 19, 1983 the SFC determined that the project was qualified for assistance under the terms of the solicitation. However, the SFC was abolished by Congress on December 19, 1985 before financial assistance was awarded to the project. The sponsors are evaluating various product options, including asphalt and combined asphalt/jet fuel. Private financing and equity participation for the project are being sought.

Project Cost; $158 million (Synthetic crude option) $90 million (Asphalt option) RAPAD BITUMEN UPGRADING PROJECT -- Research Association for Petroleum Alternatives and Ministry of International Trade and Industry (T-520) The Research Association for Petroleum Alternatives (RAPAD), supported by the Ministry of International Trade and Industry, has adopted bitumen upgrading as one of its major research objectives. Three approaches are under investigation: thermal cracking-hydrotreating, thermal cracking-solvent deasphalting-hydrotreating, and catalytlq hydrotreating. A pilot plant of the series of hydroprocessing, i.e., visbreaking-dernetallation-cracking, was completed in 1984. Its capacity is S barrels per day, and operation is continued to evaluate catalyst performance and also to obtain engineering data. Hydroconversion catalysts with high activities for middle distillates productivity, coke suppression, and for demetallation have been developed. These catalysts made it possible to produce synthetic crude oil of high quality from tar sands bitumen under mild reaction condition, which results in lower hydrogen consumption. A 10 barrels per day pilot plant with suspended-bed reactor, designed by the M. W. Kellogg Company, was completed in 1985 and is in operation. Project Cost: Not Disclosed RAS GHARIB THERMAL PILOT -- General Petroleum Company of Egypt (T-527) The tar sand thermal pilot ties onshore in the Ras Gharib field on the West Coast of the Gulf of Suez, Egypt. Three wells, spaced approximately 50 meters apart, delineate a triangular pilot area which was drilled during 1984. The tar sand formation at Ras Gharib covers an area of approximately 1,300 acres with an average thickness of about 90 meters in the tar saturated section. The tar-in-place at reservoir conditions is estimated to range from 290 to 624 million barrels. This is equivalent to 700 to 1,600 barrels per acre-foot. Based on a recovery efficiency for the cyclic steam process of 10 percent, the recoverable reserves would range from 29 to 62 million barrels. A 50 million BTU per hour single pass steam generator has been purchased. This is the first such generator in Egypt. Project Cost: Not Disclosed RTR PILOT PROJECT - RTR Oil Sands (Alberta) Ltd. (T-540) The Oil Sands Extraction pilot plant is situated on the Suncor, Inc., property, north of Fort McMurray, Alberta. The pilot plant was operated in cooperation with Gulf Canada Resouces Inc., during the second half 1981. The evaluation of the data from the operation has demonstrated the technical viability of this closed circuit modified hot water process. The process offers good bitumen recoveries and solid waste which is environmentally advantageous due to the substantial reduction in waste volume. Pilot data indicate that the total RTR/Gulf process (extraction and tailings management) offers a substantial economic advantage over conventional hot water technology. This is particularly true for a remote plant in which energy requirements must be generated. Project Cost: Undisclosed SANDALTA - Gulf Canada Corporation, Home Oil Company, Ltd., and Mobil Oil Canada Ltd. (T-550) Home Oil Company Limited, in October 1979, announced the farmout of its Athabasca oil sands property to Gulf Canada Corporation. The property, Oil Sands Lease 00980090001 (formerly BSL #30) consists of 15,086 hectares (37,115 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

3-65 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

83.75 percent interest in the lease with Elaine retaining 10 percent and Mobil Canada Ltd. 6.25 percent. An exploratory drilling program was carried out in the 1980 and 1981 drilling seasons, and more recently in 1985. Engineering studies on commercial feasibility are continuing.

Project Cost: Not Specified SANTA FE TAR SAND TRIANGLE PROJECT-- Altex Oil Corporation and Santa Fe Energy Company(T-560) Santa Fe Energy Company and Altex Oil Corporation has proposed a four-phase—ID year exploration-pilot- commercial scale project in the Tar Sand Triangle Area of Wayne County, Utah. Steam or in situ combustion would be considered on a proposed 66,000 acre Tar Sand Triangle Unit. An application for conversion of the conventional oil and gas leases to combined hydrocarbon leases has been filed with the Department of the Interior. The phased program will determine com:nereiability of the project. Project Cost: Not disclosed

'SOUTH KINSELLA (KINSELLA B) -- Dome Petroleum Ltd., PanCanadian Petroleum, and Petro-Canada (T-565) The project is at present a test of oxygen combustion in a waterflooded field. The pilot consists of five wells drilled in an inverted five spot configuration with two observation wells. Oxygen injection began in April 1985 and presently both oxygen and water are being injected. Project Cost: $4.5 million SOUTH TEXAS TAR SANDS (SOnS) PROJECT (Fracture Assisted Steamflood Technology (FAST))-- Conoco (T-240) This Maverick County, Texas project involves the use of a novel and newly patented fracture assisted steamflood process (FAST) to recover -20API gravity (i.e. viscosity over 2,000,000 cp) tar from the San Miguel 4 formation at a depth of 1,500 feet. The first 5-acre inverted 5-spot pilot test conducted during the 31 month period beginning December 1977 and ending June 1980 was successful in producing 169,000 barrels of tar which corresponds to better than 50 percent recovery efficiency. To confirm the performance of this first pattern, a second 7.5 acre inverted 7- spot pattern is presently being conducted at a location 2 miles west of the previous pilot site. Continuous steam injection and production at the new pilot began in August 1981. Tar response started at 300 barrels per day and peaked at nearly 600 barrels per day during November 1981 before beginning a gradual decline. Steam injection was terminated in June 1982, after which cold water was injected until January 1983. Cumulative tar production for this second pilot was 133,000 barrels or about 50 percent of the original tar-in-place. A smaller steam slug enabled the energy requirements to be reduced by 25 percent relative to the prior test. Because low cost steam significantly improves the economic feasibility of a large scale tar sands project, part of the steam for this second pilot test was provided by a solid fuel fired fluidized bed steam generator. The 50 million BTU per hour FBC demonstration unit has now operated for more than 8,300 hours and completed successful test burns on a wide variety of fuels ranging from low sulfur (1.5 weight percent) coal to high sulfur (7.1 weight percent) petroleum coke including a semi- bituminous coal containing 35 percent ash. Overall, the performance of the FBC unit has either met or exceeded all of its basic design parameters. Reportedly, this is the world's first application of the FBC concept to oil-field steam generation. The project is currently shut down for evaluation of post-pilot core data. The Electric Power Research Institute (EPRI) has funded a site-specific feasibility study for a 10,000 barrels per day FBC/cogeneration facility based on Conoco project data. The EPRI report is expected to be published in the near future. Project Cost: Not disclosed

SUFFIELD HEAVY OIL PILOT - (SHOP) --Alberta Energy Company Ltd., AOSTRA, Dome Petroleum Limited, Westcoast Petroleum Ltd. (T-580) An in situ combustion project located in southeastern Alberta within the Suffield Military Range and operated by Alberta Energy Company. Phase A of the project consists of one isolated five-spot pattern. The reservoir is a Glauconitic sand in the Upper Mannville formation which is underlain by water. The wells, including three temperature observation wells, were drilled during the summer of 1980. Completion of facilities construction occurred in the fall of 1981 and injection started in early 1982. Phase A is expected to continue for four years. AOSTRA holds a 50 percent interest in the project, Alberta Energy Company holds a 25 percent interest and Dome Petroleum and Westcoast Petroleum each hold a 12.5 percent interest. Phase A is scheduled for completion in 1985. The pool is presently being developed on 2.5 acres spacing for primary production and future thermal considerations. Expansion to the thermal operation is being planned to complement the primary operation. Project Cost: $11 million (Canadian)

3-66 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

SUNNYSIDE PROJECT -- Amoco Production Company (T-600) Amoco Corporation is continuing to study the feasibility of a commercial project on 1,120 acres of fee property and 9,600 acres of combined hydrocarbon leases in the Sunnyside deposit in Carbon County, Utah. Research is continuing on various extraction and retorting technologies. The available core data are being used to determine the extent of the mineable resource base in the area and to provide direction for any subsequent exploration work. Geological field work is underway in 1996; additional work is planned for 1987.

Project Cost: Not disclosed

TACIUK PROCESSOR PILOT-- AOSTRA/The UMA Group Ltd. (T-620) A pilot of an extraction and partial upgrading process located in Southeast Calgary, Alberta. The pilot plant finished construction in March 1978 at a cost of $1 million and has been in operation since. The process was invented by William Taciuk of The UMA Group. Development is being done by UMATAC Industrial Processes Ltd., a subsidiary of The UMA Group. Funding is by the Alberta Oil Sands Technology and Research Authority (AOSTRA), The processor consists of a rotating kith which houses heat exchange, cracking and combustion processes. The processor yields cracked bitumen vapors and dry sand tailings. Over 4,300 tons of Athabasca oil sand have been processed. Information agreements have been made with a major oil company and with a joint-venture company between two majors. The information agreements provide, in exchange for a funding contribution to the project, full rights for evaluation purposes to the information generated by the project during the current phase. A substantial increase in coke burning capacity and in the length of pilot run was demonstrated in the 1982 season. Recycle of the heaviest fraction of the extracted oil to produce an oil suitable for hydrotreating has been practiced. The oil product is similar to that of a fluid coker, so the process would replace both the extraction and primary upgrading steps of the process (hot water and coking) used at existing commercial plants. AOSTRA approved a $4.5 million, two-year extension to the project. The principal objective of this continuation Is to carry out the process design and sufficient detailed engineering to develop a definitive estimate for a 200 ton per hour Demonstration Plant to be constructed and operated in the Athabasca region. Consultive participation by industry in this new phase of the project is invited. Interested parties should contact AOSTRA.

Project Cost: To Date: $ 5.3 million Outstanding: 4.8 million Authorization: $10.1 million (AOSTRA)

TAR SAND RESEARCH PROGRAM - United States Department of Energy (T-625) United States Department of Energy Tar Sand Program conducted by the Laramie (Wyoming) Energy Technology Center (LETC). Field experiments with in situ thermal recovery technologies terminated in January 1982, due to severe reduction in proposed Fiscal Year 1983 Tar Sand Program Budget. Field experiment site on Sohio Shale Oil company fee property in Utah's Northwest Asphalt Ridge deposit west of Vernal, Utah, has been prepared for abandonment. Currently planned future tar sand oil recovery research will consist of laboratory experimentation. Continuation of environmental, upgrading, resource characterization, and oil recovery research is underway. Included is a three year United States/Canada cooperative project on "steam-drive with additives." Beginning in May 1983, the Department of Energy Program will be conducted by the University of Wyoming Research Corporation (UWEC) in the former LETC research laboratories. Department of Energy will fund the Program at a planned rate of $1 million per year for 42 months while the UWRC establishes a commercial clientele.

Project Cost: $1 million per year for 42 months

TAR SAND TRIANGLE - Kirkwood Oil and Gas (T-630) Kirkwood Oil and Gas drilled some 16 coreholes by the end of 1982 to evaluate their leases in the Tar Sand Triangle in south central Utah. They are also evaluating pilot testing of inductive heating for recovery of bitumen. A combined hydrocarbon unit, to be called the Gunsight Butte unit, is presently being formed to include Kirkwood and surrounding leases within the Tar Sand Triangle Special Tar Sand Area (STSA). Kirkwood is also active in three other STSAs as follows: • Raven Ridge- Rim rock—Kirkwood Oil and Gas has received a combined hydrocarbon lease for 640 acres in the Raven Ridge-Rim Rock Special Tar Sand Area.

3-67 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

• Hill Creek and San Rafael Swell—Kirkwood Oil and Gas is also in the process of converting leases in the Hill Creek and San Rafael Swell Special Tar Sand Areas. Kirkwood Oil and Gas has applied to convert over 108,000 acres of oil and gas leases to combined hydrocarbon leases. With these conversions Kirkwood will hold more acreage over tar sands in Utah than any other organization. Project Cost: Unknown TEXACO ATHABASCA PILOT -- Texaco Canada Resources (T-650) Texaco Canada Resources Ltd. is continuing to operate the experimental in situ recovery project located within Section 15-88-9 W4M on the Oil Sand Lease No. 0981030008 in the Athabasca Oil Sands in Alberta, Canada. Construction started in 1972, and initial recovery operations commenced in 1973 with twenty-six wells on a 10-acre pattern (Pattern ft. By April 1975, the number of wells increased to thirty. Steam flooding, low temperature oxidation with steam flooding, and hot water flooding with and without additives were tested between 1973 and September 1985. Operations were suspended in September 1985. Eighteen new wells were drilled in 1975 on a 3.75 acre, inverted, 7-spot pattern (Pattern II), with expansion of surface facilities completed in 1976. Steam flooding with and without light hydrocarbon, wet combustion, and hot water flooding with and without additives were tested between 1976 and September 1985. Operations were also suspended in this pattern in September 1985. By 1981, eight wells Including three horizontal wells were drilled for a third pattern (Pattern 110. During 1984 and 1985, artificial lift equipment was installed in both of the outside horizontal wells. Steam injection into the center well and production of one of the outer horizontal wells were discontinued in May 1986. Production testing on one of the horizontal wells (outer well) is on-going at the present time. Texaco Canada Resources have announced that effective September 1, 1986 the Athabasca Pilot will terminate all activities.

Project Cost: Approximately $71.0 million to December 1985

TUCKER LAKE PILOT PROJECT -- Husky Oil, Ltd. (T-655) Husky began operating a cyclic-steam pilot project at Tucker Lake in February 1984. The location of Husky's 18,000 acre lease is approximately three miles southwest of Esso's Cold Lake project. Four wells were initially put into operation and seven wells were added during 1985. To determine the most productive area the test wells are widely spaced over a 3,000 acre section of the lease. Approximately 1,250 barrels per thy of 80 percent quality steam are injected into each well. Two portable natural gas-tired steam generators rated to 2,700 psi are in use at the pilot. Water for the steam generators will be provided by fresh water wells at the site. Preliminary estimates indicate that oil in place at the project area exceeds 500 million barrels. Production is from the unconsolidated Clearwater sand with a pay zone of 110 feet at a depth of 1,500 feet. Porosity of the formation is 33 percent and permeability is 1,500 md. Oil gravity is 10°API with a viscosity of 100,000 cp at reservoir temperatures of 600F. Husky has developed a 13 well pad which includes a 50 million BTU per hour steam generator along with other associated facilities. The pad was operational during the second quarter 1986. Project Cost: Not Disclosed

ULTRA SONIC WAVE EXTRACTION - Western Tar Sands Inc. (T-660) A 30 barrels per day mini-plant located on a 640-acre site at Raven Ridge in Uinta County, Utah. Open pit mining, crushing and surface extraction will be employed. The facility will use different kinds of solvents enhanced by ultrasonic vibration for extraction. A partnership of industrial companies is responsible for detail engineering and final process configuration. The partnership will build and operate the mini plant. Baseline design and engineering was provided by Science Applications, Inc. No schedule has been set for commercial production. Corkhill Drilling, Inc. was engaged by WTS 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: $7.0 million

3-68 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since June 1986)

UNDERGROUND TEST FACILITY PROJECT -- Alberta Oil Sands Technology and Research Authority (AOSTRA) (T-410) In early 1984 AOSTRA proposed a test facility consisting of a pilot tunnel system, steam plant, and process unit. The project involves drilling two parallel vertical shafts. Horizontal tunnels off the shafts will allow drilling of access wells to permit heated bitumen to flow by gravity into the tunnels. AOSTRA refers to the technology as Shaft and Tunnel Access Concept (SATAC). Injection and production wells, 500 to 600 meters in length, will be installed in the oil sand by drilling horizontally from tunnels in the sand, or by drilling up and deviating to the horizontal from tunnels in underlying limestone. Recovery schemes which might be considered include steam assisted gravity drainage, electrical preheat, carbon dioxide steam flood, or solvent processes, Norwest Resources Consultants worked on a design study for AOSTRA involving a. mine shaft and tunnel pilot project. A test site was selected 12 miles west of Syncrude. Reserves on the lease are estimated at 325 million barrels. More drilling is planned in the winter of 1985/1986 to expand the data base. Construction of a 22 mile access road started early in January 1984. A $23 million contract was signed with Patrick Harrison and Company Ltd. and Saturn Process Plant Constructors Ltd. for the sinking of two 3-meter diameter vertical shafts and 300 meters of preliminary tunnel work. To date, the shafts have been completed and work on the initial tunneling is essentially complete. Work is currently underway on the design and fabrication of the underground horizontal well drilling equipment. Surface testing is planned for the Summer 1986. Underground testing will be part of the next phase of the project. Recovery processes will be tested in conjunction with drilling tests as part of the next phase of the project. The development of effective bitumen extraction processes is crucial to the success of the oncoming pilot phase. Preferred processes have been identified and design of the pilot phase is presently nearing completion. Project Cost: Cost for construction of all facilities, mining and process, plus a pilot operation of several years Is estimated to be around $100 million. YAREGA MINE-ASSISTED PROJECT-- Union of Soviet Socialist Republics (1-665) The Yarega oilfield (Soviet Union) is the site of a large mining-assisted heavy oil recovery project. The productive formation of this field has 26 meters of quartz sandstone occurring at a depth of 200 meters. Average Permeabilit?? is 3.17 mKm 2. Temperature ranges from 279° to 281°R; porosity is 260; oil saturation is 87 percent of the pore volume or 10 percent by weight. Viscosity of oil varies from 15,000 to 20,000 mFa per second; density Is 945 kilograms per cubic meter. The field has been developed in three major stages. In a pilot development, 69 wells were drilled from the surface at 70 to 100 meters spacing. The oil recovery factor over 11 years did not exceed 1.5 percent. Drainage through wells at very close spacing of 12 to 20 meters was tested with over 92,000 shallow wells. Development of the oilfield was said to be profitable, but the oil recovery factor for the 18 to 20 year period was approximately 3 percent. A mining-assisted technique with steam injection was developed starting in 1968. Over the past 15 years, 10 million tons of steam have been injected into the reservoir. Three mines have been operated for over ten years. An area of the deposit covering 225 hectares is under thermal stimulation. It includes 15 underground slant blocks, where 4,192 production wells and 11,795 steam-injection welts are operated. In two underground slant production blocks, which have been operated for about 8 years, oil recovery of 50 percent has been reached. These areas continue to produce oil. A local refinery produces lubricating oils from this crude. Project Cost: Not Disclosed

3-69 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 COMPLETED AND SUSPENDED PROJECTS

Project Sponsor Last Appearance in SF11 Aberfeldy Project Husky Oil Operations, Ltd. March 1983; page 3-33 A.D.I. Chemical Extraction Aarian Development, Inc. December 1983; page 3-56 Alsands Project Shell Canada Resources, Ltd. September 1982; page 3-35 Petro-Canada Gulf Canada Aqueous Recovery Process Globus Resources, Ltd. December 1984; page 3-44 United-Guardian, Inc. Ardmore Thermal Pilot Plant Union Texas of Canada, Ltd. December 1983; page 3-56 Asphalt Ridge Pilot Plant Enercor September 1984; page T-7 Mobil University of Utah Block One Project Amoco Canada Petroleum Company Ltd. September 1984; page T-8 AOSTRA Petro-Canada Ltd. Shell Canada Resources Suncor, Inc. Burnt Hollow Tar Sand Project Glenda Exploration & Development Corp. September 1984; page T-8 Kirkwood Oil & Gas Company Calsyn Project California Synfuels Research Corporation March 1984; page 3-34 AOSTRA - Dynalectron Corporation Ralph M. Parsons Company Tenneco Oil Company Cat Canyon Steamflood Project Getty Oil Company December 1983; page 3-58 United States Department of Energy Chaparrosa Ranch Tar Sand Project Chaparrosa Oil Company March 1985; page 3-42 Chemech Project Chemech December 1985; page 3-51 Chetopa Project EOR Petroleum Company December 1983; page 3-59 Tetra Systems Cold Lake Pilot Project Gulf Canada Resources December 1979; page 3-31 Deepsteam Project Sandia Laboratories March 1984; page 3-41 United States Department of Energy Falcon Sciences Project Falcon Sciences, Inc. December 1985; page 3-38 HOP Kern River Commercial [add Petroleum Corporation June 1985; page 3-51 Development Project Kentucky Tar Sands Project Texas Gas Development June 1985; page 3-52 Lloydminster Pireflood Murphy Oil Company, Ltd. December 1983; page 3-63 Manatokan Project Canada Cities Service September 1982; page 3-43 - Westcoast Petroleum Mine-Assisted In Situ Project Canada Cities Service December 1983; page 3-64 Esso Resources Canada Ltd. Gulf Canada Resources, Inc. Husky Oil Corporations, Ltd. Petro-Canada MRL Solvent Process C & A Companies March 1983; page 3-41 Minerals Research Ltd. North Kinsella Heavy Oil Petro-Canada June 1985; page 3-58 Primrose Project Japan Oil Sands Company September 1984; page T-16 Noreen Energy Resources Ltd.

3-70 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Last Appearance in SFR

Primrose-Kirby Project Petro-Canada June 1986; page 3-56 Resdein Project Gulf Canada Resources Inc. March 983; page 3-43 R. F. Heating Project lIT Research Institute March 1993; page 3-43 1-lalliburton Services United States Department of Energy Rio Verde Energy Project Rio Verde Energy Corporation June 1984; page 3-58 Santa Rosa Oil Sands Project Solv-Ex Corporation March 1985, page 3-45 Vaca Tar Sand Project Santa Fe Energy Company March 1982; page 3-43 Wabasca Fireflood Project Gulf Canada Resources, Inc. September 1980; page 3-61 Whiterocks Oil Sand Project Enercor December 1983; page 3-55 Hinge-line Overthrust Oil & Gas Corp. Rocky Mountain Exploration Company 11200" Sand Stearuflood Demon- Santa Fe Energy Company June 1986; page 3-62 stration Project United States Department of Energy

3-71 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF OIL SANDS PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

Alberta Energy Company Ipiatik Lake Project 3-61 Suffield Heavy Oil Pilot 3-66 Syncrude Canada Ltd. 3-55

Alberta Oil Sands Equity Synerude Canada Ltd. 3-55 Altex Oil Corporation Santa Fe Tar Sand Triangle Project 3-66

Amoco Canada Ltd. Elk Point Project 3-51 GLISP Project 3-61 Peace River In Situ Pilot Project 3-63

Amoco Production Company Sunnyside Project 3-67 Alberta Oil Sands Technology ABC Cold Lake Pilot 3-56 and Research Authority (AOSTRA) Athabasca In Situ Pilot Plant 3-57 Donor Refined Bitumen Process 3-59 GLISP Project 3-61 Marguerite Lake Phase A Project 3-62 Marguerite Lake "B" Unit Experimental Test 3-62 Peace River In Situ Pilot Project 3-63 Suffield Heavy Oil Pilot 3-66 Taciuk Process Pilot 3-67 Underground Test Facility Project 3-69

Bow Valley Industries, Inc. ABC Cold Lake Pilot 3-56

BP Resources Canada Ltd. Marguerite Lake Phase A Pilot Plant 3-62 Marguerite Lake "B" Unit Experimental Test 3-62 Wolf Lake Project 3-56

California Tar Sands Development Corp. California Tar Sands Development Project 3-50 Canada Centre for Mineral & Energy CAN MET Hydrocracking Process 3-57 Technology Canada Cities Service, Ltd. Eyehill In Situ Steam Project 3-60 PCEJ Project 3-63 Canadian Occidental Petroleum, Ltd. Syncrude Canada Ltd. 3-55

Canadian Reserve Oil & Gas Ltd. Eyehill In Situ Steam Project 3-60 Canadian Worldwide Energy Ltd. Charlotte Lake Project 3-58 Muriel Lake Project 3-63

Canterra Energy Ltd. Athabasca In Situ Pilot Project 3-57 Meota Steam Drive Project 3-62 Chevron Canada Resources Ltd. Beaver Crossing Thermal Recovery Pilot 3-57 Cold Lake Heavy Oil Ltd. ABC Cold Lake Pilot 3-56

Conoco Inc. Conoco South Texas Tar Sands Project 3-66 Consumers Co-Operative Refineries Ltd. Newcrade Heavy Oil Upgrader 3-52 Devran Petroleum Ltd. Sarnia-London Road Field Mining Assisted Project 3-54

3-72 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Or ganization Project Name Page

Dome Petroleum Canada Ltd. Lindbergh Commercial Project 3-52 Lindbergh Thermal Project 3-62 Marguerite Lake Phase A Project 3-62 Morgan Combination Thermal Drive Project 3-63 Primrose Lake Commercial Project 3-53 South Kinsella (Kinsella B) 3-66 Suffield Heavy Oil Pilot 3-66 Syncrude Canada Ltd. 3-55 Enercor Cedar Camp Tar Sand Project 3-58 PR Springs Project 3-64 Enpex Corporation Enpex Syntaro Project 3-59 Esso Resources Canada Ltd. Cold Lake Project 3-50 Esso Cold Lake Pilot Projects 3-60 PCEJ Project 3-55 Syncrude Canada Ltd. 3-55 General Petroleum Company of Egypt Ras Gharib Thermal Pilot 3-65 Getty Oil Company Enpex Syntaro Project 3-59 GNC Tar Sands Corporation Sunnyside Project 3-55

Greenwich Oil Corporation Forest Hill Project 3-51 Gulf Canada Resources Ltd. Donor Refined Bitumen Process 3-59 Pelican-Wabasca Project 3-64 Sandalta 3-65 Syncrude Canada Ltd. 3-55 Home Oil Company Sandalta 3-85 Husky Oil, Ltd. Bi-Provincial Project-Upgrader Facility 3-49 Lloydminster Regional Upgrader 3-49 Tucker Lake Pilot Project 3-68 Japanese Ministry of International RAPAD Bitumen Upgrading Project 3-65 Trade and Industry

Japan Canada Oil Sands, Ltd. PCEJ Project 3-63 Kenoco Corporation Kenoco Project 3-61 Kirkwood Oil and Gas Company Circle Cliffs Project 3-58 Tar Sand Triangle 3-67 L'Association pour la Valorization Donor Refined Bitumen Process 3-59 des Huiles Lourdes (ASVAHL)

Mobil Oil Canada Ltd. Battrum In Situ Wet Combustion Project 3-57 Celtic Heavy Oil Wet Combustion 3-58 Cold Lake Steam Stitnultation Program 3-58 Fosterton N.W. In Situ Wet Combustion 3-60 Sandalta 3-65 Mono Power Cedar Camp Tar Sand Project 3-58 Murphy Oil Canada Ltd. Eyehill In Situ Steam Project 3-60 Lindbergh Commercial Thermal Recovery Project 3-52 Lindbergh Steam Project 3-61

3-73 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

NewGrade Energy Inc. NewGrade Heavy Oil Upgrader 3-52 Noreen Energy Resources Ltd. Provost Upper Mannville Heavy Oil Steam Pilot Project 3-64 Nova, An Alberta Corporation Canstar 3-50 Ontario Energy Resources Ltd. Suncor, Inc. 3-54 ORS Corporation Electromagnetic Well Stimulation Process 3-59

PanCanadian Petroleum Frog Lake Project 3-51 Marguerite Lake Phase A Pilot Plant 3-62 South Kinsella (Kinsella B) 3-66 Syncrude Canada Ltd. 3-.55

Partec Lavalin Inc. CANMET Hydrocracking Process 3-57 Petro-Canada CANMET Hydrocracking Process 3-57 Canstar 3-49 Daphne Project 3-50 GLISP Project 3-61 lpiatik Lake Project 3-61 Marguerite Lake 151T Unit Experimental Test 3-62 PCEJ Project 3-63 South Kinsella (Kinsella B) 3-66 Syncrude Canada Ltd. 3-55 Wolf Lake Project 3-56 Porte-Plants, Inc. Porta-Plants Project 353 Research Association for RAPAD Bitumen Upgrading Project 3-65 Petroleum Alternatives

RTR Oil Sands Alberta, Ltd. RIR Pilot Project 3-65

Santa Fe Energy Company Santa Fe Tar Sand Project 3-66 Saskatchewan Government NewGrade Heavy Oil Upgrader 3-52 Saskatchewan Oil and Gas Corporation Meota Steam Drive Project 3-62

Shell Canada Resources, Ltd. Athabasca Project 3-49 Peace River Commercial Expansion 3-53 Peace River In Situ Pilot Project 3-63 Sarnia-London Road Field Mining Assisted Project 3-54 Scotford Synthetic Crude Refinery 3-54 Shell Explorer, Ltd. Peace River In Situ Pilot Project 3-63 Sohio Shale Oil Company Asphalt Ridge Tar Sands Pilot Plant 3-57

Solv-Ex Corporation Athabasca Project 3-49 PR Springs Project 3-64 Southworth, Ray M. Enpex Syntaro Project 3-59 Suncor, Inc. Burnt Lake Project 3-49 Fort Kent Thermal Project 3-60 Suncor 354 Sun Oil Company Suncor, Inc.

Superior Oil Company Enpex Syntaro Project 3-59

3-74 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

Tenneco Oil of Canada, Ltd. Athabasca In Situ Pilot Project 357 Texaco Canada Resources Ltd. Texaco Athabasca Pilot 3-68 Texaco Inc. Diatomaceous Earth Project 3-50 Texas Tar Sands, Ltd. Enpex Syntaro Project 3-59 Total Petroleum Canada, Ltd. Meota Steam Drive Project 3-62 Triad Engineering Services Ltd. PR Spring Project 3-64 Uentech Corporation Electromagnetic Well Stimulation Process 3-59 Underwood McLellan & Associates Taciut< Processor Pilot . 3-67 (UMA Group) Union Oil of Canada, Ltd. Grosrnont Thermal Recovery Project 3-61 Union of Soviet Socialist Republics Yarega Mine-Assisted Project 3-69 U.S. Department of Energy Tar Sand Research Program 3-57 Westcoast Petroleum, Ltd. Suffield Heavy Oil Pilot 3-66 Western Tar Sands, Inc. Ultra Sonic Wave Extraction 3-68 Whittier, FL H. Expex Syntaro Project 3-59 Worldwide Energy Fort Kent Thermal Project 3-60

3-75 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Vt tc*3r®iEt2i!

PROJECT ACTIVITIES

DOE RECEIVES TITLE TO GREAT PLAINS PLANT • Disagreeable odors in several areas throughout the plant On June 30, 1986 the Great Plains Coal Gasification Project was sold at a foreclosure sale at the Mercer • Stretford sulfur removal system problems County courthouse in North Dakota. The United States Department of Energy (DOE) was the only bidder at the • Methanation catalyst lire of 13 months rather sale. DOE's bid for the plant was $1 billion, which than 2 years represents part of the $1.5 billion DOE-secured loan • Waste gases containing various sulfur coin- that the five sponsor companies defaulted on when they pounds that cannot be desulfurized effectively withdrew from the project in August 1985. • Inadequate sulfur removal from the syngas with DOE did not receive title to the plant until a lawsuit original plant design and operating methods. filed by American Natural Resources (ANR) was settled on July 14, 1986. ANR objected to the sale on the Despite these many problems, conversion costs have grounds that: been reduced from approximately $6.00 per thousand cubic feet to $3.50 per thousand cubic feet. Addi- • The sale was not conducted in accordance with tionally, studies of recovering and selling various by- the provisions of North Dakota foreclosure law products indicate that potential exists for further improvements in the plant's profitability. By-products • The sale was not conducted in accordance with that are being evaluated include those that are current- applicable federal common law principles, es- ly being produced, those that can be produced after pecially the principle which recognizes the capital improvements are implemented, and those re- right of equitable redemption quiring 6 to 10 years of research and development. A • An incorrect legal standard was applied in partial list provided by Sabin includes anhydrous am- ordering the sale under the terms and condi- monia, carbon dioxide, naphtha, phenols, tar oil, sulfur, tions specified jet fuel, higher alcohols (which can be used as octane enhancers), cresylic acids, argon, pesticides, single cell • The sale was not conducted in a commercially protein, etc. reasonable manner. DOE has vowed to keep the plant running as long as it District Court Judge Patrick Conmy dismissed the first does not cost the taxpayers any money. Eventually two points because he had already dealt with the DOE wishes to dispose of the plant. Therefore, in allegations in previous orders. (See page 4-2 of the February 1986 DOE requested that interested organiza- March 1986 issue of the Pace Synthetic Fuels Report.) tions submit expressions of interest in the Great Plains He also found that the correct standards were used in plant. As described on page 4-7 of the June 1986 issue ordering the sale. Lastly, he ruled that the sale was of the Pace Synthetic Fuels Report nine responses conducted in a commercially reasonable manner, even were received. DOE has recently released some in- though the sale brought a lower purchase price than formation regarding the responses. expected. Therefore, he ordered that the deed to Great Plains be delivered to DOE. American Natural Resources proposed to form a consortium of public and private organizations to operate During the controversy regarding the title to the plant, the plant. After an adequate cash reserve had been DOE has been successfully operating Great Plains. accumulated from the operation of the plant, the From January through June 1986, the plant produced consortium would begin to pay the principal and inter- 137.5 millon cubic feet per day of substitute natural gas est on DOE's loan. Debottlenecking projects to (i.e.: 100 percent onstream factor). This producton has increase production and by-product sales would be ini- been achieved through continuing progress toward solv- tiated to improve profitability. ANR believes that its ing many problems, some of which were listed by V. P. long-standing association with the project makes it best Sabin at the Alternate Energy 186 conference: suited to operate and improve the plant. • Ash from the gasifiers that had cementing Amoco Corporation proposed "some form of ownership characteristics and/or operation" of the facility. The current work- • Biological activity in the plant cooling water force would be maintained to operate the plant. In system that was out of control addition to SNG, sulfur, ammonia, and carbon dioxide, Amoco would evaluate opportunities to produce more • Difficulty in screening and sizing the coal for liquid hydrocarbons. the gasifiers • Learning to operate a boiler system that fires Bohrer Consulting Service submitted a concept of pro- five different gaseous and liquid fuels simultan- ducing methanol for fuel use in trucks and vans de- eously signed to operate on conventional roadways and on railroad tracks. • Modifications to Lurgi gasifiers to better accept coal fines

4-1 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Carbon Resources, Inc., a subsidiary of Williams Tech- that they could eventually repay DOE's $1.536 billion nologies, Inc., submitted a proposal for CR! Associates, loan by modifying the plant. Ltd. (CRIAL). CRIAL is an existing limited partnership that is the owner and developer of the ChemCoal The companies' proposed modifications consist of pro- process. (See page 4-28 of the December 1983 issue ducing methanol from the gasifier synthesis gas, then and page 4-23 of the December 1985 issue for process converting the methanol into gasoline by the Mobil details.) Carbon Resources is the General Partner, with Methanol-to-Gasoline (MTG) process. Rather than pro- the present participation as follows: ducing 125 million cubic feet per day of SNG, the new product slate would be approximately as shown in Table 1. Construction and startup could be completed in 30 months at a total cost of $264 million (Table 2). Carbon Resources, Inc. 72 North American Coal Company 10 Pentatech Ltd. to TABLE 1 University of North Dakota 5 Koppers Company 3 NOKOTA-GREAT PLAINS PROJECT APPROXIMATE PRODUCT SLATE

CRIAL would acquire the Great Plains facility in return Product Amount for $1,571,000 of 8 percent, 20 year Senior Notes. Add- itional capital would be contributed in the form of Gasoline, Barrels Per Day 8,400 $80 million in cash and $20 million in the form of the SNG, Thousand Cubic Feet Per Day 69,000 value of 'Chem Coal technology. The proposed concept Propane, Barrels Per Day 435 is to co-locate a 20,000 barrels per day ChemCoal plant Butane, Barrels Per Day 1,575 at the Great Plains site. The plant, costing $200 to Blend Naphtha, Barrels Per Day 1,183 $250 million, would use low-BTU gas from a side Ammonia, ST Per Day 93 stream, reject coal fines, and a small amount of coal Sulfur, ST Per Day 85 tar oil distillate. CRIAL might also buy or lease a Carbon Dioxide, Thousand Cubic Feet Per Day 180,000 marginally economic refinery to process the coal liquids. Energy International, Inc. did not submit specific information regarding its plans for the Great Plains plant. Rather, it offered to make a "serious commercial offer" TABLE 2 based on maintaining the existing minimum gas delivery requirements plus converting a portion of the synthesis gas to higher valued products. Energy International is NOKOTA-GREAT PLAINS PROJECT an emerging company established by former Gulf exe- ESTIMATED CAPITAL INVESTMENT cutives when Chevron acquired Gulf. Recently, an TO MODIFY GREAT PLAINS underground coal gasification project proposed by (Million Dollars) Energy International was selected by DOE for funding in the Clean Coal Technology program. Naphtha Hydrogenation 6,215 Methanol Synthesis 40,821 Epeon Technologies, Inc. and Minerals Royalty Manage- Methanol Conversion + Fractionation 33,834 ment jointly proposed to purchase up to 25 percent of Other 12,960 the SNG produced by the Great Plains project. The Offsites 11.729 companies are not interested in operating the plant. Sub-Total Direct Field Costs 105,559 Rather, the companies would swap the gas for electrical power at locations around the country. The power Indirect Field Costs 39,057 would be used in Vitrifix furnaces to dispose of 100 mil- Office and Licensor Costs 22,899 lion tons of government asbestos. This new technology Interest During Construction 25.000 converts the asbestos into inert glass. Sub-Total 192,515 FHN Energy did not prepare a formal response to DOE's Contingency and Escalation 41,481 solicitation. Instead, it requested to be placed on DOE's list of potential proposers. A specific offer Budget Estimate 233,996 could then be prepared in 75 to 90 days. Working Capital 30.000 The Nokota Company and Wetzel Enterprises, Inc. pro- Total Capital 263,996 posed to assume operation of the Great Plains plant and to fund approximately $260 million for modifications to co-produce SNG and gasoline from methanol. Although the companies do not believe Great Plains is economically viable in its present configuration, they believe

4-2 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 The Three Affiliated Tribes of the Fort Berthold Reser- CHIP method overcomes this problem by using a hori- vation submitted a "statement of the Tribe's serious and zontal well drilled along the base of a coal seam. This sincere interest in negotiating with DOE to arrive at well, which is lined with a thin-walled metal pipe, mutually agreeable terms and conditions for purchase supplies oxygen to the coal to support the gasification of the Facility." The Fort Berthold Reservation is process. approximately 10 miles north of the Great Plains site. A normal commercial corporation (i.e.: without Indian To gasify the coal, successive sections of the well liner sovereignty) would be formed by the Tribe and a major are burned away and the coal seam is ignited by a energy-producing company to own and operate the propane burner inserted in the horizontal well. The plant. coal gasifies from the bottom of the seam upward producing medium-BTU gases. The gases are trans- Although the Tribe did not propose a purchase price for ported to the surface either through a second horizontal the plant, it presented a financial structure based on well near the top of the seam or through widely spaced the assumptions that: (1) the Gas Purchase Agreements vertical wells bored into the coal seam. As sections of remain in effect, (2) the purchaser will not be required the coal seam gasify, a cavity forms and ultimately to service any financial obligations of the DOE loan, (3) reaches the top of the seam. Then, the ignition device the Tribe will mine its own lignite for the plant, and (4) is moved, or "retracted," to a fresh section of coal, and no price guarantee will be requested, but the SNG price the process is repeated. will be high enough to cover the working capital for the plant. A 30 day field test of the CRIP technique was conducted in 1983 at an exposed coal face in the WIDCO The Tribe would continue to employ the ANG Coal coal mine near Centralia, Washington. (See page 4-31 Gasification Company as the plant operators, but would of the December 1985 PaceSynthetic Fuels Report for shift the coal supply to the Tribe's own reserves at a test results.) The Centralia Partial Seam CHIP test cost that is 40 percent less than the current $10 per was designed to test the concept in a coal seam with ton. Also, the Tribe would retrofit the plant to produce real commercial potential, but on a scale small enough jet fuel at a cost of $200 to $230 million. Approxi- to allow the test to be completed within 30 days. mately 6 to 12 months would be needed for the Tribe to Oxygen-steam injection was used through a 900 foot prepare a formal purchase proposal long well drilled from the coal face parallel to the dip of the seam. Medium-BTU gas was first produced through an intersecting vertical well, and then from the CRIP cavity through a slant well drilled from the exposed face. Two distinct gas qualities were achieved—a relatively high level after the CHIP man- ROCKY MOUNTAIN 1 TEST TO EVALUATE euver and lower levels during the first cavity burn and CHIP TECHNOLOGY after the roof collapse of the second burn. From October 16 to November 14 approximately 2,000 tons of A field test of the Controlled Retracting Injection coal were gasified in one cavity to produce a gas with Point (CHIP) technology will be conducted in 1987 near an average heating value of 260 BTU per cubic foot. Hanna, Wyoming. The test, named "Rocky Mountain 1," Even though some directional control problems were will be funded by the United States Department of encountered in drilling the slant holes, the overall Energy (DOE) and a four member industrial consortium. success of the Partial Seam test is very encouraging for The consortium, headed by the Gas Research Institute, the future of UCG at the Centralia site. The CRIP also includes the Electric Power Research Institute, concept adds one more degree of control to the process Amoco Production Company Research Center, and in that the average heating value of the produced gas Rocky Mountain Energy Company. These organizations can be controlled by controlling the position of the will fund 54 percent of the estimated $9.85 million injection point. project. Stearns-Catalytic Corporation has been contracted to coordinate the project with technical assist- As shown in Figure 1, the upcoming Rocky Mountain 1 ance from Energy International. DOE's participation test will create multiple cavities in two parallel rows will be managed by its Morgantown Energy Technology 350 feet underground in a 30 foot thick subbituminous Center. Lawrence Livermore National Laboratory coal seam. One row will consist of a 300 foot long (LLNL) and Western Research Institute will also assist CHIP module. The other will use vertical injection DOE. wells similar to those in previous underground field tests. As much as 20,000 tons of coal-10,000 tons per The test will take place about two miles south of row—could be gasified in the 100 day test. Hanna, Wyoming, near a site used in the 1970s by the The researchers are particularly interested in the width government to conduct some of the United States' first underground coal gasification tests. The CHIP techni- and overall geometry of the cavities. This information will be important in lessening problems created when que was conceived by LLNL in the late 1970s to two cavities intersect. Thermal instrumentation wells improve the efficiency, boost resource recovery, and (not shown in Figure 1) and post-burn core samples will increase the reliability of underground coal gasification be used to determine the extent of the cavities. Gas (UCG). Although UCG has shown merit as a way of extracting energy from unmineable or uneconomical quality will be analyzed to determine how it is affected coal seams, a recurring problem has been the tendency as the process is relayed from a depleted cavity to a new one. The researchers will also study whether of the gasification zone to move to the top of the coal vertical or slanted wells drilled into the seam are more seam, leaving much of the lower portion unused. The effective in bringing gas to the surface.

4-3 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 SCHEMATIC OF TWO UCO TECHNIQUES TO BE USED AT THE ROCKY MOUNTAIN 1 TEST

A companion effort will evaluate the ecological and Under the sponsorship of the United States Department environmental aspects of underground coal gasification. of Energy (DOE), UCC has developed a process that is primarily aimed at recovering the energy value con- A switch in the test site to Wyoming (originally the tained in wastes from coal cleaning plants. In excess of second test was to be at Centralia, Washington, near 200 million tons of coal waste is produced each year. the first CHIP experiment) will provide additional bene- Approximately 60 percent of this waste contains as fits. Researchers will be able to compare the GRIP much as 40 to 50 percent carbonaceous material. To technique with methods tested nearby in the 1970s utilize this waste, UCC developed a mild gasifica- which gasified coal horizontally along the coal seam tion/coal liquid extraction process. rather than from bottom to top. These previous tests, plus the two parallel tests in 1987, will allow the UCC's demonstration facility became operational in researchers to directly compare the two UCG methods. October 1985 with the first coal waste test commencing in November. The unit can utilize coal preparation Construction for the test is to begin within a few waste, bituminous coal, or subbituminous coal as feed- months and is expected to be completed in approxi- stocks. A high-quality hydrocarbon liquid has been mately 12 months. Drilling of the horizontal wells produced, along with a substantial amount of good through the 300 foot long section of the seam will take quality char. The coal liquid can be used as a replace- about two months. Actual gasification is scheduled for late Summer 1987. ment for or additive to diesel, gasoline, boiler, or turbine fuels. Experimental data with both diesel and gasoline engines have shown excellent performance, using a mixture of the coal liquids and petroleum-based products. The char also has a number of applications, PYROLYSIS DEMONSTRATION UNIT STARTED such as in pulverized and/or fluidized-bed industrial and UP BY UNITED COAL utility boilers, blast furnaces, and foundry coke blending systems. United Coal Company (UCC) has built a Mild Gasifica- tion Process Demonstration Unit at its research center UCC has evaluated the use of selected high-value coal in Bristol, Virginia. The unit is capable of processing waste as feed to a fluidized-bed boiler to produce both 1 ton per day of coal or coal waste. Details of the steam and electricity. They found that the economic technology and preliminary operating results were re- viability of this system could be low because coal cently explained at the New Fuel Forms Workshop in preparation plants do not use steam to process coal, and May and at the DOE Coal Gasification Contractors because utility companies in the coal regions have a low meeting in June. avoided cost. Thus, UCC decided to extract coal

4-4 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 liquids from coal waste via a mild gasification, low TABLE 1 temperature carbonization (i.e.: pyrolysis) process. The coal liquids can then be transported via tank ears to ANALYSES OF CHARS OBTAINED FROM various existing markets and the char containing the THE UCC LABORATORY UNIT coal waste can be disposed of in an improved form, or it can be burned in fluidized-beds. Also, the process can be used for high quality coals to produce even greater quantities of liquids and char of commercial value. Proximate Analyses 0CC believes that the mild gasification low temperature carbonization process may have all the economic Percent factors necessary for a successful project: Char Coal Char Sul- Vol- Heating Fixed Identification Ash Ash fur ume Value Carbon • Low capital cost (BTU/Lb) • Modular construction Low Ash Coal 2.00 2.15 0.49 15.5 14,485 82.5 High Ash Coal 10.00 11.37 0.56 17.4 12,875 71.4 • Flexibility in design and operating conditions Low Ash Coal 2.50 3.00 0.59 11.8 14,617 85.2 Kentucky No.9 15.00 18.46 1.69 7.7 11,660 73.8 • Production of both a liquid and char that could Coal be utilized in the existing coal markets • Commercial experience at a facility that has Ultimate Analyses been operating successfully in England for the Weight % Dry past 40 years. Low Ash High Ash The process design developed by 0CC concentrated Element Char (2.5%) Char (12%) primarily on constructing a test unit of sufficient size to obtain a reasonable quantity of liquids for test Carbon 87.47 79.40 Hydrogen purposes. The mild gasification unit includes a 1 ton 2.96 2.71 Nitrogen 1.99 1.63 coal storage bin, four loading hoppers, four 8 inch Oxygen 4.94 433 diameter by 8 foot long tapered reactor tubes, a constant controlled furnace, four banks of condensers, four hydraulic rams for char removal, and appropriate stor- Ash Composition age containers for char and coal liquids. Weight % Dry

Low Ash High Ash Laboratory Test Results Component Char (2.5%) Char (12%) Silicon Dioxide 35.76 53.33 0CC first constructed a laboratory fixed-bed pyrolysis Aluminum Oxide 20.06 25.25 low-temperature carbonization unit. The bench-scale Titanium Dioxide 1.31 1.14 unit produced high quality liquids and char from a Calcium Oxide 4.82 1.36 Potassium Oxide 1.23 4.05 number of different types of coal waste and coals. On Magnesium Oxide the average, the liquid yields ranged as high as 1.05 1.34 Sodium Oxide 1.77 0.43 16.6 percent, while "oil" yields ranged up to 12.8 per- Ferric Oxide 26.60 9.50 cent. Char yields were generally in the 72 to 75 per- Phosphorous Pentoxlde 0.15 0.06 cent range, and uncondensable gas yields were normally Sulfur Trioxide 7.20 1.06 in the 10 percent range. Viscosities of the coal liquids Undetermined 0.01 2.48 were generally low, and there was never more than a trace of ash in the liquids.

After all pyrolysis tests using 0CC low ash coal were completed, two tests were made using 0CC high ash successfully removed the ash to essentially zero at coal. The liquid yields ranged from 14.9 to 16.2 per- 1,800°C, and the alkaline components (sodium and cent, with approximately 12 percent of the total being potassium) to a level that would allow the char to be liquid coal "oils." Char yields were 74 percent and gas used in a turbine. The laboratory results are shown in yields ranged from 9.6 to 11.8 percent. The ash in the Table 2. coal liquids was low at 0.016 percent, while the viscosity was higher than that of the liquids from low ash coal. Laboratory analyses of the coal chars are sum- Demonstration Unit Test Results marized in Table 1. Since the initial start-up of the mild gasification dem- 0CC also evaluated various physical cleaning processes onstration unit, several shake-down tests have been involving froth flotation, magnetic separation, acid conducted. The furnace, tapered reactor tubes, char leaching, and electrostatic precipitation. However, removal and break system, electronic controls, water none of these physical cleaning system adequately re- quench system, and flare system have each performed moved the ash in the char to make the char acceptable well. The condensing system has been modified several as a turbine fuel. 0CC discovered a new system times to optimize liquid recovery. 0CC is emphasizing involving a gaseous phase, thermally induced chemical this area of the plant so that the coal liquids can be separation method using chlorine gas at elevated tem- separated according to their quality during the condens- peratures. Laboratory tests in a tube graphitizer ing phase and thus eliminate the need for distillation.

4-5 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

TABLE 2

ANALYTICAL DATA FOR UCC CHLORINE CLEANING PROCESS OF CHAR (Percent)

Char Temper- Potas- Identification atureSodium slum Sulfur Ash Chlorine (°C)

Low Ash Char 600 0.060 0.022 0.70 1.84 13.0 High Ash Char 600 0.072 0.210 0.90 6.39 13.7 Low Ash Char 1,200 0.050 0.007 0.50 0.65 1.8 High Ash Char 1,200 0.050 0.010 0.60 0.66 2.6 Low Ash Char 1,800 0.050 0.005 0.10 0.24 0.82 High Ash Char 1,800 0.050 0.005 0.06 0.00 0.95

A summary of the preliminary test results obtained Preliminary Engine Tests through February 21, 1986 are shown in Table 3. The coal liquids produced from the various laboratory and demonstration unit tests have been refined into TABLE 3 liquids acceptable for mixing with both petroleum gasoline and diesel fuels. These coal/petroleum-based fuels were tested by UCC in both diesel and gasoline engines. PRELIMINARY ANALYSIS OF UCC The results obtained with a 25 horsepower Kubota and a COAL LIQUIDS 250 horsepower Cummin diesel engine using a coal (Percent) liquids-diesel fuel mixture of 50 percent showed no significant difference in engine performance. The lighter portion of the coal liquids (distilled at less than Proximate Analysis 300°F) mixed well with both naphtha and gasoline Moisture 9.08 petroleum-produced products. A few preliminary Volatiles 71.78 engine tests using a 5 horsepower Briggs-Stratton have Ash 40.01 been conducted which show no measurable difference in Fixed Carbon 18.54 engine performance. Sulfur 0.59 Ultimate Analysis Future Testing Carbon 80.02 United Coal Company believes that the mild gasifica- Hydrogen 5.70 tion process unit is sufficiently flexible to allow for Nitrogen 2.07 tests with different coals, catalysts, steam injections, Oxygen 11.61 coal/residual oil cracking, waste products mixed with coal, char chlorination, etc. They expect that the Other Analysis forthcoming testing program will determine the com- Carbon Aromaticity 97 mercial viability of the process design. In addition, Specific Gravity 0.85 sufficient quantities of liquids will be produced to allow Heating Value (Dry), BTU/Lb -15,460 for gasoline, diesel, and turbine engine testing to prove Hydrogen/Carbon Ratio 0.85 the market acceptability of the products. The char will also be evaluated in various markets. Compound Classes Allphatics 0.28 Neutral (Naphthalenes) 2.87 Neutral (Aromatics) 52.15 Base (Aromatics) 35.37 Acid (Aromatics) 6.09

4-6 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 CORPORATIONS

GRI DESCRIBES 1987-1991 R&D PLAN AND 1987 PROGRAM In view of this reassessment of the role of coal-based SNG in the long-term supply picture, OR! has redir- The Gas Research Institute (CR1) plans, manages and ected its R&D program to pursue longer-term research develops financing for a cooperative research and on advanced gasification processes and advanced cat- development program in supply, transport, storage, and alysts aimed primarily at achieving dramatic reductions end use of gaseous fuels. CR! was chartered in 1976 to in SNG cost. Development of technologies aimed at provide a centralized organization to formulate and evolutionary improvement of existing or emerging coal manage an R&D program on behalf of member gas gasification systems has been deferred. industry companies and the gas consumer. OR! implements its mission through planning and managing con- CR1 R&D on coal gasification is now organized into two tractor-performed R&D and through in-house analyses project areas: and communications activities. The objectives and goals for the contract R&D program are developed and • Coal Gasification revised on an annual basis. GRI's R&D program for the • In Situ Coal Gasification Technology. next five years is described in its 1987 to 1991 Five- Year R&D Plan, with emphasis on R&D proposed for 1987. Coal Gasification Processes The OR! program is subject to annual review and GRI's objectives in this area are to verify the technical approval by the Federal Energy Regulatory Commission feasibility and economic viability of advanced technolo- (FERC), with participation by state regulatory com- gies for conversion of United States coals to pipeline- missions and other interested parties. On June 2, 1986 quality substitute natural gas, and evaluate the implica- cm submitted their proposed 1987 R&D program bud- tions of applying this R&D to existing and emerging get to FERC. The Plan, which describes all the coal gasification technologies to improve their effi- projects OR! intends to fund, provides for total outlays ciency. Performance goals include: of $187.3 million, up from $164 million in 1986. The major issues to be addressed in the 1987 Plan are: • Develop a comprehensive data base of advanced gasification processes • End-use research that will improve energy efficiency in current applications and create new • Identify and pursue breakthroughs in gasifica- end-uses for gas tion technology that offer the possibility of reducing the cost of producing SNG from coal • Supply research that reduces the cost of producing marginal natural gas • Thoroughly test new sulfur-tolerant, direct methanation catalysts • Refocusing of synthetic natural gas research on longer-term fundamental research • Research an advanced acid gas removal process compatible with direct methanation with the • Increased funding for basic research. capability of eliminating hydrolysis of carbonyl sulfide in the product gas The research program areas specifically related to synthetic fuels are briefly described in the following • Investigate engineering designs that capitalize summaries. on research on gasification technology. In contrast to last year's plan, CR1 will not develop the Substitute Natural Gas Supply agglomerating-ash fluid-bed or slagging-Lurgi gasification processes, nor scale up direct methanation or acid This sub-program focuses on the development of tech- gas removal technology. nologies that will enhance the availability of cost- competitive substitute natural gas (SNG) from fossil GRI R&D initiated in 1986 is directed at several fuels, wastes of various kinds, and biomass. CR1 expect approaches that appear promising, such as low-temper- that in the long term (post 2000), supplemental gas ature catalytic gasification processes or the use of supplies—imports, LNG, Alaskan gas, and SNG from pretreated coal as a feedstock. These advanced pro- coal and biomass—will play an increasingly important cesses are targeted for use in the post-2000 period. role in meeting United States gas demand. In particular, CR! will continue to conduct research on The 1985 CR1 Baseline Projection forecasts that 20 per- the sulfur-tolerant methanation catalyst. Development cent of total United States gas demand by 2000 will be of an advanced acid-gas removal system that is compa- provided by supplemental sources. This forecast is tible with sulfur-tolerant catalytic methanation will down from 25 percent of United States supplies by 2000 also continue. By 1990, CR1 expects that the results of in their 1984 report. CR1 expects adequate supplies of its research on direct methanation and acid-gas cleanup natural gas from current and other supplemental should be ready for integration and testing. GRI's sources, such as imported gas, to be available over the estimate of funding for this area over the next five next 25 years. years is shown in Table 1,

4-7 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

TABLE 1

CR75 FUNDING ESTIMATES FOR COAL GASIFICATION

CY 1987 Funding Estimate Govern- In- GRI ment dustry Direct Methanation 750 0 55 Develop direct methanation process using new sulfur- tolerant catalysts and determine their activity and selectivity in direct methanation of coal gasifier product gases with H2/CO ratios of from 0.5:1 to 2.5:1

Technical/Economic Evaluation 500 0 50 Provide technical and economic evaluations of technologies and sub-systems involved in producing SNG from coal

Acid Gas Removal 200 0 30 Develop improved sub-systems for removal of acid gases from coal gasifier product gas, compatible with direct methanation technology

Advanced Gasification Process Development 900 0 200 Identify and pursue scientific and engineering breakthroughs in gasification technology that offer the possibility of significantly reducing (e.g., by 25 to 40 percent) the cost of producing SNG from coal compared to existing coal gasification technologies

Advanced Catalyst Development 500 0 20 Identify and pursue concepts for the application of advanced catalysts to a variety of processes in coal gasification, with a focus on those that may offer substantial performance improvement or cost reduction compared with existing approaches

Bu dget (Thousand Dollars) 1986 1987 1988 1989 1990 1991 CR1 Funds 5,550 2,850 3,250 3,950 6,350 7,300 Government Funds 2,350 2,000 0 0 50 50 Industry Funds 150 355 480 955 1,785 2,125

In Situ Coal Gasification TechnoLogy ------Gifi's objective for in situ coal gasification is the development of gasification processes that allow cost- At the present time, CR! views in situ gasification as a effective gas production from coal without mining and high-risk technology, but with a very high payoff poten- with acceptable environmental impacts. Performance tial. CR1 believes that major problems with the devel- goals include: opment of this technology include finding low-cost, reliable, and reproducible methods for providing a path- • Define the impacts on plant design and gas way between injection and production wells, control of costs from environmental control and treat- the combustion front and gas quality, prediction of ment facilities by monitoring hydrological ef- subsidence potential and other environmental impacts. fects at in situ gasification sites

4-9 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 • Expand the data base on gasification kinetics, roof collapse, and injection well design by com- TABLE 2 pleting large block tests in subbituminous and bituminous coals GEl'S FUNDING ESTIMATES FOR • Define applicable site-specific criteria to be IN SITU COAL GASIFICATION TECHNOLOGY used for comparison with competing SNG technologies Ci' 1987 Funding Estimate Govern- In- • Improve the capability for commercial design GRI dust by developing a comprehensive model of in situ Controlled Retracting Injection Point Technology 800 2,300 BOB gasification Demonstrate the ability of CRIP technology to control gas quality to within 80 percent of the • Demonstrate deep-seam in situ coal gasifica- original hosting value in dual wells and obtain 60 percent resource recovery in multiple-well tion technology to provide data suitable for tests for subbituminomss and bituminous coals commercial design. Table 2 shows GRI's five year funding plan for ths area. Dumet (Thousand Doiiars) 1886 1987 1988 1989 1990 1991

Coal Sciences GRi Funds 1.100 800 700 1,100 1,100 1,100 Government Funds 1,500 2,300 1,900 1,400 2,000 2,000 While coal can be used to substantially extend gaseous Industry Funds 734 868 330 150 1,050 1,050 fuel supplies, basic research is required to understand the intrinsic unreactivity of coal toward carbon-carbon bond cleavage. According to CR1, a specific impedi- ment to the development of low-temperature methodo- logies for breaking down the macromolecular structure of coal is a general lack of scientific understanding of the relationship between coal's chemical structure and its reactivity. CR1 feels basic research needs to be undertaken on specific reactions and structure/reactivity relationships in coal or coal-like compounds.

The objective for this project area is to develop the TABLES scientific understanding needed to provide new methods for converting coal to methane. Performance goals USFS FUNDING ESTIMATES FOR include: COAL SCIENCES • Improve the understanding of the mechanisms CY 1987 Fundlrc Estimate for breaking carbon-carbon bonds in coal mole- Govern- In- cules GRI a • Increase understanding of structural/reactivity Coal Reaction Chemistry and Mechardan. 1,470 22 240 Advance coal chemistry in areas relevant to coal relationships in coal that control reaction rates gasification, including elucidation or mole- and selectivities cular-level factors controlling reaction rates and sensitivities involved In cleaving coal • Improve understanding of retrogressive coal carbon-carbon bends gasification reactions Technical Evaluation ioo 2 3 Perform technical evaluations or advanced coal • Develop methods for quantitative comparison gasification concepts to identify potential and correlation of coal-char gasification reacti- technical and coat advantages vity and models for predicting pyrolysis reactions with coal properties Buttet (Thousand Dollars) • Develop and/or improve mechanistic under- 1986 1987 1888 1989 1990 1993 standing of catalytic and radical-cation chem- Gal Funds 1,450 1,570 1,850 1,850 1,850 2,000 istries pertaining to coal gasification. Government Funds 21 24 2 2 2 2 Industry Funds 240 243 61 53 53 53 GRI's funding for this area is shown in Table 3.

### it

49 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 GOVERNMENT

NINE CLEAN COAL PROJECTS CHOSEN BY DOE federal funds while contributing nearly $600 million total in private financing. The 65/35 ratio of private to On July 25, 1986 the United States Department of federal funding is well above the minimum 50/50 cost- Energy (DOE) announced that the nine projects listed in sharing required by Congress when it established the Table 1 had been selected as DOE's top choices in their Clean Coal Technology Program in December 1985. Clean Coal Technology Program. The projects were picked from 51 proposals submitted to the agency last Costs for each project and specific information on cost April (see page 4-9 of the June 1986 Pace Synthetic sharing will be provided by DOE when actual agree- Fuels Report). DOE selected the nine projects on the ments are negotiated and signed. If a cooperative basis that they offered the greatest likelihood of suc- agreement is not actually awarded to any of the nine cessfully demonstrating and subsequently commercial- applications, additional projects could be selected from izing emerging clean coal technologies. According to a second group of proposers listed in Table 2. DOE the first facilities to use technologies financed under this program could be built and in operation When Congress appropriated nearly $400 million for the within several months after cooperative agreements program last year, it mandated a full competition open with the government are signed. Some of the larger to all markets. The nine projects selected by DOE projects will not be ready for testing until the early proposed new coal technologies for a variety of differ- 1990s. ent market applications, including utility power generation, industrial processing, steelmaking, and fuel pro- Negotiations with the nine firms will begin immediate- duction. Both new plants and retrofits are included in ly. If agreements are reached with the sponsors of all the selected projects. nine projects, the proposers will share $360 million in

TABLE 1

PROJECTS SELECTED FOR ASSISTANCE IN THE FIRST ROUND OF DOE'S CLEAN COAL TECHNOLOGY PROGRAM

Sponsor Technology Prolect Location American Electric' Pressurized Fluidized Bed Brilliant, Ohio Power Service Corpor- Combustion Combined Cycle Lion-Columbus, Ohio Utility Retrofit Babcock & Wilcox' Extended Tests of Limestone Lorain, Ohio Alliance, Ohio Injection Multi-Stage Burner Plus Sorbent Duct injection Coal Tech Corpor- Slugging Combustor With Williamsport, tion-Marlon, Penn- Sorbent Injection Into Pennsylvania sylvania Combustor Energy & Environ- Gas Reburning & Sorbent Springfield, Illinois Research Corporation injection Retrofit Into Hennepin, Illinois Irvine, California 3 Utility Boilers Bartonville, minim Energy International, Steeply Dipping Bed Under- Rawlins, Wyoming Inc. ground Coal Gasification Cheswick, Pennsylvania Integrated with Indirect Liquefaction General Electric Integrated Coal Gasification Evendale, Ohio Company Steam Injection Gas Turbine Dunkirk, New York Cincinnati, Ohio Demonstration Plants (2) With Hot Gas Cleanup Ohio Ontario Clean' Coal-Oil Coprocessing Warren, Ohio Fuels, Inc. Liquefaction The M.W. Kellogg Com- Fluidized Bed Gasification Cairnbrook, pany With Hot Gas Cleanup Pennsylvania Houston, Texas Integrated Combined Cycle Demonstration Plant Weirton Steel Cor- Direct Iron Ore Reduction Weirton, West Virginia poration to Replace Coke Oven/Blast Weirton, West Virginia Furnace for Steelmaking

'Also selected for financial assistance from the State of Ohio

4-10 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 2

RUNNER-Up CLEAN COAL TECHNOLOGY PROJECTS THAT MAY BE CONSIDERED FOR FUNDING BY DOE

City of Tallahassee - Circulating Fluidized Bed Combustion Utility Retrofit (Tallahassee, Florida) Colorado-Ute Electric - Circulating Fluidized Bed Combustion Association Utility Retrofit (Nucis, Colorado) Combustion Engineering Inc. - Combustion of Medium and Deep Cleaned Coals (Homer City, Pennsylvania; Wind- sor, Connecticut; Alliance, Ohio) Consolidation Coal Company & - Advanced Integrated Gasification Com- Foster Wheeler Power Systems bined Cycyle with Hot Gas Cleanup (Mor- gantown, West Virginia) McDonnell Douglas Energy - Advanced Microbubbie Flotation Coal Systems Cleaning (Shelbyville, Kentucky) Minnesota Department of - Direct Iron Ore Reduction to Replace Natural Resources Coke Oven/Blast Furnace (Mt. iron, Min- nesota) Southwestern Public Service Co. - Circulating Fluidized Bed Combustion Utility Replacement (Amarillo, Texas) Tennessee Valley Authority - Indirect Liquefaction to Enhance Inte- grated Gasification/Combined Cycle (Muscle Shoals, Alabama) Tennessee Valley Authority - Lime Spray Dryer/Baghouse Flue Gas Cleanup (Paducah, Kentucky) TRW, Inc. - Advanced Slagging Combustor for Utility Retrofit (Rockland County, New York United Coal Company - Microbubbla Flotation/Centrifugal Drying Of Coal Preparation Wastes (sharpies, West Virginia Western Energy Company - Coal Cleaning to Upgrade High-Moisture, Low-Rank Coal (Colstrip, Montanta) Westinghouse Electric Corporation - Coal Gasification/Phosphoric Acid Fuel Cell Power Plant (Madison, Pennsylvania) Wisconsin Electric Power Company - Pressurized Fluidized Bed (Turbocharged) Boiler Retrofit (Port Washington, Wiscon- sin)

DOE chose the projects following a three-month long (AEP), on behalf of the Ohio Power Company, will evaluation by an eight-person board of technical, pro- construct and operate a 70 megawatt Pressurized Fluid- curement, and legal specialists. The board also called ized Bed Combustion (PFBC) Combined Cycle Demon- on various DOE and United States Environmental Pro- stration Plant in Brilliant, Ohio. The project will use tection Agency (EPA) experts to examine specific as- technology developed by ASEA-PFB, a Swedish firm pects of the proposals. The 39 proposals that passed that supplies major utility components. the preliminary evaluation in early May were judged on technical, business and management, and cost criteria. AEP has designed a PFBC plant—the Tidd PFBC Results of the board's review were then submitted to Demonstration Plant—with a capability of 70 mega- DOE's Acting Assistant Secretary for Fossil Energy, watts, to be located in the town of Brilliant, Ohio. Its Donald L. Bauer, who considered the board's report design is based on almost a decade of research and along with several "program policy factors." These development by AEP and its partners. The schedule Policy factors reflected DOE's interest in selecting calls for having the plant start operation in late 1989 projects representing a diversity of technical ap- and run for a demonstration period of five to ten years, proaches or applications that would use a broad cross during which time enough data about the technology section of United States coals, and which would repre- and equipment will be acquired to confidently build sent a balance between the goals of expanding the use large, commercial power plants. of coal and minimizing environmental impacts. The PFBC process involves burning coal in a fluidized As described in the following article in this issue, the bed of coal, dolomite (a form of limestone), and inert state of Ohio is planning to provide financial assistance material. Sulfur in the coal is absorbed by the dolo- to four of the projects selected by DOE. mite, resulting in a dry, granular by-product ash which is removed from the bed. As shown in Figure 1, the The following is a brief description of the nine selected hot, pressurized, sulfur-free gas flows through a dust projects: collector then through an ASEA STAL GT120 gas turbine to drive an air compressor and a generator to produce electric power. American Electric Power Service Corporation Immersed in the bed are tubes to generate steam which The American Electric Power Service Corporation flows through a steam turbine that drives a second

4-11 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 1 SCHEMATIC OF PFBC COMBINED-CYCLE SYSTEM

STEAM CLEAN HOT GAS STEAM TURBINE

GENERATOR ..

FLUIDIZED DEC

TO STACK jC CLONE ASH

WASTE HEA EEDW TE '. COAL AND RECOVERY DOLOMITE

BED ASH GAS TURBINE

COMPRESSOR GENERATOR

AIR

generator to produce additional electric power. The on the order of 50 to 60 percent at a capital cost at clean, cooled gas is released through the stack in full least $100 per kilowatt less than wet scrubbers. compliance with environmental requirements. The combined cycle plant will operate at 1,580°F and a As a result of funding limitations of the existing EPA pressure of 12 atmospheres. The demonstration plant contract, testing currently is restricted to one sorbent will be a retrofit of a mothballed coal-fired power plant and one coal. The results of the Clean Coal Technology and will utilize the existing steam turbine and other project will extend the number of coals and sorbents to site utilities. be evaluated. The EPA project, begun in 1984, is scheduled to run through 1988. The proposed extensions AEP and the State of Ohio have proposed to contribute would involve additional work into 1990. The Unit 4 66 percent of the project cost. According to the Ohio boiler at the Edgewater Station was originally commis- Coal Development Office (OCDO), total project cost is sioned in 1957, and is designed to burn approximately $175.6 million, with DOE providing $60 million and 45 tons of coal per hour. An electrostatic precipitator OCDO providing $10 million. designed for over 99 percent particulate emission control was installed in 1982. At the present time the plant burns a low-to-medium sulfur coal. Babcock & Wilcox The second part of the project will evaluate the Conoco The two part project will develop retrofit acid rain "Coolside" process for sulfur dioxide control. This precursor control technologies. The first part is an process involves dry sorbent injection/humidification extension of on-going Limestone Injection Multistage technology downstream of the boiler. The "Coolside" Burner (LIMB) testing. Babcock & Wilcox is currently technology has been tested in a 1 megawattt field test conducting the full-scale demonstration of the LIMB at DuPont's Martinsville plant. The proposed demon- technolgoy on a 105 megawatt wall-fired utility boiler stration will also be done at the Edgewater Station and in a project co-sponsored by the EPA and the State of will provide a side-by-side comparison with LIMB. Ohio at Ohio Edison's Edgewater Station in Lorain, Ohio. The objectives of this project are to demonstrate The project sponsors intend to provide 61 percent of the nitrogen oxide and sulfur dioxide emissions reductions required project funding. The Ohio Coal Development

4-12 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Office will provide $9.8 million to the $27.5 million emission reductions are obtained by injecting calcium- project, with DOE providing $7.5 million and the EPA based sorbents either with the burnout air or down- providing $1.8 million. stream between the air preheater and the electrostatic precipitator. Three host sites have been selected representing the Coal Tech Corporation three major firing configurations currently employed. These are tangential (Hennepin, Illinois site), wall-fired This proposed project is for a 1,000 hour test to demon- (Bartonville, Illinois site), and cyclone (Springfield, Illi- strate the performance of an advanced, air-cooled, nois site). Boiler sizes are 80, 117, and 40 megawatts, cyclone combustor with dry pulverized coal. Two respectively. A 48 month program is proposed with a Pennsylvania bituminous coals, containing 2 percent and 60 month period required if phase overlay is omitted. 3 to 4 percent sulfur, and one Utah subbituminous coal containing 0.5 percent sulfur will be tested to demon- The sponsors, which include the Gas Research Institute strate that this advanced combustor is capable of and the State of Illinois, have proposed to contribute burning a variety of United States coals in an environ- 50 percent of the project cost. mentally acceptable manner. The technical performance objectives of the proposed project are to demonstrate: (1) 90 to 95 percent coal ash retention in the Energy International, Inc. combustor (and subsequent rejection), (2) NO, reductions to 100 ppm or less, (3) sulfur dioxide emission This project involves a proof-of-concept/pilot demon- reductions of 70 to 90 percent, and (4) combustor stration of underground coal gasification (UCG) techno- durability and flexibility. logy applied to the steeply dipping bed subbituminous coal deposits near Rawlins, Wyoming. The pilot demon- According to the project sponsors, the combustor can stration will operate for 180 days, gasify 36,000 tons of be adapted to new as well as retrofit boilers; it can be coal, and produce up to 2,000 to 4,000 barrels of middle used for converting oil- and gas-designed boilers to distillate liquids using a fixed bed indirect liquefaction coal; and it has industrial and utility applications. The technology. The demonstration represents one module Coal Tech Corporation is now constructing a 30 million of a commercial plant which would ultimately produce BTU per hour (1 ton per hour) combustor which is 4,000 barrels per day of liquids and 60 million standard nearing completion. The proposed demonstration pro- cubic feet of substitute natural gas (SNG). The com- ject will be conducted at the Keeler Boiler Com- mercial plant will utilize underground coal gasification pany/Dorr-Oliver site in Williamsport, Pennsylvania, technology to produce a synthesis gas feedstock for a where a 23 million BTU per hour D-tube package boiler gas-to-liquids conversion for the production of middle designed for oil is available. The 27 month demonstra- distillates. The three year proposed demonstration tion project includes 1,000 hours of testing. In addition project will provide the additional process, economic, to Coal Tech Corporation, project sponsors include the and environmental data required to reach the commer- State of Pennsylvania Energy Development Authority, cialization decision. the Pennsylvania Power and Light Company, and the Southern California Edison Company. The Keeler Approximately 51 percent of the project cost will be Boiler Manufacturing Company will assist Coal Tech in contributed by the project team consisting of Energy the implementation of the project. International, Stearns Catalytic Corporation, and Rocky Mountain Energy Company (a subsidiary of Union Paci- fic Corporation). (Additional details of the project The five sponsors will contribute 50 percent of the were described on page 4-4 of the June 1986 issue of project cost. the Pace Synthetic Fuels Report.)

Energy and Environmental Research General Electric Company Corporation This project will use a coal gasification, steam-injected The Energy and Environmental Research Corporation gas turbine power plant to demonstrate the feasibility (EER) intends to demonstrate a combination of natural of simplified integrated gasification combined cycle gas reburning and sorbent injection for the control of (IGCC) systems for commercial coal-to-electricity ap- 502 and NOx emissions from existing coal-fired boilers. plications. The simplified system is configured to Program goals are 60 percent NOx control and 50 per- reduce components in each of the major sub-systems: cent SO2 control. Gas reburning is achieved by injec- gasification, gas cleanup, and gas turbine power gener- tion of natural gas (10 and 20 percent of the total fuel ation systems, while retaining commercial hardware input) above the normal furnace heat release zone to and design philosophy for many of the sub-system an oxygen deficient region in the upper furnace components. (reburningF zone). As shown in Figure 2,burnout air is introduced above the reburning zone to complete the The technology uses an air-blown moving bed gasifier, fuel combustion. A portion of the NOx produced in the high temperature sulfur removal technology, hot cy- main heat release zone is decomposed to molecular clones, and the "LM" series (aircraft derivative) gas nitrogen in the reburning zone. Because the reburning turbine/generator package. Key elements are the high- fuel contains no sulfur, SO2 emissions are reduced in temperature gas cleanup systems which can allow signi- proportion to the amount of gas fired. Additional SO2 ficant reduction of contaminant levels without degrade-

4-13 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 2 ILLUSTRATION OF GAS REBURNING - SORBENT INJECTION TECHNOLOGY

SULFAtION ZONE SULFATION ZONE 80 2 CAPTURE BY ACTIVE SORBENT CREATED IN THE BURNOUT ZONE

SORB tNT -... I BURNOUT ZONE • — BURNOUT COMBUSTION COMPLETED EFFICIENTLY AIR ZONE BURNOUT AIR USED AS SORSENT TRANSPORT MEDIUM REBURNINOZo NATURAL GAS — REBURNING ZONE N% REDUCTION BY HYDROCARBON RADICALS INTRODUCED BY NATURAL 0

MAIN HEAT RELEASE ZONE EFFICIENT COMBUSTION AT LOW EXCESS AIR USING EXISTING EQUIPMENT

tion of plant efficiency. (See page 4-38 of the June and will be the host industrial site for the 50 megawatt 1986 issue for a discussion of the technology). The plant. The other industrial participaton in this project system will be demonstrated at different sizes at two includes the Niagara Mohawk Power Corporation, who site locations—a 5 megawatt plant in Dunkirk, New will be the host for the 5 megawatt plant, the Peabody York owned by Niagara Mohawk Power Corporation and Holding Company, and the Burlington Northern Rail- a 50 megawatt General Electric plant in Evendale, road. The institutional participation will include the Ohio. Ohio Department of Development, the Empire State Electric Energy Research Corporation, and the New A prime objective of the demonstration program is the York State Energy Research and Development Author- establishment of a high-performance, cost-competitive ity. The participants will contribute 50 percent of the environmentally compliant, coal-fired power plant in needed funding for the project. According to OCDO, the less-than 200 megawatt size. According to the the total cost of the project is $156 million, with DOE sponsors, this option will significantly reduce the fin- providing $78 million and OCDO providing $10 million. ancial risk associated with the addition of large capacity increments to meet projected needs. The demonstration program is proposed as a five-year project. Ohio Ontario Clean Fuels Inc. The phasing will permit the 5 megawatt plant to come on-line three years after project initiation. The initial This project is a prototype commercial coal/oil co- checkout and system characterization of the 50 mega- processing plant to be located in Warren, Ohio. This watt plant will start three years into the program with plant will convert high sulfur, high nitrogen, Ohio full-scale operaton at the industrial site in four and bituminous coal and poor-quality petroleum to produce one-half years. clean liquid fuels. The process to be utilized is HRI, Inc.'s proprietary commercial ebullated-bed reactor The General Electric Company is the lead organization technology. In this process coal is blended with residual

4-14 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 oil and both are simultaneously converted to clean Weirton Steel Corporation distillate fuels. A "typical" C4-975°F distillate fuel will contain 0.1 percent sulfur and 0.2 percent nitrogen. This project will involve a demonstration of the Kohle The prototype plant will process 800 tons per day of Reduction process which was developed by Korf Engi- coal, plus residual oil sufficient to yield 11,750 barrels neering (a Federal Republic of Germany company). The per day of distillate product. Startup of the plant is process replaces the two-step coke oven/blast furnace slated for 1990. approach to producing pig iron from iron ore and metallurgical coal with an integrated two component The sponsors (Ohio Ontario Clean Fuels Inc., Stearns oxygen-blown blast furnace system capable of operation Catalytic Corporation, and BRI, Inc.) proposed to pro- on a variety of United States coals. The system vide 80 percent of the project cost. According to consists of an upper "reduction shaft" and a lower OCDO, total project cost if $217.5 million of which "melter-gasifier" component. Iron ore, along with an DOE will provide $45 million and OCDO will provide appropriate flux (e.g., limestone), is fed into the top of $2.5 million. (Details of the Hal coal/oil coprocessing the reduction shaft where it is reduced to sponge iron technology are explained in the article beginning on by the off-gas from the lower melter-gasifier section. page 4-27 of the December 1984 issue.) The lower section is an oxygen-blown fluidized bed coal gasifier. In this section the sponge iron is melted and the resulting pig iron and slag are separated and tapped The M. W. Kellogg Company as in a blast furnace. The low/medium-BTU, sulfur- free off-gases from the process (sulfur is captured by At the Appalachian Project the applicants will demon- the limestone and remains in the slag) are scrubbed to strate an advanced integrated coal gasification com- remove particulates and are available for site use. bined cycle (IGCC) system. The project, to be located at Cairnbrook, Pennsylvania, will feature the Kellogg- The Kohle Reduction process has been tested in a Rust-Westinghouse (KRW) ash agglomerating fluidized- 66,000 tons per year pilot plant using a wide range of bed gasification process. One KRW gasifier operating coals and iron ores. The proposed project calls for the in the air-blown mode will convert 485 tons per day of design and construction of a 330,000 ton (iron) per year bituminous coal into a low-BTU fuel gas for use in an demonstration plant at the Weirton Steel plant in advanced combustion turbine generator. Steam gener- Weirton, West Virginia. The plant will operate on a ated from the combustion turbine exhaust and from the variety of United States feedstocks. A plant of the gasifier heat recovery system will be fed to a steam same technology and size in South Africa is to be turbine generator. completed in late 1987.

The 60 megawatt demonstration project will feature a Weirton Steel intends to fund nearly 65 percent of the hot gas cleanup system which delivers fuel gas at 1,0000 cost of the project. to 1,2000F to the combustion turbine, thus avoiding inefficient lower temperature cleanup processes. This system uses in-bed desulfurization and a hot-sulfur- removal polishing step consisting of a zinc ferrite sorbent bed. Particulates will be removed by a sintered metal filter. OHIO MAKES AWARDS TO 24 CLEAN COAL The system, if demonstrated as proposed, would be PROJECTS highly efficient with heat rates around 7,800 BTU per kilowatt hour. Various sizes of commercial plants can On September 15, 1986 the Ohio Coal Development be configured by using the 60 megawatt module that Office (OCDO) announced that it had awarded will be demonstrated. Other applications for the sys- $41.6 million (pending successful negotiations) to tem are cogeneration and retrofit of combustion tur- 8 clean coal demonstration projects and 16 research bines and gas-fired combined cycles, according to the projects in Ohio. These projects are listed in Table 1. project sponsors. These projects represent a total investment of more than $600 million in new technologies and processes. The participants in the project include: The M. W. As described on page 4-16 of the June 1986 issue of the Kellogg Company, the developer of the gasification Pace Synthetic Fuels Report, the 24 projects were technology through KRW Energy Systems Inc. (a com- Oat- from 176 proposals that were submitted to pany jointly owned by M. W. Kellogg and the Westing- OCDO in March 1986. house Electric Corporation); the General Electric Com- pany; and the Pennsylvania Electric Company (Penelec). Funds for Ohio's Clean Coal program were authorized by Ohio voters in a constitutional amendment known as State Issue 1. For research projects OCDO is permitted These particpants have proposed to provide 50 percent to fund up to two-thirds of the total project cost, or of the project costs. (A detailed description of the $150,000 whichever is less. For larger projects, OCDO Appalachian Project begins on page 1-1 of the June can fund up to one-half the total project costs of a 1986 issue. The technology is described in this issue in development project (pilot plant) and up to one-third of the article entitled "KRW Pilot Plant Successfully the cost of a demonstration project, up to a maximum Demonstrates In-Bed Desulfurization.") of $10 million.

4-15 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 As shown in Table 1, tour of the eight demonstration under the federal Clean Coal Technology Program. The projects selected by OCDO will also receive financial status of the federal program is briefly described in the support from the United States Department of Energy preceding article in this issue.

TABLE 1 PROJECTS RECEIVING AWARDS IN OHIO'S CLEAN COAL PROGRAM (Dollars) Total DEMONSTRATION PROJECTS Project Cost Ohio Funding DOE Funding (million) American Electric Power Company—Pressirized 175.6 10 million 60 million fluidized bed combustion combined cycle retrofit of the Tidd Station Babcock & Wilcox—Extended tests of limestone. 27.5 9.8 million 7.5 million Injection multi-stage burner (LIMB) technology (EPM$1.8 million) plus sorbent duct injection at the Edgewater Station Babcock & Wilcox—Post-combustion sulfur dioxide 7.2 3.6 57,248 control project at the Toronto Station (EPM$2.4 million) Battelle Memorial Institute—Determine the 2.6 259.860 0 applicability of spray-dry scrubbing of high-sulfur coal fuel gas Columbia Gas System Service Corporation—Cata- 1.2 612,032 0 lytic reduction process for coal fuel kas General Electric—integrated gasification 156 10 million 78 million combined cycle using steam-injected gas turbine and hot gas cleanup Ohio Ontario Clean Fuels, Inc.—Coal/oil copro- 217.5 2.5 million 45 million ceasing using Hal technology Scio Pottery—industrial application of steam 6.45 215,000 plus 0 and electricity coproduction 2.5 million loan RESEARCH PROJECTS Babcock & Wilcox (Ailiance)—Swelling techno- not disclosed 150,000 0 logy for deep cleaning of coal Battelle (Columbus)— Selective oxidation de- not disclosed 75,000 0 sulfurization process Lambda Group, lac.—Microbial desulfurizatlon not disclosed 66,500 0 process for clean coal fines Ohio Department of Natural Resources/Geological not disclosed 500,000 0 Survey—To characterize Ohio's coal resource by seam and perform washability tests on each type of Ohio coal - Ohio Edison/Electric Power Research Institute— not disclosed 150,000 0 Clean coal fuels management Ohio State Unlversity/Cerbogel, Inc.—Sulfur not disclosed 150,000 0 reduction by physical cleaning and In-flame sulfur absorption Ohio State Universlty—Combined chemical and not disclosed 150,000 0 physical coal cleaning process Ohio State University--Sulfur extraction, not disclosed 66,000 0 separation by supercritical fluids Ohio State University—Microbial clean coal not disclosed 150,000 0 processing Ohio University—Limestone emission control not disclosed - 144,000 0 system University of Akron—Sulfur extraction by not disclosed 142,000 0 supercritical fluids University of Cincinnati—Sulfur dioxide removal not disclosed 106,000 0 through a circulating fluidized bed absorber University of Toledo—Hollow fiber membrane not disclosed 145,000 0 desuliurization University of Cincinnati—Sulfur dioxide removal not disclosed 74,000 0 through calcium/ammonia spray dryer University of Cincinnati—Organo-metallic not disclosed 119,000 0 complex process for sulfur and nitrogen oxide removal University of Cincinnati—ion exchange resin/ not disclosed 148,000 0 fixed bed desulfurization Not listed by DOE as an award in the Clean Coal Technology Program

4-16 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

DOE SUBMITS CLEAN COAL REPORT TO CONGRESS The size of the projects ranged from 10 tons of coal per day to 1,450 tons per day. A wide variety of products On August 15, the United States Department of Energy would be produced by the projects including cleaned (DOE) submitted a report to Congress summarizing the coal, steam, electricity, fuel gas, distillate fuel, coke, proposals that were received in response to the Clean methanol, and iron. Project schedules ranged from one Coal Technology Program Opportunity Notice issued by year to ten years, with three-fourths of the projects DOE. As described in the article in this issue entitled having schedules of 5 years or less. "Nine Clean Coal Projects Chosen by DOE," DOE has selected nine projects for funding in the program. The proposed technologies could be used by all five These projects were selected from Si proposals that energy consuming sectors: utilities, industrial, commer- DOE received in April 1986. The Report to Congress cial, residential, and transportation. Most technologies reviews the solicitation process used by DOE for re- (42) could be used by the utility sector, while 31 could ceiving proposals, summarizes each of the 51 proposals, be used by industry. Once commercialized, most tech- describes the nine categories of clean coal technologies nologies could use most types of United States coals. that were submitted, and reviews special issues related to the solicitation such as environmental requirements All 51 projects are listed in the Appendix of this issue and cost. of the Pace Synthetic Fuels Report with the projects' capacity, schedule, end-use applications, and coal type. Congress authorized $397.6 million in funds for the Clean Coal Technology program, of which $25 million is Perhaps of most interest are the estimates of com- being held in reserve by DOE to cover potential cost mercialization potential of each of the technologies. overruns. Also, $4.9 million will be redirected to the Each submitting organization was required to estimate Small Business Innovative Research (SBIR) program, and when a technology would become a viable commercial operating funds will be withheld. Thus, funds for actual process. As shown in Table 2, all technologies were awards will total $362 million over a three-year period estimated to be viable by 1995, with some technologies as shown in Table 1. ready for commercialization as early as 1991. How- ever, scale-up required to reach commercial size varied widely for the proposed projects. Some projects were TABLE 1 proposed at a commercial scale (i.e.: scale-up of 1:1). Other projects would need to be scaled up by a factor BUDGET FOR THE CLEAN COAL of 100 before the technology would be at a commercial TECHNOLOGY PROGRAM size. (Thousand Dollars) Lastly, DOE's Report to Congress includes brief descriptions of each of the nine types of clean coal FY 1986 FY 1987 FY 1988 technologies. DOE also provides a summary of the environmental benefits and the current status of devel- Congressional Appro- 99,400 149,100 149,100 opment of each technology. Two-page summaries of all priations 51 proposed projects conclude DOE's report. Overrun Reserve 6,250 9,375 9,375 SBIR Program 1,226 1,837 1,837 Operating Expenses 1,491 1,988 1,988 Net Monies Avail- 90,433 135,900 135,900 able for Award

DOE separated the 51 proposals into ten major categories as follows:

Number of Technology Category Proposals Coal Preparation and Waste Recovery 10 Advanced Combustion 4 Fluidized-Bed Combustion Atmospheric Fluidized-Bed Combustion 7 Pressurized Fluidized-Bed Combustion 2 Flue Gas Cleanup 7 Surface Coal Gasification 9 Gasification/Fuel Cells 3 In Situ (Underground) Coal Gasification 1 Coal Liquefaction 3 Industrial Processes 3 Other 2

4-17 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 2

PROPOSERS ESTIMATES OF COMMERCIALrLA'[lON POT&(TIAL FOR CLEAN COAL TECHNOLOGIES

PROJECTED PENETRATION DATE OF REGION OF SCALE-UP POTENTIAL OF POTENTIAL TECHNOLOGY C'L APPLICATION COAL TYPE FACTOR MARKET MARKET BY 1995

COAL PREPARATION 1990-1995 Notional All ranks and 1-1 to 1-100 100.000.000 to 1-7 AND WASTE RECOVERY conventional 200.000.000 tons coal waste per-yew

ADVANCED COMBUSTION 1990-1995 National All ranks 1-1 to 1-50 20.000 to 1-20 35.000 combustors

ATMOSPHERIC 1989-1995 Notional All ranks 1-1 to 1-2 11,000 to 5-30 FLUIDIZED-BED 45.000 1W COMBUSTION

PRESSURIZED 1991-1995 Notional All ranks I-I or modular 60,000 to 5-10 FLUIDIZED-BED replication 112.000 MW - COMBUSTION

FLUE GAS CLEANUP 1988-1993 9 midwest All ranks I-S to 1-25 79.000 to 20-50 to 31 state 130.000 1W region

GASIFICATION 1990-1993 Notional All ranks 1-1 to 1-20 0.2 to 5.0 Quads 1-60 per year

GASIFICATION/ 1991-1995 Notional All ranks 1-1 to 1-10 3,000 to 1-5 FUEL CELLS 34,000 MW

IN-SITU 1990-1995 Western U.S. Sub-Bituminous 1-1 In excess or i-s GASIFICATION Bituminous 100.000.000 tons of cool per year

LIQUEFACTION 1995 Notional All ranks 1-2 to 1-100 230,000 BPD 1-5

INDUSTRIAL 1991-1995 National All ranks 1-3 to 1-90 30 to 60 1-5 PROCESSES million tons per year

OTHER N/A N/A N/A N/A N/A N/A

4-18 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENERGY POLICY & FORECASTS

UTILITIES ENTHUSIASTIC ABOUT TABLE! COAL GASIFICATION TECHNOLOGY

In a panel discussion titled "Utilities Attitudes Toward ANTICIPATED EMISSIONS FROM Synthetic and Advanced Fossil Fuel Options," which COAL-FIRED PLANTS took place at the Alternate Energy '86 Conference, all utilities participating agreed that Integrated Gasifica- tion Combined Cycle (10CC) is a promising technology, Zero Discharge and that it will be a key power generation option for PCF IGCC utilities in the near future. The participants included, Liquid & Solid Atmospheric Lb/MM BTU Lb/MM BTU Robert Dietch, Vice-President at Southern California Edison Company (Socal) and chairman of the Utility Central Utah Coal Coal Gasificaton Association, John W. Arlidge, Vice- President with Nevada Power Company, and Samuel S02 0.100 0.030 Brown, Vice-President with Virginia Power. NO, 0.440 0.160 Particulate 0.015 0.015 Studies of a second generation 10CC plant have con- vinced Soeal that 10CC plants are competitive with Altos Coal conventional coal plants and otter substantially greater 502 0.100 0.059 financial and operational flexibilities than other alter- NO 0.440 0.170 natives. Particulate 0.015 0.015 Brown, of Virginia Power, feels that 10CC technology * PCF-pulverized coal-fired stands out as "the most promising and timely answer to "10CC-integrated gasification combined cycle the utilities' supply problems." He rules out conventional power generating plants to meet rising demand due to long lead times and huge capital outlays. Vir- ginia Power is studying several alternatives to conventional plants including 10CC, atmospheric fluidized bed Robert Dietch, of Soeal, also agrees that the emissions combustion (AFBC), and fuel cells. Fuel cells have of all airborne pollutants are lower for an 10CC plant shown excellent potential, but they are not expected to than for any commercially available fossil fuel techno- be cost effective until well into the next century. logy. He also lists an additional advantage of AFBC prospects are good also, but tests have been 10CC—the quantity of solid waste generated is lower small-scale only and APBC is not expected to be than for conventional coal plants. Virginia Power commercially viable in the needed size before 2000. concurs with this assessment and states that "10CC plants produce only about one-quarter of the solid IGCC is likely to be Virginia Power's choice for future wastes from a pulverized coal plant." They also state power generation. They have found 10CC to have many that some components of IGCC can be out of service advantages over other alternatives. Combined cycle while other components are operating, therefore IGCC units have operated for 17 years and the technology has lends itself to easy maintenance and high unit availabi- been thoroughly proven. Construction time is short and lity. 10CC capacity can be added in small increments, enabling utilities to better match capacity additions Along with the obvious advantages of IGCC technology, with demand growth. all the participants agreed that there are some potential problems and questions to be settled about the 10CC also has very low emission rates. All of the process. Nevada Power has found a few major draw- participating utilities felt that these low emissions backs with the Cool Water plant. One is that the were a major advantage of IGCC. John Arlidge of Process is a chemical process unknown to utility engi- Nevada Power states that Cool Water (an 10CC test neers and power plant operators. Virginia Power plant and the first utility plant licensed in the state of agrees, stating that "our operators would need thorough California to use coal to generate electricity) has training in chemical plant operations." They also site "demonstrated very low emissions for SO2, NOx, and another disadvantage of 10CC, stating that gasifiers particulates." The low emission rates will be especially are relatively expensive and that uncertainties exist valuable if federal law requires utilities to reduce total about their durability and operating and maintenance emissions, particularly if the law permits trade-of fs costs for various types of coal. among units. Test projects such as Cool Water are addressing the Table 1 shows Nevada Power's comparison of the antici- above questions; demonstrations so far have been most pated emission levels between an IGCC plant and a encouraging and Cool Water is making believers out of conventional pulverized coal-fired plant. traditionally conservative utilities.

4-19 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 There is, however, one more concern with the 10CC technology. Robert Dietch states, "With the current oil glut and depressed oil prices, the enthusiasm and the urgency to pursue an aggressive RD&D effort to com- mercialize these promising technologies has waned. The federal government's support for the synthetic fuels industry has all but vanished and, by and large, advanced clean coal technologies have been left to the private sector to develop, demonstrate, and commer- cialize." He believes that now is the time to convince energy policy makers to prepare for the inevitable oil price increases and potential supply disruptions that will follow the current oil glut.

Socal has concluded that the most cost-effective approach to fund demonstration projects is something along the line of the Cool Water program where interested parties pooled their technical expertise, operational experience, and financial resources together with a price guarantee (or capital cost share) from the government to make it happen. In a broader sense, synthetic and advanced fossil fuels technologies must be evaluated relative to other conventional options and advanced technologies which are or could become available to utilities in the near future. Samuel Brown of Virgins Power sums it up stating, "It's vital that development of 10CC be expedited, because this promising technology is a key part of utilities' plans and the country's future."

4-20 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ECONOMICS

UCU ECONOMICS AFFECTED BY GAS QUALITY The study was undertaken to determine the relationship between reactor coal utilization (which influences gas A presentation by Energy International, Inc. at the 12th quality) and final product costs. There are two major Underground Coal Gasification Symposium, August effects on gas compositions. 1986, illustrates the effect of gas quality on project economics. • High water contents due to groundwater influx into the system. Reported values for product In the horizontal UCG process, two wells are drilled water content range from 18 to 65 percent. into a horizontal coal seam, establishing a link zone between the wells, igniting the seam and gasifying the • The decline of gas quality over the life of a coal by injection of air or oxygen and steam into one horizontal UCO reactor. well and removing the gasification products from the production well. As the process continues, the reactor A Process Economic Model was utilized to evaluate a grows to the roof laterally as well as along the zone set of process parameters that included: between the wells. The oxidation zone is continually growing, while the reduction and pyrolysis zones remain • Product water contents of 20, 34, and 50 per- constant or diminish in size. Gas quality tends to cent by volume degrade over the life of a horizontal UCG reactor with • Average product compositions representing 50, the gas heating value dropping as much as 50 percent. 75, and 100 percent of maximum reactor life. The process efficiency is reduced as well. Examples of the economic data are shown in Tables Energy International carried out a study based on a and 2. commercial facility near Hanna, Wyoming producing 40 million standard cubic feet per day of methane. The resource characteristics are: TABLE 1 Depth 400 feet Thickness 30 feet CAPITAL SUMMARY Rank Subbituminous A Ash 30% Sulfur 0.6% MM$ The financial assumptions are: Total Capital Investment Return on Capital, % 18 Upgrading Plant Process 64.974 Taxes, % so Upgrading Plant Utility 19.444 Field and Surface Facilities 15.722 Site Development 8.700 The utility rates and options are representative of those Miscellaneous Offsites 12.017 for a project located in south-central Wyoming. They Engineering Fee 12.086 are: Construction Overhead 9.064 Base Plant Cost 142.002 • Electric power is imported at 3.20 cents per KWH Total Catalyst Investment 2.044 • Oxygen is imported at $30 per ton Contingency Allowance 21.608 Contractors Fee - 4.260 • Boiler fuel is site generated off-gas plus fuel Special Charges 8.643 gas Total Plant Investment 178.563 • Major equipment is HP stream driven. Working Capital 22.936 The well field parameters included: Start-Up Costs 5.000 Process Well Spacings 100 feet Total Capital Required 206.499 Well Line Spacings 150 feet Coal Gasification Rate 67 Tons/Day Monitor Wells I/Process Well

4-21 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 2 The costs for resource extraction tend to be fixed for a given well pair. Once the recovered resource reaches a certain level, the incremental benefits for additional ECONOMIC SUMMARY production continually decline. On the other hand, product processing costs tend to be proportional to the volume of gas handled. When product quality declines, $/MMBTU Incremental costs increase. Thus, there is a trade off Main between resource recovery costs and processing cost. Operating Costs $/MM/Yr Product The Energy International study clearly shows the impor- Coal Royalty 2.102 0.263 tance of product quality. It suggests that there may be Raw Water Costs 0.600 0.075 too strong an emphasis on resource recovery In the Catalyst & Chemical Costs 18.900 2.368 design of UCG modules with too little attention being Imported Coal Cost 0.000 0.000 paid to operational decisions for abandonment of reac- Other Operating Costs 0.000 0.000 ton and control of product water content. Well Operating Expense: Injection 5.531 0.693 Production 0.000 0.000 # IS IS Link 0.000 0.000 Monitor 4.366 0.547 Average Main & Cross Line 0.744 0.093 STEAM-INJECTED GAS TURBINES Expense UNECONOMICAL WITH COAL Local Pipe Relocation Expense 1.070 0.134 GASIFICATION EQUIPMENT Production Equipment Reloca- 2.274 0.205 tion expense Researchers at the Electric Power Research Institute Operating Labor 2.010 0.252 (EPRI) conducted a series of engineering and economic Operating Labor Burden 0.704 0.088 studies to assess the possibility of substituting steam- Supervision 0.407 0.051 injected gas (STIG) turbines for the gas turbines cur- Operating Supplies 0.603 0.076 rently proposed for use in British Gas Corporation General Administrative Overhead 3.263 0.409 (BGC)/Lurgi coal gasification-combined cycle plants. Miscellaneous Operating Costs 3.719 0.466 Maintenance Materials & Labor 4.085 0.512 The study (EPa! AP-4507) sought to determine whether Total Operating Costs 50.649 steam-injected gas turbines and intercooled steam- 6.344 injected gas turbines, as proposed by General Electric Capital Charges 32.266 4.042 would be economically competitive with conventional gas and steam turbines when integrated with coal Total Product Cost 82.915 10.386 gasification equipment.

Approach

Incremental effects for the various parameters are The researchers developed engineering designs and cost shown in Table 3. The trends are similar in all cases. estimates for a plant using STIG turbines and for a The benefits of minimizing product water content are plant using intercooled steam-injected gas (ISTIG) tur- evident. Even more striking is the benefit for switching bines. At the time of the study neither STIG nor ISTIG reactors short of burnout The cost benefits of an turbines were commercially available. Each turbine Improved product quality more than compensate for the would require development, with ISTIG requiring major poorer resource recovery. development. The purpose of EPRPs study was to determine if development would be warranted for this application, i.e., integration with the BGC/Lurgl gasification system. TABLE 3 The EPRI researchers used a previous BGC/Lurgi gasification-combined cycle study (EPRI AP-3980) as a data base and adjusted the heat and material balances to INCREMENTAL SNG PRODUCT COSTS (Dollars Per Million TU) reflect the substitution of the STIG and ISTIG equipment for the combined cycle equipment used in that study. Reactor Life, Fraction 0.40 0.70 1.00 % Water in Raw Product Gas: Results 20 0.05 0.00 0.78 33 0.48 0.45 1.31 The study estimates of plant efficiency, plant cost, and 50 1.33 1.41 2.40 levelized electricity cost (all cost in constant 1984 dollars) offered no incentive for further developing the STIG and ISTIG concepts. For example, the study indicated that the STIG plant efficiency was much

4-22 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 lower than that of the conventional plant, 33.4 versus Levelized cost of electricity was estimated based on 39.4 percent (see Table 1). The ISTIG plant efficiency was 39.1 percent, virtually the same as that of the the same criteria used for evaluation of the BGC/Lurgi conventional plant. gasification-combined cycle plant. The researchers found that the cost of electricity from a STIG plant was substantially higher than from the combined cycle TABLE 1 plant. However, the ISTIG plant cost of electricity was estimated to be slightly higher, but very close to the cost of electricity from the combined cycle plant (see Table 3). SUMMARY OF PLANT PERFORMANCE AT 59°F AMBIENT TEMPERATURE infAURDWI BOC/Lurgi Coal Gasifica- tion Integrated With: COST OF ELECTRICITY SUMMARY Combined (At 65% Annual Capacity Factor) Cycle §IIQ !BQ New Plant Power (MW) 509.0 443.1 522.0 Net Plant Efficiency (%) BGC/Lurgi Levelized Cost 39.4 33.4 39.1 Gasification Water Requirements, 8.4 8.5 6.7 of Electricity GPM/MW Integrated With: (Mills/K WH) Combined Cycle 44.91 STIG 53.73 ISTIG 45.51

The EPRI study indicated that the capital costs for a Expressed in First Quarter 1984 dollars plant using STIG turbines ($1,270 per kilowatt) would be considerably greater than a plant with conventional combined-cycle equipment ($1,036 per kilowatt), Table 2. The capital costs for the plant using ISTIG turbines ($1,067) were comparable to those estimated Conclusion for the conventional plant. The major area of change in the cost estimates was the power and steam production area, followed by the oxidant production, water treat- The EPRI researchers concluded that in this application ment, electrical and control, and heat rejection areas. (integrated with BGC/Lurgi coal gasification equip- Cost estimates for other areas remained unchanged. ment) the STIG and ISTIG turbines would not have economic advantage over conventional combined-cycle systems and, as now conceived, would not warrant TABLE 2 further development. The scientists stress however, that these results do not preclude considering these turbines for other applications—for example, direct natural gas-fired plants. SUMMARY OF PLANT COST ESTIMATES (First Quarter 1984 Dollars)

BGC/Lurgi Coal Gasifica- tion Integrated With: Combined Cycle STIG ISTIG Total Cost (Million $) 527.9 563 557 Specific Cost ($/FCW) 1,036 1,270 1,067

*Plant only. Does not include land, start-up, and working capital costs and allowance for funds used during construction

4-23 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TECHNOLOGY

KEW PILOT PLANT SUCCESSFULLY DEMON- Fines elutriated from the top of the gasifier are cap- STRATES IN-BED DESULPURIZATION tured in an external cyclone and recycled to the gasifier. Fines escaping the cyclone are captured in a In-bed desulfuriza tion using calcium-based sorbents has sintered metal filter. This filter is capable of operation been evaluated in the 1(11W pressurized fluidized bed up to 1,200°F and removing all fines one micron or gasifier at Waltz Mill, Pennsylvania as part of a joint larger. program with 1(11W Energy Systems Inc. and the United States Department of Energy. For combined cycle The process has been demonstrated for a wide range of power generation or synthesis gas applications the sys- feedstocks and conditions at the Waltz Mill 15 to tem may have economic advantages over conventional 30 tons per day Process Development Unit (PDU). In cold gas cleanup. Recent tests of the concept were addition to its ability to process a variety of feed- summarized at the American Chemical Society meeting stocks, the process has also demonstrated effective in September 1986. utilization of coal fines, high overall carbon conversion efficiency, and virtual elimination of tar and oil in the The 1(11W gasifier is a pressurized fluidized bed process product gas. that can produce low-BTU (100 to 160 BTU per standard cubic foot) or medium-BTU (200 to 300 BTU per stand- Hot gas clean-up via the in-bed desulfurization concept ard cubic foot) gas. The essential features of the involves the removal of hydrogen sulfide and COS by gasifier are shown in Figure 1. Coal or lignite in the reacting them with dolomite or limestone which is fed size range of 1/4 inch by zero is injected into a jet into the gasifier freeboard to mix with the bed char. located in the combustion zone. The coal is rapidly 1(11W has conducted five in-bed desulfurization PDU devolatilized and decaked, and the residual char is tests to demonstrate the feasibility of this concept. In gasified in the upper region of the fluidized bed. The addition to achieving over 90 percent desulfurization, jet induces vigorous mixing of solids between the lower the process cold gas efficiency improved 20 percent combustion region and the upper gasification region. over conventional PDU gasifier operation. The coal ash undergoes partial melting and sintering in the hotter combustion jet, and the resulting 'glue' The spent sorbent, calcium sulfide (CaS), is eventually action causes fine ash particles to agglomerate. These withdrawn through the gasifier annulus along with ash ash agglomerates are separated from the char in a agglomerates. Calcium sulfide is a reactive waste that separator in the bottom section of the gasifier. can recombine with acidic water to release toxic hydrogen sulfide gas. Further treatment via oxidation is necessary to convert the calcium sulfide to the environmentally acceptable sulfate. The waste can then be disposed of in conventional solid waste landfills.

Test Results

PDU tests were conducted to first demonstrate gasifier operability and then to optimize the desulfurization process. Table 1 summarizes the results of the in-bed desulfurization program.

According to 1(11W, equivalent desulfurization for limestone injection into conventional furnaces and atmospheric fluidized bed combustors requires calcium sulfide molar feed ratios of 3 to & compared to 1.5 to 2.0 demonstrated by the 1(11W process. Desulfurization in the gasifier reducing environment occurs at a faster rate for the hydrogen sulfide/calcium oxide reaction compared to the sulfur dioxide/calcium reaction. Also, the absence of sintering maintains a relatively high surface area compared to typical calcined surface areas. The reducing environment apparently does not increase sintering, according to the researchers.

Although the sulfur content of the feed coal varied widely, the sulfur species concentrations in the product gas were characteristically in the range of 500 to 650 ppm for hydrogen sulfide and 160 to 270 ppm for COS. Thus, the degree of desulfurization increased as the sulfur input rate (coal sulfur content) increased. Also, desulfurization varied inversely with the steam concentration of the product gas. Because hydrogen sulfide concentrations were 200 to 400 ppm higher than

4-24 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE!

SUMMARY OF PRELIMINARY KEW IN-BED DESULFIJRIZATION RESULTS

Coal Gas Steady State Coal Sulfur Ca/S Molar Composition Desulfurization Type Content Sorbent Type Feed Ratio L!2 S COS Achieved (%) (ppm) (-PP m) (%) Pittsburgh No.8 2.3 Glass Dolomite 1.67 550 263 86 Pittsburgh No.8 4.5 Glass Dolomite 1.55 679 216 92 Pittsburgh No. 8 4.5 Greer Limestone 1.84 651 258 90 Wyoming 2.0 Glass Dolomite 2.00 484 167 91

equilibrium levels, the researchers do not believe that releasing more than that level may be regulated as equilibrium limits desulfurization. KRW investigations hazardous. of the mechanism by which water limits desulfurization are currently underway. Unsulfated in-bed solid waste samples from the gasifier discharge, fines loss, and separator pit sludge were Only small incremental increases in desulfurization analyzed for reactive sulfide levels and extraction were achieved with large increases in the calcium/sul- procedure toxicity. The concentration of extraction fur feed ratio as shown in Table 2. These results differ procedure toxic metals were all significantly below the significantly from fluidized bed combustor experience RCRA toxic levels. As shown in Table 3, the fines loss where desulfurization is directly proportional to the samples from the process had extremely low reactive calcium sulfide feed ratio. sulfide levels of less than 5 ppm. Separator pit sludge, which consists of wet fines carryover from the quench/cooling system, also had less than 5 ppm reac- TABLE 2 tive sulfide. However, all untreated PDU withdrawal wastes may be potentially hazardous when subjected to the interim EPA reactivity test. INCREMENTAL INCREASE IN DESULFURIZATION AS A FUNCTION OF Ca/S RATIO FOR PITTSBURGH 4.5% SULFUR COAL TABLE 3

Observed % Observed Equilibrium REACTIVE SULFIDE TEST RESULTS FOR Ca/S Desul- Hydrogen Hydrogen KRW IN-BED DESULPURIZATION Feed Ratio furization Sulfide Sulfide SOLID WASTES FROM TP-036-3 (ppm) -F--T- 1.84 91 651 180 Sample Sulfide Reactive Sulfide 3.41 94 424 242 (Wt %) (mg/kg) Untreated Gasifier 8.6 l,200 Discharge Fine Loss 1.3 4 S Separator Pit Sludge 0.9 C5 KRW has investigated waste characterization testing and disposal laws and determined that coal gasification wastes are not on any of the promulgated hazardous wastes lists by specific and non-specific sources. Therefore it is the responsibility of the generator to determine if the released waste possesses any of four KRW has sulfated the gasifier discharge material in hazardous characteristics—corrosivity, ignitability, laboratory reactors under a variety of experimental reactivity, and extraction procedure toxicity. In KRW's conditions. The test configuration and experimental opinion reactivity and extraction procedure toxicity are conditions summarized in Table 4 reduced reactive the most critical characteristics for in-bed waste dis- sulfide levels of the sample to less than 500 milligrams posal. Presently, the EPA has only an interim test per kilogram. These results are encouraging to KRW method and reactivity threshold of 500 milligrams of because sulfation is the simplest and most direct evolved hydrogen sulfide per kilogram of waste. Wastes method of treating in-bed wastes. Tests are underway

4-25 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 at the PDU to evaluate the technical feasibility of a time in the bed so that a larger portion is consumed continuous waste treatment process. before escaping the bed surface. Gasifier performance was observed to improve during in-bed testing as shown in Table -5. Sorbent injection Conclusions increased the cold gas efficiency and decreased the apparent fines elutriation rate. Cold gas efficiencies KEW concludes that in-bed desulfurization integrated increased dramatically during in-bed desulfurization with hot particulate removal is potentially the most from 50 to 70 percent. The increase in cold gas economical process for converting all types of United efficiency and corresponding drop in air/coal ratio may States coals to electricity while complying with New indicate improved gasification, according to KRW. Source Performance Standards (NSPS) for sulfur re- Catalytic effects of calcium are one of several poten- moval. Direct injection of calcium-based sorbents into tial contributing factors being investigated by KEW. the KEW gasifier demonstrated:

Reduced fines loss and elutriation rates are primarily • Desulfurization exceeding 90 percent for a the result of increased gasification rates and longer 4.5 percent sulfur coal tines residence times. Low gas by-passing as bubbles is thought to have increased fluidized bed filtering of fine • Cold gas efficiencies over 70 percent material, which in turn increased the fines residence • Feasible waste treatment by sulfation. TABLE 4

EXPERIMENTAL CONDITIONS, SULFUR ANALYSIS AND REACTIVE SULFIDE LEVELS OF SULFATED GASIFIER DISCHARGE

Furnace Oxygen Gas Re- Reactor Temper- Concen- Flow Contact active Total Percent Type ature tration Rate Time Sulfide Sulfur Sulfation (°F) (Vol %) (liters/ (hrs) (mg/kg) (wt %) (mole %) min)

Packed Bed 1,500 21 5 1 5 5.00 80.7 Fluidized 1,500 5 >10 1 '5 am nm Bed Open Dish 1,500 21 0 1 <5 7.48 63.4 Open Dish 1,500 21 0 3 45 8.02 74.0

am: not measured

TABLES

PILOT PLANT PERFORMANCE WITH IN-BED DESULFURIZATION

Gasifier Carbon Air/ Bed Conversion Cold Gas Coal Sorbent Coal Temperature Efficiency Efficiency (iE7iS) ("F) (%) (%) Pittsburgh - 4.28 1,846 90 50 Pittsburgh Dolomite 3.39 1,950 90 73 Pittsburgh Dolomite 3.37 1,970 91 72 Pittsburgh Limestone 3.27 1,830 92 70 Wyoming Dolomite 3.03 1,820 91 65

4-26 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Future development work at I{RW includes pilot-scale unit, 100 grams of coal (particle size -8 by 100 mesh) sulfation of the gasifier discharge and demonstration of were heated to 500°C in 40 minutes and maintained at throughput improvements. Laboratory scale investiga- that temperature for one hour. tions of desulfurization and the effect of calcium-based sorbents on char gasification will be conducted in Sufficient coal was used to generate enough liquids for parallel with the pilot plant testing to determine the various analyses including ultimate, distillation, den- controlling mechanisms for the relevant reactions. sity, and viscosity tests. In selected experiments, pour point and Conradson carbon residue of the liquids were KRW is also developing an external bed desulfurization also measured. Two high-volatile coals were system using zinc ferrite sorbent that is capable of tested—Pittsburgh No. 8 and Illinois No. 6. The analy- removing sulfur compounds in a hot (1,1000F) coal gas ses of these coals are listed in Table 1. Product gases stream to 10 ppm. Regeneration tail gases from the were collected and analyzed using gas chromatographs. zinc ferrite unit will be recycled to the gasifier where the sulfur compounds will be captured by the sorbent. Installation and testing of the external bed desulfurization system is currently underway at the Waltz Mill TABLE 1 KRW Process Development Unit. As described in the Government portion of the Coal ANALYSIS OF COALS USED IN Section in this issue, the technology was selected by MILD PYROLYSIS TESTS DOE for funding in the Clean Coal Technology program. (AS-RECEIVED BASIS) A 485 tons per day KRW gasifier with hot gas cleanup (Weight Percent) will be used to generate 60 megawatts of electrical power at the Appalachian Project. Pittsburgh Illinois No. 8 Coal No. 6 Coal Carbon 77.18 69.3 Hydrogen 5.03 4.75 Nitrogen 1.44 1.32 Sulfur 1.98 3.2 Volatile Matter 37.86 36.3 HIGH QUALITY LIQUIDS PRODUCED BY MILD Moisture 0.57 4.05 PYROLYSIS OF COAL-LIME MIXTURES Ash 7.27 8.41 Heating Value (BTU/Lb) 13,976 12,523 Pyrolysis is one of several technologies that can be used to produce liquids from coal. Recent laboratory tests were conducted at the Department of Energy's (DOE's) Morgantown Energy Technology Center (METC) to evaluate the concept of slowly heating coal in the presence of lime to produce pyrolysis liquids. Results of these tests were summarized by M. H. Khan in a recent Test Results report entitled "Production of High-Quality Liquid Fuels from Coal by Mild Pyrolysis of Coal-Lime Mix- tures," DOE/METC-86/4060. Calcium oxide was utilized as an additive in the pyrolysis experiments because of its desirable reactivity (i.e., The author notes that when coal is pyrolyzed slowly in hydrogen sulfide capture) and availability. Some results the presence of calcium oxide in a batch or fixed-bed regarding the effects of calcium oxide addition on the system, the yield of liquid is not maximized. However, yield and composition of devolatilization products are the quality of the fuel is superior to that obtained in a shown In Tables 2 and 3. The author concludes that the high-heating-rate process. For example, a high-quality results demonstrate that the presence of calcium oxide liquid fuel can be produced in a relatively low-cost, during coal devolatilization significantly reduces the batch or fixed-bed, low-pressure, slow-heating-rate sys- yield of hydrogen sulfide. For example, when 21 weight tem which copyrolyzes coal with lime. The hydrocar- percent of calcium oxide (Ca:S = 6:1) was added to the bon-rich portion of coal can be recovered, while the by- coal, hydrogen sulfide in the gas was reduced from product char can be used for combustion or gasification 3.7 volume percent to 0.05 percent for the Pittsburgh purposes. The usability of the by-product char is not No. 8 coal, and from 5.2 percent to 0.1 percent for the discussed in the report. Illinois No. 6 coal, while the total sulfur content of the solids increased due to the formation of calcium sulfide. Experimental Approach Another effect of calcium oxide addition that was A batch reactor (approximately 250 milliliter capacity) detected in the tests is the reduction of carbon dioxide was utilized in the study. This unit is similar to a yield in the pyrolysis product gases. The author attri- Fischer Assay apparatus, but was modified to collect butes this reduction in carbon dioxide yield to the the liquids and gases, and to introduce gas flow into the formation of CaCO3. For Pittsburgh No. 8 coal, pyro- bottom of the reactor through a distributor. In the lysis of coal in the presence of calcium oxide decreased

4-27 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

TABLE 2

EFFECTS OF CALCIUM OXIDE ADDITION ON THE YIELD AND COMPOSITION OF MILD PYROLYSIS PRODUCTS

Illinois ,F_Pittsburgh No. 8 No. 6 + Pitts- Wt% +21 Wt% 21 Wt % burgh Ca01 Ca02 Illinois Ca02 No. 8 (Ca/S = 3) (Ca/S = 6) No. 6 (Ca/S=3.75)

Total Gas (liter) 7.0 7.0 7.1 7.6 6.0 Char (wt %) 75.3 75.5 76.2 76.7 77.8 Tar (wt %) 17.7 17.5 16.5 14.0 13.0 Water (wt %) 1.6 1.6 2.2 6.0 7.0 Gas Composition (Vol %) Hydrogen 11.6 12.2 13.4 12.35 13.5 Carbon Monoxide 3.9 3.9 3.2 7.2 7.1 Carbon Dioxide 5.4 1.3 0.2 11.2 3.1 C1-C8 75.4 80.5 83.0 62.7 76.0 Hydrogen Sulfide 3.7 2.1 0.05 5.2 0.1 COS 0.39 na 0.03 0.528 0.09 Methane 49.8 na 53.7 48.26 49.0 Water 0.25 na 0.34 0.616 0.41 Liquid Characteristics H/C Ratio (Atomic) 1.35 1.30 1.31 1.42 1.32 Total Sulfur (wt %) 0.72 0.67 0.57 0.54 0.35 Total Nitrogen (wt %) 1.59 1.62 1.66 1.70 1.66 Oxygen, By Difference 7.89 6.55 5.82 12.44 8.42 (wt %) Heating Value (BTU/Lb) 15,926 15,986 16,581 14,980 15,905 Viscosity (centistokes 51.5 na 29.7 37.0 18.7 at 100°F) Conradson Carbon Residue (%) 6.07 na 5.22 na na Pour Point (OF) 50 na 45 Ash (wt %) 0.03 0.03 0.03 0.05 0.04 Density (g/cc) 1.0299 na 1.0157 na na APIOO Specific Gravity 5.9 na 3.8 na na (at 60°F) Phenol (wt %) 3.66 na 2.8 na na Methyl Phenol (wt %) 10.85 na 7.99 na na Dimethyl Phenol (wt %) 10.05 na 7.47 - - Char Characteristics (wt %) H/C Ratio (atomic) 0.43 na 0.55 0.41 0.57 Carbon (deaf)" 84.36 na 80.46 89.2 82.1 Hydrogen (deaf) 3.06 na 3.72 3.06 3.93 Nitrogen (deaf) 2.16 na 1.90 2.57 3.93 Sulfur (deaf) 1.58 na 2.20 na na Ash/Additive 9.98 na 38.21 9.58 32.98 Volatile Matter 13.51 na 14.80 15.64 18.15 Water 1.01 na 0.01 1.25 0.60 Heating Value (daaf) 13,946 13,962 13,594 (BTU/Lb)

Not available "American Petroleum Institute "Dry-ash and additive-free basis 1. Certified grade CaO from Fisher Scientific 2. CaO prepared by calcination of CaCO3 from Fisher Scientific

4-28 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 the yield of carbon dioxide from 5.4 percent to 0.2 per- 0.05 weight percent, and mercury and arsenic contents cent by volume. However, this decrease of 5.2 percent below 0.1 ppm by weight. Vacuum evaporation curves corresponds to the formation of less than I gram of for the liquids derived from Illinois No. 6 coal with and CaCO3, or less than 5 percent conversion of calcium without the presence of calcium oxide suggest that both oxide to CaCO3. samples can be evaporated almost entirely below 300°C. The average molecular weight of the pyrolysis liquids Two types of calcium oxide were used in the tests. The from Illinois No. 6 coal ranges between 250 and researchers noted that calcium oxide that was prepared 325 amu. by the calcination of CaCO3 was more reactive than purchased certified grade calcium oxide. Characteriza- tion of various limes is continuing. TABLE 3 In addition to improving pyrolysis gas quality, calcium oxide in the char is available to capture the evolving sulfur gases when the char is subsequently utilized. EFFECTS OF CALCIUM OXIDE ADDITION ON X-Ray diffraction studies indicate the presence of MILD PYROLYSIS PRODUCTS FROM calcium sulfide in the solid residue, suggesting to the PITTSBURGH NO.8 COAL FINES author that calcium oxide reduces the hydrogen sulfide (MINUS 100 MESH) yield by forming calcium sulfide and water. The total gas yield remained almost unchanged in Pittsburgh No. 8 coal and was slightly reduced in Illinois No. 6 coal bOg Coal bOg Coal when calcium oxide was applied to the coals. The -s-lOg CaO 4-21g CaO presence of calcium oxide during devolatilization signi- bOg Coal (Ca/S=3) (Ca/S6) ficantly increased the yield of C1 to C8 hydrocarbon gases and hydrogen, while slightly reducing the yield of Total Gas (liter) 7.0 6.8 7.0 liquid. Char (wt %) 75.4 74.7 77.3 Tar (wt %) 17.0 16.15 14.6 Another positive attribute of coal pyrolysis with cal- Water (wt %) 2.2 4.0 3.5 cium oxide is the improved quality of the liquids. As Gas Composition (Vol %) shown in Table 2, these improvements include: Hydrogen 11.3 13.27 12.7 • A significant decrease in viscosity Carbon Monoxide 3.6 3.61 3.1 Carbon Dioxide 5.4 0.84 0.1 • A reduction in pour point C1-C8 76.6 81.64 84.0 • A decrease in Conradson carbon residue Hydrogen Sulfide 3.2 0.61 0.0 COS 0.2 0.118 • A small reduction in density 0.0 Methane 49.2 58.8 55.7 • A significant reduction in total oxygen content Tar Characteristics • A significant reduction in the phenolic compounds. Total Sulfur 0.71 0.59 0.51 (wt %) Additionally, tests by other researchers suggest that Total Nitrogen 1.68 1.41 1.61 under mild conditions (approximately 500°C), pyrolysis (wt %) tars contain statistically insignificant mutagenicity Heating Value 16,243 16,349 16,607 properties. In contrast, the highest values of mutageni- (BTU/Lb) cities were found for the tars produced at 800 0C. The H/C Ratio (Atomic) 1.33 1.31 1.27 author believes that because the oxygen content of the Oxygen, By Difference 9.14 7.59 5.49 tar is significantly reduced by addition of calcium (wt %) oxide, the toxicity and mutagenicity of the tars will be Ash (wt %) 0.01 0.01 0.01 further decreased. Char Characteristics (wt %) The data reported in Table 2 were obtained using -8 by 100 mesh coal size fraction. The influence of calcium H/C Ratio (atomic) 0.41 na 0.49 Carbon (daaf) 85.53 na oxide on sulfur capture when applied to smaller coal 86.18 Hydrogen (daaf) 2.90 na 3.53 particles (-100 mesh) is shown in Table 3. The data Nitrogen (daaf) show that adding 21 weight percent calcium oxide to 2.40 na 2.04 Sulfur (daaf) 1.99 na 2.57 -100 mesh coal reduces the hydrogen sulfide yield to Ash/Additive zero, and the sulfur content of the tar is reduced to 10.54 na 29.75 Volatile Matter 14.56 na 18.19 0.51 weight percent from 0.71 weight percent observed Water 0.48 na 0.50 for the untreated coal. Thus, the author suggests that coal fines could be a useful feed to a mild-pyrolysis batch retort. These fines are generally considered Not available waste materials. Dry-ash and additive-free basis Other attributes of the coal liquids produced with calcium oxide added include ash contents below

4-29 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Data in Tables 2 and 3 indicate that char produced in expensive than advanced pyrolysis and liquefaction. the presence of calcium oxide has a greater sulfur Under such a mild reaction condition, the generated content and a slightly larger hydrogen-to-carbon ratio liquid will require little or no upgrading before use for than char produced without the additive. The volatile- some applications as transport fuels. Because coal matter content of the char ranges between 14 and pyrolysis liquids possess higher aromaticities, they may 18 weight percent compared to 36 to 38 weight percent also serve as octane boosters to conventional gasoline. for the raw coals. The researchers found that visual examination of char suggested that the agglomerating The author points out that the objectives of conven- characteristics of the char may be reduced when coal is tional approaches to hydrotreating coal tars (to reduce pyrolyzed in the presence of calcium oxide. tar viscosity and sulfur, oxygen, and polynucicar aromatic contents) are readily achieved when coal is pyrolyzed at mild conditions in the presence of calcium Comparison With Other Conversion oxide. The result is a potentially low-cost liquid fuel. Processes Although the quality of liquid is relatively high, the yield of liquids generated in a mild pyrolysis process is Tars resulting from mild pyrolysis and those from low (15 to 20 weight percent). However, this type of various conversion processes were compared by the process may be economically attractive for low cost author. The hydrogen-to-carbon ratio for the assay tar feeds, such as coal fines. from Pittsburgh No. 8 coal was 1.35, while that of Illinois No. 6 coal was 1.42. Addition of 21 weight percent of calcium oxide reduced these ratios slightly to 1.31 for Pittsburgh No. 8 coal and 1.32 for Illinois No. 6 coal. In general, hydrogen-to-carbon ratios of the assay tars are superior to solvent refined coal (SRC-10 NEW UCO METHOD FOR LARGE BLOCKS (hydrogen-to-carbon ratio approximately 0.84 for Illi- AT GREAT DEPTHS PROPOSED nois No. 6 parent coal); COED process tar (hydrogen-to- carbon ratio about 1.0 for Pittsburgh seam parent coal); At the 12th Underground Coal Gasification symposium or the METC fixed-bed gasifier tars (hydrogen-to-car- held in West Germany in August, P. L. Ledent, former bon ratio approximately 0.9). The hydrogen-to-carbon director of Institution pour Ic Dcvelopement de Is ratio of the mild pyrolysis tar is comparable to the coal Gazeification Souterraine, Belgium presented a new liquid obtained in the Exxon Donor Solvent process approach for UCG at great depths. (hydrogen-to-carbon ratio about 1.4), which requires the Deep coal beds constitute the main part of European addition of hydrogen. energy resources and, during the last ten years, impor- The sulfur content of Illinois No. 6 coal slow pyrolysis tant research programs have been carried out to make tar is 0.54 weight percent, which is comparable to the their recovery possible by underground coal gasifi- sulfur content of the oil from the SRC-II process cation. (0.6 percent) using the same coal. The sulfur contents of the mild pyrolysis tars are lower than those noted for the tars produced in the COED process (1.2 weight Particular Concerns With Deep percent for Pittsburgh No. 8 coal and 2.5 weight per- Coal Bed, cent for Illinois No. 6 coal). The author suggests that the longer residence time allowed in the mild pyrolysis The development of 13CC at great depth must take into conditions (including slow heat-up and a fixed bed) account: facilitates greater contact between the primary products and calcium oxide; thus, a low-sulfur liquid is S The much longer wellbores produced in the Fischer assay. • The increase of the in situ fluids pressure • The increase of the lithostatic pressure Possible Applications of the Concept • The development of coal creeping phenomena. The author believes that the low-temperature pyrolysis Due to the longer welibores required and to the in- of coal-lime mixtures offers several advantages over crease of the rock pressure, the cost of the preparatory advanced processes. Conventional advanced pyrolysis works becomes the main part of the total cost. and liquefaction processes involve complex combinations of unit operations. Normally, such designs are As a result, the development of 13CC at great depths aimed at a single product and attempt to maximize the may only be considered in the form of powerful gas yield of that product. Hydropyrolysis and hydrolique- generators of great extent, linked to the surface by a faction processes add the expense and complexity of small number of wells, with as small a diameter as hydrogen production. possible. A pyrolysis scheme operating at mild conditions in the These conditions imply the use of oxygen and a high presence of calcium oxide and aimed at multiple pro- gasification pressure. A major problem is that the coal ducts can produce a clean liquid transport fuel and an permeability quickly decreases with the increase of the acceptable solid fuel, according to the author. This lithostatic pressure at depth. In the Thulin deposit, at approach is also expected to be simpler and, thus, less 860 meters depth, the coal permeability varies between

4-30 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 0.01 and 0.10 millidarcy. The fissures are too small to Table 1 summarizes calculated results obtained with allow the propagation of combustion reactions. the three gasifying agents. The most significant differences concern the volume of the gasifying media and In most of the European coal fields, the coal crushing the size of the injection pipes. It appears that oxygen + strength fluctuates around a mean value of 120 bar. At water foam would be a very useful gasifying medium. a depth of 500 meters, this value is outstripped by the lithostatic pressure. In these conditions, the coal no longer reacts like an elastic material, but flaws toward the open spaces and forms creeping zones around the TABLE 1 wells and along the working faces. The permeability in such creeping zones may be COMPARISON OF THREE GASIFYING AGENTS 100 times greater than that of the undisturbed coal. Similarly, the reactivity may be 10 to 100 times as Gasifying Agent 02-Steam 02+Water 02+CO2 great. These facts are the basis of the new method. Molar Ratio 0.4+0.6 0.5+0.5 0.50.5 Gasification Temperature, °C 890 900 930 An Unconventional Gasification Medium Gas Analysis (Volume %) The classical oxygen + steam mixture, which has been Hydrogen 33.6 31.8 17.6 successfully used during UCG tests at shallow depth Carbon Monoxide 33.0 36.2 53.3 suffers from numerous inconveniences for UCG de- Carbon Dioxide 12.95 13.4 19.35 Methane 3.55 3.0 0.7 velopment at great depth. Because of heat losses to Water 16.9 15.6 9.05 the formation in the long wellbores, steam cannot be Dry Gas U.H.V., kJ/m 3N 11,883 11,650 10,190 produced by waste heat recovery. As a result, steam would have to be produced by fuel consumption. Materials Consumed Also, keeping the gasifying medium temperature above Oxygen, m S N/KWH gas 0.072 0.087 0.091 the steam condensation point induces a high expense for Carbon Dioxide, - - 0.091 pipelines and injection wells, due to the necessary m 3N/KWH gas increase in diameter and to the use of special steel, Water, kg/KWH gas 0.087 0.070 - expansion joints and insulating coatings. Energy Consumed Possible replacements for oxygen + steam mixtures Electricity, KWH/KWH Gas 0.0432 0.0521 0.0711 include oxygen plus carbon dioxide and oxygen plus Fuel, KWH/KWH Gas 0.0860 - - liquid water. To provide homogeneity of the last Total Primary Energy(1) 0.200 0.137 0.187 mixture, the water has to be premixed with a foaming agent. As an example, Figure 1 shows a foam generator G.A. Mean Temperature, °C 240 27 35 installed at the head of an injection well. G.A. Volume at 50 bar, 6.77 1.98 4.12 1/KWH Gas Pipe Section Ratio(2) 1.00 0.29 0.61 Internal Diameter Ratio(2) 1.00 0.54 0.78 External Diameter Ratio( s) 1.00 0.45 0.65

1. Total primary energy 1/0.38 electrical energy plus thermal energy 2. For the same speed of flow 3. Taking into account a supplement of 20 percent for the insulation of steam pipes

Linking and Controlled Retraction of the Injection Point

In-seam drilling is the only process which can be used to link an injection well and a production well situated at great distance from each other. However, when working at depths, the link obtained by drilling is a precar- ious one, which must be consolidated, as soon as possible, by the insertion of a liner. The best solution to this problem is the use of the controlled retraction injection point (CHIP) technique. The application of the CHIP method makes possible the creation of an in-

4-31 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 seam gallery of great size; after caving of the seam roof, this gallery, filled by rock rubble of high permeability, can be used as a gas collector during the whole duration of the gasification process. The controlled retraction of the gasifying media injection point produces a progressive displacement of the gasification zone, from the production well to the injection well. There remains a channel filled with rock rubble and, on each side of this channel, a coal creeping zone the width of which can reach 3 to 4 times the seam opening.

The Underground Gas Generator At the beginning of research into UCG at great depth, it was hoped to use a stream gasification process in which gasifying media and gas would now in a channel of great length. A number of mathematical models were developed to calculate the gas quality, the productivity, and the efficiency of such a gas generator. The results of these studies were, as a whole, very disappointing. These conclusions were confirmed by the poor performances which were obtained during a number of tests. The recent development of the CRIP method, however, makes possible a gasification process by filtration through the coal rubble, which produces a gas of high quality, with an efficiency comparable to the efficiency of surface gas generators. Figure 2 shows how this process could be used, at great depth, to gasify a panel of great extent. The first step would include the drilling of a production well and the achievement of a linking channel to be used as gas collector. Perpendicularly to this channel, 10 to 12 boreholes would be drilled, in-seam, at 20 to 25 meter intervals. At the present time, directional drilling techniques are not sufficiently reliable and accurate to realize such a network of boreholes starting from the surface. How- ever, this type of gasification could be developed by a between the wells I and II spaced at 35 meters 097 mixed method, starting with mining galleries which ure 3). This experiment apparently gave rise to the would be created below the deposit, as in the upper part creation of an underground gas generator, the effi- of Figure ciency of which was relatively high. Calculations of the gas pressure and of the coal stresses around well II Using a simultaneous retraction of the gasifying media found that four concentric zones may be distinguished: injection points, in all the boreholes, the gasification would progress uniformly over the whole width of the • A rock rubble resulting from the coal combus- panel, taking advantage of the great permeability and tions which had occurred during preceding tests of the high reactivity of the coal creeping zone which • A coal creeping zone of high permeability, develops in front of a working face. resulting from the high level of the vertical and tangential stresses The Reverse Combustion Test • A zone of undisturbed coal, with a very low Of April 1984 permeability, through which the gas flow produced a very big pressure drop The possibility of developing a filtration gasification • A zone of undisturbed coal, the permeability of process, which would require fewer preparatory in-seam which had been considerably increased by the drillings than the above process, appeared from the high pressure of the flowing gas. results of a reverse combustion test, which took place in Thulin, in April 1984. The creeping zone which developed around well H apparently played a determining role in the development The aim of this test was the creation of a linkage, of this experiment. The crushing of the coal by the

4-32 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 rock pressure produced an increase in its reactivity in which the self-ignition of the coal would syste- because of which self-ignition happened around well 11 matically happen in the creeping zones situated in the sooner than around well I. vicinity of the production wells. The self-ignition of the coal around the injection well FIGURE 3 would be prevented by reducing to a minimum the extent of the creeping zone there and by keeping this zone continuously wet, by the use of a gasifying me- REVERSE COMBUSTION TEST dium in foam form. Self-ignition in the vicinity of the THULIN - APRIL 1984 production well would be favored by different means: WELL I WELL! • The development of large creeping zones, the 90%AIR renewal of which would continuously create GAS new surfaces of high reactivity TOt. (02 580-600. 1 1A 720-750m3,/h • The use of a sufficiently high counterpressure _Z70 bar 50 To 7206., in the gasification zone • The control of the advance rate of the gasification front, by regulation of the gasifying medium injection rate, to keep the self-ignition points inside of the creeping zones. Figure 4 shows how a system could be set up for the AN Ofp working of a panel of about 7 hectares. The preparatory works would include two vertical production j wells and three in-seam boreholes, two of which would be situated at the panel limits and the third one in the axis of the panel. The working would be divided in two successive phases. The first phase would include the creation at the border of the panel, of two large channels, by the injection of a gasifying medium at medium pressure (below the in situ pressure) and by the use of the CRIP method. This The existence of a creeping zone surrounded by a ring first operation would also result in the creation, along of virgin coal of very low permeability, playing the role these channels, of two creeping zones of great extent of a gas diffuser, created ideal conditions to propagate which would be used as a starting point for the later self-ignition in the whole creeping zone, which spon- gasification operations. taneously transformed into a filtrating gas generator. The second phase would include the injection, through the central borehole, of a gasifying medium, under high An Unconventional Gasification pressure, conditioned as a foam and which would be Process distributed through calibrated holes, drilled at regular intervals, on the whole length of the liner. Two conditions are required for an industrial application of the results of the Thulin test. The first This second gasification phase would proceed by con- requirement is a big underground gas generator, the tinuous self-ignition of the coal in the creeping zones geometry of which will allow a recovery rate of nearly situated along the two lateral channels, the consump- 100 percent and in which creeping zones of large extent tion of the coal having, as a consequence, to displace will be created. the pressure wave which is developing in front of the working faces and to ensure the advance of the creep- The second requirement is a better knowledge of the ing zone at the same rate as the advance of the coal reactivity at great depth, to be able to use a gasification front. gasifying medium of high oxygen content and, at the same time, to keep control of the self-ignition reac- The application of such a method implies the use of tions. A theoretical analysis shows that the ignition of high injection pressures, but it results only in a rather the coal is not a homogeneous phenomenon which takes small increase of energy consumption, the compression place in the whole coal volume, but that it arises energy of a gas being proportional to the logarithm of locally, in crushed coal areas situated in the vicinity of the pressure. the wells and then propagates in the whole volume of the creeping zone. When this volume of coal is Savings obtained by application of this method result consumed, it is generally possible to observe the self- from the large reduction in the number of in-seam extinction of the fire, as was observed many times boreholes required and the reduction of their diameter, during the Thulin tests. which would not exceed two inches. From these data it was deduced that it would be possible to develop a new filtration gasification process

4-33 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 0*00

4-34 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TIGAS PROCESS CONVERTS COAL TO If the synthesis gas is produced by steam reforming, the GASOLINE IN ONE SYNTHESIS LOOP make-up gas will contain a surplus of hydrogen which must be purged from the gasoine loop. This surplus of The process scheme for the conversion of synthesis gas hydrogen can be avoided by proper process design to gasoline via methanol that was developed by Mobil and/or operation, however. consists of two independent synthesis loops: a methanol loop and a gasoline loop. A further development of this technology is the Topsoe-Integrated-Gasoline-Synthesis Coal-Based Process (TIGAS) process in which the two loops are integrated into one single synthesis loop without isolation of When syngas is produced by coal gasification the basic methanol as an inatermediate. This integration results problem is hydrogen deficiency. This hydrogen defi- in a simple flow scheme and, hence, in savings in ciency is overcome by adding water to the gas and investments and energy consumption. Details of the producing the necessary hydrogen by the shift reaction. TIGAS process were recently explained at the American Traditionally, the gas from the gasifier is shifted out- Institute of Chemical Engineers April 1986 meeting. side the loop to obtain the necessary hydrogen/carbon monoxide ratio. Before entering the loop, the carbon The TIGAS process has been demonstrated since Jan- dioxide produced in the shift reactor and the carbon uary 1984 in a pilot plant with a capacity of 1,000 tons dioxide formed in the gasifier must be removed (see per day of gasoline. The test program, which will Figure 3). terminate in late 1986, is sponsored by the European Communities in a program for liquefaction of coal. In a new process configuration the gas is shifted to the Operating periods up to 21 weeks have been demon- desired stoichiometric hydrogen/carbon monoxide ratio strated without regeneration. In the conventional inside the TIGAS loop by utilizing the methanol catalyst MTG-fixed bed scheme, regeneration is required after 3 as a shift catalyst. As shown in Figure 4, carbon to 4 weeks of operation. Until now, the pilot plant has dioxide is removed somewhere in the loop. According demonstrated a process scheme based on syngas pro- to Haldor Topsoe, one of the advantages of this new duced by steam reforming of natural gas. In the near approach is that by using the existing methanol catalyst future, the TIGAS process will be demonstrated with as shift catalyst, the shift rector normally used in the syngas that simulates the gas from a coal gasifier. front-end can be avoided. Modern coal gasifiers provide syngas with hydrogen-to- The stoichiometry of the gas can differ depending on carbon monoxide ratios less than 1. This low ratio the reactions in the oxygenate reactor. If only offers the advantage of loop integration, because the methanol is produced in the oxygenate reactor synthe- hydrogen/carbon monoxide ratio of the feed gas does sis, the gas must be shifted to a hydrogen/carbon not have to be adjusted for methanol (which requires a monoxide ratio of 2. When using a combined hydrogen/carbon monoxide of 2), but could be adjusted methanol/DME catalyst in the oxygenate system, the to a lower hydrogen/carbon monoxide for production of syngas needs to only be adjusted to a hydrogen/carbon gasoline. monoxide ratio of 1. Thus, the amount of steam necessary to shift the gas is less, resulting in substan- Natural Gas-Based Process tially lower energy consumption.

A simplified flow scheme for the TIGAS process based The type of gasifier that is most suitable for the TIGAS on natural gas as feedstock is shown in Figure 1. process is a high pressure gasifier with a low methane Syngas, produced by steam reforming of natural gas, is content in the produced syngas. Suitable processes are mixed with recycle gas containing unconverted syngas the Texaco, the Winkler, and the Koppers Prenflo and ligher hydrocarbons. This mixture is the feed gas gasifiers. With high pressure gasifiers, syngas compres- for the oxygenate reactor system. sion can be eliminated with consequent investment and energy savings. By using a multi-functional catalyst system which produces other oxygenates such as dimethyl ether (0 ME) as well as methanol, higher conversions of syngas can be Comparison of Coal-Based achieved (Figure 2). Alternatively, the same conversion Process Configurations per pass can be obtained at a lower loop pressure. Table 1 presents five different cases for the conversion The oxygenates, together with unconverted syngas and of coal into gasoline. For all cases, the authors lighter hydrocarbons, are fed directly to the gasoline assumed that the exit gas from the coal gasifier has the reactor. In the gasoline reactor, the oxygenates are dry gas composition shown in Table 2. For all eases, converted into hydrocarbons in the range from Cl to carbon dioxide removal is necessary, and also, the C. Because the reactions are highly exothermic, authors assumed that in all cases the carbon dioxide temperature in the reactor is controlled by proper wash reduced the carbon dioxide content to approxi- selection of recycle for the synthesis loop. mately 2 volume percent. The loop pressure was selected to 35 bars, to achieve 95 percent conversion of The exit gas from the gasoline reactor is cooled, and the carbon monoxide and carbon dioxide, thus eliminat- the gasoline and water are separated. The unconverted ing the need for compression of the syngas. The syngas and lighter hydrocarbons are recycled, and a recycle ratios were adjusted so that the gasoline pro- purge from the loop is taken to keep a fixed inert level. duction in all cases is the same.

4-35 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

FIGURE 2

THERMODYNAMIC POSSIBLE CONVERSION OF CO AND CO2 AT DIFFERENT TEMPERATURES AND PRESSURES

I -- METHANOL ONLY 100 - MIXED OXYGENATES 80 -

60 - FEED GAS COMPOSITION

40 - H2 BO VOL. % co 5 VOL. % 20 - CO2 3 VOL. % - INERTS 12 VOL. Z I I I I I I 0 p

200 220 240 260 280 300 320 340 OC

TEMPERATURE

4-38 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 FIGURE 3 TIGAS PROCESS SCHEME COAL-BASED WITH SHIFT OUTSIDE LOOP CASE B+D

WATER CO2 WATER GAnDC

FIGURE 4 TIGAS PROCESS SCHEME COAL-BASED WITH SHIFT INSIDE LOOP

CASE C + E

WATER GASOLINE

4-37 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE 1 Case A In Case A, the conversion of coal into gasoline is COMPARISON OF COAL-BASED! carried out in two separate steps, the methanol-synthe- GASOLINE PROCESS SCHEMES sis and the gasoline synthesis. The hydrogen/carbon monoxide ratio of the make-up gas must be adjusted to 2. Also, two recycles are needed, one for each synthe- Case A B C D E sis loop.

Loop Pressure, 35 35 35 35 35 The energy consumption of the two recycle compressors bars was estimated by assuming that the pressure drop in the No. of Loops 2 1 1 1 1 two loops is 2.25 bar each, whereas in the integrated Shift Inside/ Out Out In Out In loop the total pressure drop is 4.5 bars. Outside Loop Required H2/CO 2 2 2 2 1 Ratio, mole! Case B mole Gas from Gasi- 1.106 1.106 1. 106 1. 106 1.106 Case B is the simplest form of the TIGAS process based fier (Dry), on coal gas. The syngas from the gasifier is shifted to a m 3/hr hydrogen/carbon monoxide ratio of 2 before entering Gasoline Pro- 3,244 3,244 3,244 3,244 3,244 the loop where the syngas is converted to methanol. duction, MTPD The gas from the oxygenate reactor is fed directly to (based on 75 33 the gasoline reactor without any condensation of raw wt% selee- methanol, and the unconverted syngas is recycled to the tivity to gasoline reactor. Only one recycle loop is needed. gasoline from methanol) Steam Addition, 175 175 175 175 59 Case C 1000 kg/hr Recycle/Make- 25.2 8.4 12.1 5.5 1.8 Case C differs from Case B in that the shift reactor in Up, mole/mole " the make-up gas stream has been removed. Instead the Required Recy- 39.9 63.2 29.9 9.60 shift activity of the methanol catalyst in the oxygenate dc Energy, MW reactor is utilized. Water is added in the form of Water Partial 1.0 0.05 0.02 0.6 0.02 medium pressure steam at the inlet of the oxygenate Pressure at reactor to adjust the hydrogen/carbon monoxide ratio the Inlet of to 2 (i.e., the stoichiometry of methanol). The authors the Gasoline conclude that this configuration is less interesting than Reactor, bars Case B because the higher recycle ratio represents a severe penalty in terms of larger investment and energy Only for methanol loop consumption in the synthesis loop. "Includes recyle energy in MTG-loop. Recycle ratio is 9 moles/moles Case D

Case D utilizes the DME-reactions along with the methanol and shift reactions by using a combined catalyst system. The make-up gas is adjusted to a hydrogen/carbon monoxide ratio of 2 outside the loop. The authors conclude that the advantage of Case I) compared with Case B is that the introduction of the TABLE 2 DME-reaction thermodynamically enables higher conversions of carbon and carbon dioxide and thus allows a lower recycle/make-up gas ratio to obtain the same ASSUMED COAL GASIFIER overall conversion. DRY GAS COMPOSITION (Volume Percent) However, it is not possible in this case to take advantage of the DME-reactions and adjust the hydrogen/carbon monoxide ratio to 1 because the carbon dioxide Hydrogen 35.85 Carbon Monoxide produced in the nethanol/DME reactors would accumu- 50.59 late in the loop. Carbon Dioxide The high carbon dioxide content would 12.29 affect the shift equilibrium and cause hydrogen to be Methane 0.29 Inerts converted to water, which would be condensed in the 0.98 separator. Hydrogen would then be rejected from the loop as water, and the desired gasoline production would not be obtained.

4-38 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Case E test in pilot scale, the combined methanol/UME catalyst showed high stability and more than 99 percent Case E is by far the most interesting case, according to selectivity to oxygenates. the authors. As in Case D, a combined mcthanol/DME catalyst is employed in the oxygenate reactor system. Whereas the gasoline yield is unaffected by the change The gas from the gasifier is not shifted before entering from natural gas to coal, pilot experiments have shown the synthesis loop. Instead, water is added at the inlet that the content of aromatics in the gasoline is signifi- of the methanol/DME reactor and the methanol cat- cantly higher in the coal-based scheme. As summarized alyst is used as shift catalyst to produce the necessary in Table 3, aromatics are 7 weight percent higher in the hydrogen. The carbon dioxide removal step is located coal-based scheme than in the natural gas-based in the loop at the inlet of the methanol/DME reactor. scheme, most likely resulting from the low hydrogen In this case, the hydrogen/carbon monoxide ratio only partial pressure. The higher content of aromatics will has to be adjusted to 1 instead of 2. No problems with increase the research octane number of the gasoline by the carbon dioxide produced in the loop will arise 4, thus producing a more valuable gasoline. because the carbon dioxide is washed out inside the loop. TABLE 3 HYDROCARBON PRODUCTS FROM In Case E, the steam addition to produce the required THE TIGAS PROCESS hydrogen is approximately 3 times lower than the steam (Weight Percent) additions in Cases A, B, C, and D. The water produced by dehydration of methanol to OME is consumed by the shift reaction producing hydrogen and carbon dioxide. Feedstock Natural Gas Coal Only small amounts of methanol and water will be (simulated) present in the reactor effluent, with the main products being DME and carbon dioxide. The absence of substan- Cl 1.90 1.97 tial amounts of methanol and water enables a high C2 4.28 conversion of carbon monoxide and carbon dioxide in 3.25 C3 6.73 7.79 the oxygenate reactor. The authors note that the C4 12.11 benefits of this configuration can be seen from the data 11.91 C5 16.45 12.75 in Table I in which the recycle ratio for Case E is much Ce 18.37 lower than for the other eases. The results of the lower 15.72 C7 14.20 13.46 recycle ratio in Case E are investment savings that C8 13.13 occur from avoiding a shift reactor and substantial 13.05 C9 7.64 10.00 energy savings because the necessary steam addition is C10 4.85 lower. 9.20 C11 0.34 0.90 If the recycle ratio in Case E was allowed to increase C5' 74.98 75.08 to 5, the synthesis loop pressure could be decreased to Aromatics 18.30 24.90 22 bar, thereby allowing the operating pressure of the coal gasifier to be decreased to the same level. The lower pressure could result in lower investment costs. Future Work

Process Parameters In the near future, the process scheme outlined in Case E will be tested in the gasoline pilot plant to estimate catalyst lifetimes. In the natural gas-based TIGAS process, the use of a combined methanol/DME catalyst will result in the A more advanced process scheme, which is being ex- presence of substantial amounts of water in the reac- plored at pilot scale, is the one stage conversion of tor. Water produced by dehydration of methanol to syngas to gasoline. In principle, the hydrogen/carbon DME will not be consumed by the shift reaction because monoxide ratio then needs only to be adjusted to 0.5. the equilibrated gas has a high content of water and Water could be added to the reactor inlet to obtain this hydrogen. Because water is adsorbed on the active hydrogen/carbon monoxide ratio if necessary. With this catalyst sites, the presence of water in the concept water is not a product because oxygen is only methanol/DME reactor increases the required catalyst volume. converted to carbon dioxide. Secondly, the conversion of syngas is not limited by thermodynamics because as soon as methanol is formed it will be converted to However, in the coal-based TIGAS process, the water gasoline. formed by dehydration of methanol is immediately consumed by the shift reaction, leaving virtually no Conclusion water in the reactor. The absence of the inhibiting water results in higher reaction rates and, hence, signi- The authors conclude that loop integration as demon- ficantly lower catalyst volumes. Also, the relatively strated in the TIGAS process represents a simplification low water partial pressures in the coal-based scheme of the conversion of syngas into gasoline. With coal as increase the catalyst life of the DME catalyst. the feedstock the lower hydrogen/carbon monoxide ratios result in lower investments as well as lower energy consumption. However, more development work Pilot tests have shown promising results on a is needed before final commercialization of the coal- methanol/DME catalyst system. In a 1,500 hours aging based TIGAS process.

4-39 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 INTERNATIONAL

PYROSOL PROCESS OFFERS ATTRACTIVE thus generating considerably less Cl to C4 gas respec- TWO-STAGE LIQUEFACTION OPTIONS tive to hydrogen consumption. Furthermore, the pressure can be reduced from 300 bars to 200 bars for 0(1< Gesellsehaft fur Kohieverflussigung mbH, a German hard coal. 100 percent subsidiary of Saarbergwerke AG, has been The other 50 percent of the oil is produced by coking engaged in coal liquefaction tests since 1974. A the residue from the first stage. There is almost no 6 tonnes per thy pilot plant was installed in 1981 at hydrogen consumption during coking, but GfI< has found Voelklingen-Fuerstenhausen in West Germany. The unit that the presence of hydrogen improves the quality and is capable of operating at pressures up to 300 bars. quantity of the coker oils. Approximately 50 percent of Initially, the plant was configured to utilize the single- the undistillable bitumen formed during mild hydrogen- stage 10 Farben technology. In 1984 GfK conceived a ation in the first stage can be converted to distillates in unique two-stage liquefaction technology called the the coking section. The residual coke has a low PYROSOL process. hydrogen content. Although the PYROSOL process yields as much oil as the single stage processes do, the The PYROSOL process was devised because 0(1< con- pressure and hydrogen consumption are considerably cluded that coal liquefaction is uneconomic because: lower. The data in Table 1 indicate that with the PYROSOL process the hydrogen consumption is only • The hydrogen consumption is still much too high one-half of that in a single stage operation. • The operating pressures are too high, which results in high capital and operating cost. TABLE 1 In a single stage process the entire oil yield is produced in one stage, which makes it difficult to adjust operating conditions. Also, a large amount of gaseous hydro- HYDROGEN BALANCE OF THE PYROSOL PROCESS carbons (up to 25 percent of thf coal) are formed, (Weight Percent of 'Ensdorf' Coal thf) leading to a considerable increase in the consumption of hydrogen. Another portion of the reacted hydrogen goes into hydrogenation of the residue that is with- Hydrogen drawn from the vacuum distillation tower. Compared Cancan- to the input coal, the hydrogenated vacuum residue Mild Hydrogenation Yield tration Content contains more hydrogen. Finally, the recovery of oil is (First Stage) limited because the vacuum distillation tower operation must be adjusted to maintain good fluidity of the Cj-C4 6.9 18.0 1.24 bottoms product. C5-200°C 5.0 11.4 0.57 200°-380°C 20.0 9.1 1.82 Due to these limitations, 0(1< has been developing a Extract (SRC) 54.8 6.25 3.42 new two-stage process to convert coal into oil which Unconverted Coal 8.0 4.0 0.32 comparatively consumes much less hydrogen and oper- H2O, COx, NH3, H25 8.0 10.36 0.83 ates at considerably lower pressures. In contrast to the Total 102.7 8.20 IG Farben process, the PYROSOL process only partly (5.47)• liquefies the coal in the first stage using mild hydrogenation conditions. Approximately 25 percent of the daf 2.73 coal is converted into distillates. The remaining residue, which contains a high amount of bitumen, is then Hydrocoking coked in the second stage. In the hydrocoker the (Second Stage) residue is cracked into additional oil and coke under a hydrogen atmosphere. In: Extract (SRC) 54.8 6.25 3.42 The PYROSOL process can be configured for direct Unconverted Coal 8.0 4.0 0.32 coal liquefaction or for coprocessing coal and oil. De- Total 62.8 3.74 tails of the coprocessing scheme were described on page 4-49 of the December 1985 Pace Synthetic Fuels Out: Report The coal-only scheme was described by Oil 30.0 9.1 2.73 Dr. H. E. Warfel at the Coal Science Conference in Coke 29.8 2.9 0.865 Sydney, Australia. Gases +H20 3.0 17.3 0.519 As illustrated in Figure 1, approximately 25 percent of Total 62.8 4.114 the coal is converted to distillates at moderate conditions. With increased hydrogen consumption the forma- Total H2 Consumption 2.730 tion of distillate oils is steadily decreasing whereas the 0.374 formation of the gaseous hydrocarbons (C1 to C4) is %of Coal daf 3.104 increasing. Because only one-half the oil usually generated in a single stage is produced in the first stage of 112 originally in the coal the PYROSOL process, the severity can be reduced, **Net H2 consumption

4-40 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 A simplified flow diagram of the PYROSOL process is FIGURE I given in Figure 2. As shown, the PYROSOL process can PYROSOL COAL LIQUEFACTION also utilize the concept of directly preheating the coal PRODUCT DISTRIBUTION slurry by use of the coke drum overhead vapors and those of the hot separator of the liquefaction section. I® - - CI- (This concept was more fully described in the December 1985 article.) Present activities are directed at install- OAF COAL 1-fYOROGERATtON ing a hydropyrolizer in the liquefaction unit. Data that OIL can be used to plan a large demonstration plant are expected to be available by the end of 1989.

OIL

COKE ------] 20 UCONV. COAL O 7 I 2s 'CAI44flT HYOftOOtPI CONSUNPTION

4-41 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 TABLE I KOHLEOL PROCESS MAY FAVOR HIGH OPERATING PRESSURE KOHLEOL TEST RUN CONDITIONS Bergbau-Forschung GmbH of West Germany is developing the KOHLEOL process, a direct coal liquefaction process. In the process, oil yields have been observed Reactor Temperature, °C 465-475 to be dependent on coal rank (measured as vitrinite Total Pressure (Standard), bar reflectance). Also, pyrite found in coal is often a good 300 Red Mud as Fe203 (On Coal), % 1.2 catalyst for liquefaction. However, German bituminous Reactor Volume, liter 11 coals are low in both reactivity and pyrite. Therefore, Slurry Feed Rate, kg/hr 14.5 the researchers tested whether increased hydrogen Slurry Oil:Coal Ratio, kg/kg 1.4 pressure could compenstate for the disadvantages of the coal. These tests were recently described at the Coal Science Conference in Sydney, Australia. The results were obtained from test runs lasting several days each under steady state conditions in a 150 kilograms per day process development unit. The PDU was operated at conditions typical of the KOHLEOL process In the test runs, the reactor temperatures ranged from (Table 1). Essential features of this process are: 465°C with the lowest rank coal to 475°C with the high rank coals. Recycle gas flows were maintained con- • Distillate recycle oil is used only for slurry stant in terms of "effective" volume flow, but lower preparation (i.e., no recycling of any asphal- flow settings were used in the red mud experiments tenes) versus the pyrite and the pressure variation experiments. • Once-through catalyst is used (red mud preferred) Conversion of subbituminous coal and of lignite ex- • A simple tube reactor was run at relatively high ceeded 99 percent at standard conditions. For higher temperatures and pressures rank coals, conversions exceeded 90 percent. However. the researchers observed that high conversion does not • The product oil has a relatively low final boiling necessarily correlate to high distillate oil yield, which point (C 3500C). is the main objective of the KOHLEOL process. Al- though hydrocarbon gas formation was roughly the same • general flowsheet of the process is given in Figure 1. for all coals, water and carbon oxides yields differed. • partial oxidation unit (denoted with broken lines) was The researchers found that coals very rich in oxygen not included in the PDU. gave low yields in spite of being highly convertible, whereas low-oxygen coals were generally low in reactivity, with more organic insolubles and more preasphal- tenes and asphaltenes. Sulfur contents of the coals tested varied from 0.3 to 3.0 percent. When low-sulfur coals (C 1 percent) were processed, some elemental sulfur was added to the slurry to promote the catalytic activity of red mud. However, the researchers found that once enough sulfur is available to convert the iron oxides into pyrrhotines, excess sulfur amounts do not further improve oil yield but merely consume hydrogen (Table 2).

TABLE 2

EFFECT OF SULFUR ADDITION TO A LOW SULFUR COAL

% on d.a.f. Coal Sulfur Added - 1.0 2.0 Red Mud Fe2O3 1.3 1.3 1.3 Net Oil Yield 42 51 50

4-42 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 To determine the catalytic activity of pyrite relative to red mud activity, a series of runs was conducted using FIGURE 2 an Illinois No. 6 coal sample with 10.1 percent ash content and 2.7 percent sulfur. Under 300 bar pressure, EFFECT OF HYDROGEN overall oil formation with no red mud added was found to be remarkably high. However, with the addition of PRESSURE ON OIL YIELDS comparably little red mud, oil yield increased more FROM TWO DIFFERENT COALS than expected from earlier investigations. Under 0/ 200 bar, the difference in oil formation was more to ISO 25 3 2 bar obvious-38 percent oil formation was enhanced to a, dat cm,! rbS Pressure 49 percent by red mud addition. These results are summarized in Table 3. TABLE 3

EFFECT OF RED MUD ADDITION TO A HIGH PYRITE COAL on d.a.f. Coal) RmJ ass'i. Pressure (bar) .!.tflna,,PtirR,jQ.9OZ 300 200 300 400 bar Coal Minerals 11.8 11.8 11.8 11.8 Nydmgen Porno! Pressure Pyrite, as Fe203 2.3 2.3 2.3 2.3 Red Mud Added - 4.0 - 4.0 Red Mud, as Fe203 - 1.2 - 1.2 The results depicted in Figure 2 indicate that the highly reactive Illinois No. 6 could be hydroliquefied under at Total Inorganics 11.8 15.8 11.8 15.8 least 250 bar hydrogen (300 bar total) pressure. The lesser reactive German coal requires another 100 bar to Overall Oil Formation 50.0 56.8 36.3 48.7 yield as much oil. By extrapolation, the researchers Difference 6.8 12.4 estimate that oil formation from either of these coals Net Oil Yield 43.3 46.9 29.7 42.8 could reach 60 to 65 percent on d.a.f. coal under hydrogen pressure as high as 400 to 500 bar. According Unreacted Coal 5.6 4.3 10.3 6.5 to the curves, the net oil yields would not exceed Asphaltenes Plus 13.3 9.1 24.6 16.0 55 percent. However, heavy distillate oil could be Pre-Asphaltenes recovered with little additional effort. Considering these results, the researchers believe that although the process pressures have been drastically reduced during the last 40 years perhaps the pressure has been reduced too much. The Wandoan coal (Australia) used for the sulfur addition tests (Table 2) contained only 0.2 percent pyrite but about 10 percent ash. The red mud alone was found to be as active as when it is applied jointly with the pyrite in the coal. DOE AND JAPAN SIGN COAL RESEARCH AGREEMENT From these results the researchers conclude: The governments of Japan and the United States signed • Red mud is superior to pyrite as a catalyst an Agreement on Cooperation in Research and Develop- • The catalytic activity of pyrite is increased at ment in Energy and Related Fields on May 2, 1979. higher pressure. Article IV of the Agreement provides that implementing arrangements specifying the details and procedures In other tests, pressure was varied for two coals of of cooperative activities will be made between the two different rank: Illinois No. 6 and German Ruhr. The governments. Therefore, on May 9, 1986 the Agency of effect of hydrogen partial pressure was found to be Industrial Science and Technology (AIST) of Japan and very significant, with about the same effect for both the United States Department of Energy (DOE) estab- coals. Under 100 bar hydrogen pressure, the coal lished such an implementing arrangement for coopera- conversions were 89 and 85 percent. Under 500 bar, the tion in the field of coal energy research and develop- lower rank coal converted completely, while conversion ment. of the other coal will apparently not exceed 96 to 97 percent at any pressure. Pre-asphaltenes and The areas for cooperation in coal energy R&D covered asphaltenes respond to hydrogen pressure in a similar by the Arrangement may include: way; but the pre-asphaltenes were found to be far more reactive than the asphaltenes. • Coal liquefaction technology

4-43 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 • Coal gasification technology The Arrangement will continue in force as long as the 1979 Agreement on Cooperation in Research and Devel- • Materials and components for coal conversion opment in Energy and Related Fields remains in force. and utilization The Arrangement may be terminated at any time on • Pollution control technology related to coal one year's advance notification in writing. conversion and utilization • Additional areas for cooperation in the field of coal energy R&D, such as magnetohydrodyna- mic technology • Other areas as may be mutually agreed by AIST JOINT RESEARCH AGREEMENT SIGNED BY and DOE in writing. BRITISH GAS AND OSAKA GAS COMPANY

Cooperation under this Arrangement may include, but is A joint research agreement was signed on June 2, 1986 not limited to, the following forms: by the British Gas Corporation and the Osaka Gas Company Ltd. of Japan. British Gas and Osaka Gas will • Exchange of scientific and technical informa- carry out a joint program to develop a process to make tion substitute natural gas (SNG) by a coal hydrogenation • Exchange of information on policies, program route. Initially a three year program of experimental plans, practices, regulations and statutes con- work will be undertaken at a total cost of over 9 million cerning the development and utilization of coal British pounds sterling. energy technologies In most SNG processes, methane is made directly by • Holding of seminars, workshops, and other reacting coal with hydrogen at high temperatures and meetings pressures. The aim of the joint work is to develop a • Short-term visits by scientists, engineers, and new entrained flow reactor operating at short residence other experts to the facilities of AIST and DOE times that may co-produce valuable aromatic liquids. According to British Gas, initial studies have shown • Exchange or loan of equipment, instruments, that such a coal hydrogenation system should offer and materials for testing lower SNG costs than other routes and be more flexible • Exchange of scientists, engineers, and other in the types and size range of coals it can handle. experts for participation in research, development, analysis, design, planning, and experi- The program includes the use of laboratory test equip- mental activities conducted by AIST and DOE ment in both England and Japan to obtain experimental data for various coal types under a wide range of • The use by one party of the facilities owned and hydrogenator operating conditions. British Gas is build- operated by the other ing a new pilot plant (coal throughput of 0.1 tonne per • Cooperative projects hour) and associated physical modelling facilities to demonstrate the new reactor design at a realistic scale. • Other forms of cooperative activities. British Gas and Osaka Gas have previously worked together to successfully develop a process to make SNG To supervise the execution of the Arrangement a Joint by the hydrogenation of heavy oils. The program was AIST/DOE Coordinating Committee in coal R&D will be completed in 1983 and, although technically met its established. The Joint Coordinating Committee will objectives, it has not been pursued further because the consist of up to three representatives from each Party. economics for SNG production in the long term favor At its meetings, the Joint Coordinating Committee will the use of coal as the primary feedstock. evaluate the status of cooperation under the Arrange- ment and, if necessary, consider measures to correct any imbalance.

AIST and DOE will support wide dissemination of infor- ERECTION OF GASIFIER IN POLAND mation exchanged under the Arrangement (subject to TO BEGIN IN 1981 the need to protect proprietary information). With respect to the exchange of staff under the Arrange- Erection of a coal gasification project in Poland is to ment, each party will be responsible for the salaries, resume in 1987. The plant is to be built by Krupp insurance, and allowances to be paid to its staff. In the Koppers at Libiaz in southern Poland. Equipment for event equipment, instruments, materials, or necessary the plant has been stored at Libiaz for several years. spare parts are to be exchanged, loaned, or supplied by The project, which began in 1980, has been stalled due one party to the other, the equipment, etc. supplied by to "political difficulties" in Poland. the sending party will remain its property and will be returned on completion of the mutually agreed upon The Libiaz project will reportedly use approximately activity. Unless otherwise agreed in writing, all costs 1 million metric tons per year of high sulfur coal. resulting from cooperation under the Arrangement will Synthesis gas produced by the Koppers Totzek techno- be borne by the party that incurs them. logy will be utilized to produce methanol.

4-44 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 ENVIRONMENT

EXPERIMENTAL STUDIES ON TOXICITY OF Conclusions COAL LIQUIDS AND PETROLEUM PRODUCTS COMPLETED The scientists concluded that the carcinogenic potential of a raw H-coal blend mostly can be abolished by An experimental study has recently been completed hydrotreatment due to the reduction in tumoriens that determines whether prolonged skin contact with however, some carcinogenic potential remains with a coal-derived liquids will produce signs of toxicity not devolatilized version of a severely hydrotreated sample. only on the skin, but in internal organs. The research Petroleum-derived products have considerably less car- was sponsored by the United States Department of cinogenic activity, an observation compatible with earl- Energy (DOE) and conducted by the Oak Ridge National ier findings. Finally, the researchers did not find gross Laboratory, Tennessee. The study mimicked human signs of toxicity in organs other than the skin, and the response in a life-long skin painting study with mice. compounds treated seemed not to act as systemic carcinogens.

Materials and Methods TABLE I The scientists tested the following materials: a raw SKIN TUMOR INCIDENCE H-coal blend, a low-hydrotreated and a high-hydrotreated H-coal blend, a "home heating oil," and an H-coal reformed naphtha. Petroleum-derived samples No. of included a No. 2 fuel oil and a cracked naphtha. The Animals W test agents were applied three times per week in Skin Tumors/ various dosages on the shaved skin of the backs of the Number Median animals. Twenty-five animals of each sex were used Dose Per' of Animals Time to per dose level. A complete necropsy was performed by Compound Application Exposed Tumor the researchers on all skin lesions and on all animals (Days)Z killed or found dead. 931 Raw H-Coal 50 41/50 45 Blend 25 45/50 52 Results and Discussion 12.5 44/50 62 934 Low Hydro- SQ 7/50 112 Data on overall tumor incidence are shown in Table 1 treated 25 6/50 117 and can be summarized as follows: among the coal (2650 ppm N) 12.5 1/50 149 liquids only the raw H-coal blend produced an almost 935 High Hydro- 50 10/50 100 100 percent Incidence of skin tumors at all three dosage treated 25 17/50 111 levels. Hydrotreating dramatically reduced the carcin- (0.2 ppm N) 12.5 8/50 119 ogenic potential. The low hydrotreated preparation 978 H-Coal "Home 50 14/50 97 resulted in a tumor incidence of only 14 percent, while Heating Oil" 25 12/50 108 the high hydrotreated preparation produced a tumor 12.5 8/50 112 incidence between 16 percent and 44 percent in all 936 H-Coal Re- 50 0/50 - three dose groups. The scientists found only two formed Naphtha 25 0/50 - tumors out of 150 in those animals exposed to H-coal 12.5 2/50 155 reformed naphtha but exposure to "home heating oil" 975 API No. 2 50 5/50 120 resulted in a 30 percent final tumor incidence. The two Fuel Oil 25 6/50 131 petroleum-derived samples had practically no carcino- 12.5 2/50 144 genic potential; only 3 animals with tumors overall 976 API Gasoline 50 3/50 125 were found in animals painted with gasoline and only a 25 4/50 130 total of 13 animals had tumors 95 weeks after beginning 12.5 6/50 143 of the experiment. Benzo(a)Pyrene 3 0.1 25/25 21 0.05 25/25 24 In a second part of the study the scientists sought to 0.025 25/25 31 determine the chemical characteristics that contributed to the variations in tumorigenicity. They found that hydrogenation reduced a number of tumorigens in 1. High dose was SO,al of undiluted material; 50jal the H-coal blend, including the PAR dermal tumori- lower doses obtained by dilution with acetone; gens, quinoline, and the ether-soluble fraction, all all doses applied 3 times weekly determinant mutagens in crude coal liquids. Further 2. Animals killed 2 weeks after appearance of skin refining into petroleum products reduced these tumori- tumors; all tumors confirmed by histological gens to nearly nothing. diagnosis 3. Doses are in percent (w/v) benzo(a)pyrene, 501al per mouse

4-45 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RESOURCE

CHARTER PROPOSED FOR FORT UNION • Inform the public of decisions and issues before REGIONAL COAL TEAM the RCT. After a 2 year suspension of regional coal lease lales, on February 26, 1986 the Department of the Interior When operating in the leasing on application mode: announced a framework for resumption of federal coal lease sales. (See page 4-41 of the March 1986 Pace • Review all leasing applications, PRLA actions, Synthetic Fuels Report.) As part of the program, and exchange proposals, and make recom- regional coal teams must be re-established to guide mendations on any that appear to have signifi- federal coal leasing activities in each federal coal cant regional implication region. The teams are also intended to act as a forum • Solicit and consider, to the maximum extent for balancing regional and national interests, On possible, the views of the public at each deci- August 1, 1986 Interior distributed a draft charter for sion point the Fort Union Regional Coal Team (ReT). • Provide advice to the Federal-State Coal Advi- The draft charter is patterned after the national sory Board charter for the Federal-State Coal Advisory Board. • Guide the preparation of EISs on coal leasing The draft describes the Coal Team's requirements con- actions that appear to have significant regional cerning competitive coal leasing, Preference Right implications. Lease Applications (PRLAs), public participation, etc. • Consider comprehensive land use plans to be The Fort Union Regional Coal Team will report to the used for coal activities Secretary of the Interior through the Director of the • On an annual basis, review market assessments Bureau of Land Management (BLM). The RCT's recom- prepared by the Bureau and requested by the mendations must be accepted, except in cases of over- RCT and recommend whether the region should riding national interest or in the case that the advice of return to a regional activity planning mode. a state governor is accepted. The RCT will have the flexiblity to recommend to the BLM Director its desire Membership of the Fort Union team includes as voting to operate in either a regional activity planning mode members the team chairperson who will be the Bureau or leasing on application mode. When operating in a of Land Management State Director for Montana, the regional activity planning mode, the RCT will: governors of Montana and North Dakota (or their designated representatives), the Bureau of Land Man- • Transmit to the Secretary alternative leasing agement's Dickinson District Manager, and the Deputy levels and a proposed action leasing level State Director for Mineral Resources for BLM's Mon- • Guide tract delineation and preparation of site- tana State Office. The team will also have a non- specific analyses of delineated tracts voting member who will be a Washington Office official appointed by the Secretary. The chairperson may also • Rank delineated tracts, select tracts, and request assistance from appropriate representatives of identify all alternative tract combinations to be affected federal, state, and local agencies. analyzed in the regional lease sale Environ- mental Impact Statement (EIS) The team will terminate 2 years from the date the • Guide the preparation of the regional lease sale charter is filed uness it is renewed by the Secretary of EIS the Interior. • Utilize market assessments to recommend a regional coal lease sale schedule • Conduct a post-sale reassessment of the need for additional sates • Recommend a lease sale schedule for re-offer- ALABAMA SUB-REGION MAY BE DECERTIFIED ing tracts that were not sold in earlier lease AS FEDERAL COAL LEASING AREA sales On September 4, 1986 the Bureau of Land Management • Solicit and consider the views of the public (BLM) announced that it was considering a proposal to • Consider comprehensive land use plans to be decertify the Alabama Sub-Region of the Southern used for regional coal activity planning Appalachian Federal Coal Production Region. Public comment is being requested on the proposal on or • Advise the Secretary of tracts lacking adequate before October 6, 1986. information • Serve as the forum for Department-State con- BLM established the Alabama Sub-Region for the man- sultation agement of federal coal in Fayette, Tuscaloosa, and Walker Counties and the western portion of Jefferson • Provide advice to the Federal-State Coal Advi- County. On March 10, 1982 the BLM announced the sory Board deletion of Jeffereson County from the sub-region.

4-46 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Three separate coal sates were held over a 15 month period which resulted in the teasing of 13 separate tracts and about 39 million tons of federal coal. (The sales were held in June 1981, December 1981, and September 1982.) Although a second round effort was commenced in September 1982 a decision on a second round lease sale was suspended in early 1984 pending a review of the federal coal leasing program. During 1982, the Alabama coal industry was rapidly expanding to meet the anticipated demands for coal. However, currently, only one company has shown interest in leasing federal coal in the Alabama Sub-Region. In light of the soft market conditions, the Governor of Alabama proposed that the BLM Eastern States Director convert the region to lease by application procedures. If the decision is implemented, the federal coal reserves in the Alabama Sub-Region will be open to lease by application. Under this system a party interested in leasing federal coal in Alabama would submit an application to the BLM. The District Manager would prepare an environmental assessment for the lands that are proposed for lease. The governor will be given 30 to 60 days to review the document and provide comments; the public will be able to review and provide comment during the process; and there will be a public hearing before any leasing decision.

4.47 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 SOCIOECONOMIC

DOE ASSISTS IN MEETING SOCIAL IMPACTS In announcing the impact assistance, Herrington cited OF GREAT PLAINS PLANT North Dakota's cooperation a year ago when DOE was forced to take over plant operations. In making his On August 15, 1986 Department of Energy Secretary announcement Herrington said, "Last August, as we John S. Herrington pledged that federal funds of began working to return financial stability to the pro- $100,000 per month would be provided to the local ject, the State of North Dakota played an integral and governments and school districts of Mercer County, cooperative role. This cooperation has continued even North Dakota. These funds are intended to assist the as the state faced the loss of tax revenues that would governments meet demands caused by the Great Plains have accrued had the plant remained under private Coal Gasification Plant. The community impact assist- ownership. Now that we have legal title to the facility ance will continue for as long as the government is the and the project is on better financial footing, we owner of the facility. The initial assistance package believe it is our obligation to assist neighboring munici- began in August and will include a retroactive payment palities in meeting the local demands imposed by the of $100,000 for the month that elapsed since a United presence of the plant." States District Court transferred legal title to the facility to the Department of Energy (DOE). (Refer to the article in the Government portion of the Coal In July, the United States District Court in North section in this issue of the Pace Synthetic Fuels Re- Dakota transferred legal ownership of the project to DOE as the final step in a court-ordered foreclosure process. DOE has pledged that plant operations will Funds for the community assistance will come from a continue as long as no additional taxpayer funds are DOE reserve fund established in 1980 to cover a pos- expended. sible default on federal loans by the plant's original private sponsors. DOE used most of the fund to help repay the plant's debt when the sponsors withdrew from the project on August 1, 1985 due to financial problems caused by the drop in energy prices. Approximately $23.8 million now remains in the fund. The Great Plains plant employs nearly 1,000 workers and contractors. The large influx of employees during construction and operation of the plant required many local communities to expand their school systems, increase fire and police protection, and add other community services. To assist in meeting the demands, the state imposed a "coal conversion tax" on the private owners of the facility. Approximately 35 percent of the tax revenues were to have been returned to Mercer County municipalities to help mitigate economic and social impacts. However, on August 29, 1985, North Dakota's Attorney General ruled that the state could not collect the coal conversion tax while the federal government was operating the facility. The attorney general's ruling was based on the "Supremacy Clause" of the United States Constitution which prohibits a state from imposing a tax on the federal government without special legislation. Under the Federal Non-Nuclear Energy R&D Act of 1974, however, the Secretary of Energy has the authority to make direct community assistance payments in the event the govenment takes over operation of the project.

4-48 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 RECENT COAL PUBLICATIONS/PATENTS

The following papers were presented at the American Chemical Society meeting held in Anaheim, California on September 7, 1986: D. S. Jordan, "Secondary Reactions of Low Molecular Weight Olefins During Fischer-Tropsch Synthesis" J. A. Williams, "Chemical Trapping of CO/112 Surface Species" R. C. Silver, "Isosynthesis Mechanisms Over Zirconium Dioxide" M. A. McDonald, "Effects of H20 and CO2 on the Activity and Composition of Iron Fischer-Tropsch Catalysts" R. B. Gatte, "The Influence of Particle Size and Structure on the Mossauer Spectra of Iron Carbides Formed During Fischer-Tropsch Synthesis" D. K. Ludlow, "Nickel Crystallite Thermometry During Methanation" M. D. Curtis, "Methanation and HUB Catalysts Based on Sulfided, Bimetallic Clusters" E. B. Zuckerman, "ZSM-5 Supported Iron and Ru from Fe3(CO)12: Structure-Activity Correlations for Synthesis Gas Conversion" J. A. Broussard, "Catalytic Conversion of Syn Gas with Perovskites" W. E. Carroll, "Fishcer-Tropsch Slurry Catalysts for Selective Transportation Fuel Production" B. L. Gustafson, "Selective Production of Alpha Olefins from Synthesis Gas Over mo Supported Pd-Fe Bimetallics" D. T. Wickham, "The Catalytic Decomposition of Methanol into Syngas for Use as an Automotive Fuel" A. Skov, "Testing of a Sulfur Tolerant Direct Methanation Process" K. J. Carrazza, "Steam Gasification of Carbonaceous Solids Catalyzed by a Mixture of Potassium and Nickel Oxides Below 1,000K" R. E. Sears, "Catalyzed Steam Gasification of Low-Rank Coals to Produce Hydrogen" G. L. Anderson, "Coal Gasification with Internal Recirculation Catalysts" E. M. Suuberg, "Oxygen Chemisorption as a Tool for Characterizing "Young" Chars" S. F. Ross, "In-Mine Variation and Its Effect on Coal Gasification" P. R. Solomon, "Coal Pyrolysis in a High Pressure Entrained Flow Reactor" L. A. Bissett, "Response Surface Model Predictions for the Flash Pyrolysis of Montana Rosebud Coal" M. S. Sundaram, "Flash Pyrolysis of New Mexico Subbituminous Coal in Helium-Methane Gas Mixtures" J. Weldon, "Advanced Coal Gasification and Desulfurization with Calcium Based Sorbents" C. Chen, "Mountain Fuel Resources 30 Tons Per Day Entrained Flow Coal Gasification Process Development Unit" E. C. Moroni, "Low-Severity Coal Liquefaction a Challenge to Coal Structure Dependency" Martin L. Corbaty, "A Critical Temperature Window for Coal Hydropyrolysis" J. Shabtai, "Low-Temperature Coal Depolymerization. 5. Conversion of New Mexico and Utah HVB Coals to Hydrocarbon Oils" K. C. Kwon, "Thermal Effects on Liquefaction of Kentucky No. 9 Coal with NIMO/AI 203 Catalyst" R. P. Skowronski, "Moderate Temperature Coal Hydrogenation" M. Kaufman, "Coal Processing in Non-Dissolving Media" B.S. Olson, "Extraction of Low-Rank Coals with Supercritical Water" M. A. Mikita, "Reactions of Coal and Coal Model Compounds with Supercritical Water" E. S. Olson, "Reactions of Low-Rank Coals in Supercritical Methanol" C. R. Porter, "The Chemical Process for Low Temperature Conversion" M. S. Sundaras, "The Direct Use of Natural Gas in Coal Liquefaction"

4-49 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 S. Huang, "Reaction of a Bituminous Coal with the Potassium-Crown Ether Reagent" R. B. Winans, "Mild Oxidative Solubilization of Coal Macerals" P. G. Stansberry, "The Structure and Plastic Properties of Coals Following Low-temperature Catalytic Hydrogenation" D. M. Bodily, "Distribution of Impregnated Metal Halide Catalysts in Coal Grains" B. C. Boekrath, "A Pseudokinetic Study of Coal Liquefaction" J. Nowak, "An Electron Spin Resonance Investigation of Free Radicals in Lignite Formed Using Programmed Temperatures, H2S, CO, and 1-12" J. A. Ruether, "Structural Features of Products Derived from Water-Assisted Liquefaction of Bituminous Coals" C. W. Curtis, "The Roles and Importance of Hydrogen Donation and Catalysis in Coprocessing" J. B. McLean, "Reactivity Screening of Feedstocks for Catalytic Coal/Oil Co-Processing" J. G. Gatsis, "Single-Stage Slurry Catalyzed Co-Processing" P. M. Rahimi, "Coprocessing Using 112S as a Promoter" B. lgnasiak, "Two-Stage Coprocessing of Subbituminous Coals and Bitumen or Heavy Oil" M. L. Greene, "Coal Liquefaction/Resid Hydrocracking Via Two-Stage Integrated Co-Procesing" G. W. Pukanic, "Simulation of a Coal/Petroleum Resid Coprocessing Pilot Plant Scheme" D. A. Huber, "An Assessment of the Potential for Coal/Residual Oil Co-Processing" C. W. Wright, "Chemical and Toxicologic Characterization of Co-Processing and Two-Stage Direct Coal Liquefaction Materials" C. W. Lamb, "Process Development Studies of Two-Stage Liquefaction at Wilsonville" F. V. Stohl, "The Impact of the Chemical Constituents of Hydrotreater Feed on Catalyst Activity" R. A. Winschel, "Improvement in Coal Liquefaction Solvent Quality by Dewaxing" J. B. McLean, "Performance of the Low Temperature First Stage of IlRPs Catalytic Two-Stage Coal Liquefaction Process" R. F. Sullivan, "Transportation Fuels from Two-Stage Liquefaction Products" B. C. Moroni, "Integrated Two-Stage Liquefaction: The Legacy and the Unfinished Work" D. Gray, "Comparative Economics of Two-Stage Liquefaction Processes" F. J. Derbyshire, "Temperature Staged Catalytic Coal Liquefaction" H. P. Stephens, "Two-Stage Liquefaction Without Gas-Phase Hydrogen" P. R. Biekowski, "Enhanced Coal Liquefaction with Steam Pretreatment" B. R. Utz, "The Effect of Reaction Conditions on Solvent Loss During Coal Liquefaction"

Baxter, David .3., "The Corrosion Behavior of Coated 2.25Cr-1 Me and Carbon Steels in a Simulated High ps2 Waste Heat Recovery System Environment of a Coal Gasifier," Argonne National Laboratory.

The following papers were presented at the Carbon One Chemical Technology Symposium on March 19, 1986 in London, England: M. Blanchard, "Cl Chemistry, Catalysis and Processes" 0. F. Williams, "Direct Liquefaction of Coal" N. D. Parkyns, "Production of Premium Fuels by Gasification of Coal" W. D. Deckwer, "Developments in Fischer-Tropsch Processes" M. Dunster, "Review of Methanol Production Processes" R. M. Gould, "Status of the 100 BPD Fluid-Bed Methanol-to-Gasoline Project" G. F. Tice, "Cosolvent Alcohols from Syngas" G. G. Mayfield, "The Eastman Chemical Process for Acetic Anhydride from Coal" J. B. Saunby, "Ethylene Glycol from Syn Gas"

4-50 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Department of Mines and Energy, "Coal in Nova Scotia" Easier, T. E., "Comparison of Results of 200- and 500-h Exposures of Silicon Carbide to a Slagging Coal Gasification Environment," Argonne National Laboratory. Electric Power Research institute, "Competitiveness of Small Power Plants Using Ambient Pressure, Air-Blown Gasifiers," February 1986. Electric Power Research Institute, "Prediction of Emissions and Performance of Coal Liquids in Tangential- and Wall- Fired Boilers," March 1986. Electric Power Research Institute, "1986 Research and Development Program Plan," January 1986. Gas Research Institute, "1987-1991 Research and Development Plan and 1987 Research and Development Program," April 1986. Khan, M. R., "Production of a High-Quality Liquid Fuel from Coal by Mild Pyrolysis of Coal-Lime Mixtures," March 1986. The following papers were presented at the New Fuel Forms Workshop held in Washington, D.C., on February 25, 1986: J. W. McGlothlin, "Feeding the Iron Horse and Other Potential Coal Teôhnologies" D. M. Carlton, "New Opportunities for Coal Utilization" R. B. Harrington, "Coal: Fuel of Choice" F. B. Meserole, "A Review of Coal Chemistry and Technologies" R. A. Graft, "Rapid Devolatilization of Steam-Treated Coal" P. J. Bekowies, "Ultra-Clean Fuels from Coal" J. G. Schultz, "Oxidative Coal Solubilization" W. G. Bair, "Understanding the Fate of Coal Heteroatoms and Their Effect on the Products of Mild Gasification" P. W. Spalte, "Use of Coal Tars in the United States" G. H. Hill, "Differential Coal Liquefaction, An Economically Viable Way of Producing Liquid, Solid, and Gaseous Fuels" J. G. Sikonia, "An Examination of the Costs of Upgrading Coal Liquids" R. L. Graves, "Performance of Coal-Derived Fuels in Diesel Engines" R. A. Wolfe, "Coal Waste Energy Recovery System" G. H. Cataldi, "Coal: The Next Railroad Locomotive Fuel?" J. C. Corman, "Turbine Utilization of Coal and Coal-Derived Fuels" The following papers were presented at the Underground Coal Gasification Symposium held on August 28, 1986 in Saarbrucken, West Germany: Harald Juntgen, "Research for Future In Situ - Conversion of Coal" L. Dockter, "Underground Coal Gasification in the United States" B. E. Davis, "Optimization of UCG Economic Parameters" S. Furfari, "The Role of the Commission of the European Communities in the Field of (leG" J. Palarski, "Gas and Heat Transport in the Underground Coal Gasification" A. F. Wylde, "Underground Coal Gasification as a Means of Recovering Coal in New Zealand's North Island" J. Patigny, "Evolution of the European UCG Projects at Great Depth" V. Chandelle, "Overview About Thulin Field Test" M. Kurth, "Linking and Gasification in Thulin, A New Endeavor" T. K. Li, "Short Radius Deviated Lateral In-Seam (Drainhole) Drilling and Sidetracking Techniques Applied to the Thulin Field Test" C. Sonntag, "Surface Equipment Usable for UCG at Great Depth" H. W. Hill, "Review of the CHIP Process"

4-51 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 0. E. Martin, "Rocky Mountain I Underground Coal Gasification Test" B. E. Davis, "A Coal to Liquids Fuels Plant at Rawlins, Wyoming" C. Gadelle, "An Attractive Pilot Test Site for UCG" P. Ledent, "Unconventional Ways to UCG at Great Depth" F. H. Franke, "Survey on Experimental Laboratory Work on UCG" J. Wagner, 'Burning Channels at High Overburden Pressures" L. G. Beyer, "Large Scale Apparatus for Simulating UCG" M. Hoffmann, "Electro-osmosis and Extraction with Supercritical CO2 for Initiation of In Situ Reactions" D. Yeary, "Experimental Study of Lateral Cavity Growth Mechanisms" R. D. Skocypec, "Char Consumption in the Underground Gasification of Eastern Bituminous Coal" P. Wubben, "Permeation and Sorption Behaviour of Gas and Water in Coal" J. Brych, "Rock Mechanics for Underground Coal Gasification in Belgium" H. Dindi, "Modelling and Laboratory Studies of Electrolinking" D. Schilling, "In Situ Gasification Modelling" K. Guntermann, "An Integrated UCG-Simulation Model of Laboratory Work and Mathematical Modelling" A. Coeme, "Modelling of the Coal Gasification Process in the Framework of the Belgian-German Experiment" H. Ronde, "Simplified Modelling to Interpret High Pressure Tube Coal Gasification Results in Permeable Packed Beds" C. B. Thorsness, "A Mechanistic Model for Axisymmetric UCG Cavity Growth" H. R. Mortazavi, "A Model Describing Rubble Formation in Underground Coal Gasification Cavities" A. Hufnagl, "A Mathematical Model for Determining Characteristics of Anisotropic Porous Media" S. H. Advani, "Geomechanical Modelling Associated with Underground Coal Gasification Processes" D. Nguyen Minh, "Physical Modelling for Stability Analysis of the Linkage in Deep Underground Gasification" P. Klingenberger, "Pressure Swinging Effects on UCG" V. Shirsat, "UCG Cavity Growth Model" C. J. de Pater, "Modelling of Cavity Collapse for Gasifying Deep Seams" S. B. Tantekin, "Laboratory Characterization of Overburden Spelling Properties in Underground Coal Gasification" J. Bruining, "Coal Sample Preparation and Mass Transfer Phenomena During Tunnel Gasification" K. Kowol7Choice of a Flexible Tube to Line the Thulin Drainhole" M. Mostade, "Instrumentation, Data Processing and Evaluation in the Thulin Field Test and Their Prospects" F. P. Depouhon, "UCG Deep Well Completion with Corrosion Resistant Alloys" R. S. Upadhye, "Experimental Investigation of Coal Spelling" E. Hunsdorfer, "Method and Purpose of Carrying Out Corings Not Relieved of Overburden Pressure" F. Fuhrman, "Investigations on the Permeability of Hard Coal Under Petrostatic Pressure" 3-0 Choi, "Influence of Thermal Decomposition on Coal Oxidation" N. Schmitt, "Characterization of the Thermomechanical Behaviour of Coals" R. ft. Glaser, "Physical Simulations of Underground Coal Gasification in an Eastern Bituminous Coal" J. R. Covell, "Status and Plans for Environmental Research for Underground Coal Gasification-Affected Groundwater" R. M. Brimhall, "In Situ Gasification of East Texas Lignite: Resource Recovery and Environmetnal Changes" R. R. Glaser, "Generation, Control, and Recovery of Organic Pyrolysis Products in Underground Coal Gasification" D. N. Contractor, "Field Application of a Finite Element Water Quality Model to a Coal Seam with UCG Burns"

4-52 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 COAL - PATENTS "Coal Gasification Combustion Chamber Structure," Devendra T. Beret - Inventor, Texaco Inc., United States Patent 4,574,002, March 4, 1986. A combustion chamber for powdered coal and the like having a refractory lined floor with an exit throat at the bottom. The throat is shaped approximately in accordance with the ratios employed in a contraction cone of a wind tunnel to produce a monotonic increase in flow therethrough in order to avoid any clogging by liquid slag and fly ash. "Method of Making Carbon Black Having Low Ash Content from Carbonaceous Materials," Wenjai R. Chen and Robert L. Savage - Inventors, United States Patent 4,590,056, May 20, 1986. A partial combustion method of producing commercially acceptable carbon black containing less than approximately 1 percent ash from carbonaceous material taken from the group consisting of coal, lignites, tar sand, pitch, oil shale, and asphaltic substances, which comprises reacting the carbonaceous material with oxygen at a temperature of from 2,000°F to 3,000°F, the carbonaceous material having an average particle size of from 75 microns to 1,700 microns and wherein the oxygen to carbonaceous material weight ratio is no more than 0.4, and recovering the carbon black from the reaction. "Medium-Load Power Generating Station with an Integrated Coal Gasification Plant," Konrad Goebel, Rainer Muller, Ulrich Schiffers (all of West Germany) - Inventors, Kraftwerk Union AG, United States Patent 4,590,760, May 21, 1986. Medium-load power generating station with an integrated coal gasification plant, a gas turbine power generating station part connected to the coal gasification plant, a steam power generating station part connected to the raw gas heat exchanger plant of the coal gasification plant, a methanol synthesis pinat having a plurality of modules connected in parallel to each other, and a purified gas distribution system which connects the methanol synthesis plant to the gas turbine power generating station part and which includes a purified gas continuous flow interim storage plant and is connected on the gas side to the raw gas heat exchanger plant. The methanol synthesis plant is associated, for hydrogen enrichment, to a "cooler-saturator loop" which is connected to the raw gas heat exchanger plant and consists of the saturator, a converting plant, cooler and following gas purification plant. In one mode of operation, a water elctrolysis plant is associated with the methanol synthesis plant and its hydrogen line is connected to the methanol synthesis plant, and its oxygen line is connected to the coal gasifier. "Wear Resistant Atomizing Nozzle Assembly," Adam J. Bennett, Charles E. Capes, Kevin A. Jonass, and William L. Thayer (all of Canada) - Inventors, Canadian Patents and Development Ltd., United States Patent 4,592,506, June 3, 1986. A wear resistant atomizing nozzle assembly is provided having an outwardly diverging, frustum of a cone-shaped deflector core of wear resistant ceramic and a nozzle rim of wear resistant ceramic and having an outwardly flared inner surface encircling the core to form a flared, atomizing nozzle orifice therewith. The core is mounted in a flared socket of a deflector core holder and inner and outer sleeves feed, say, atomizing air to the deflector core surface and, say, a coal liquid mixture fuel inwardly around the nozzle rim so that the fuel is held by the air as a film against the nozzle rim inner surface and then atomized as it emerges from the nozzle rim. "Use of Ethers in Thermal Cracking," Partha S. Ganguli - Inventor, HRI Inc., United States Patent 4,592,826, June 3, 1986. A process for improving the upgrading/conversion of hydrocarbonaceous materials such as coals, petroleum residual oils, shale oils, and tar sand bitumens. In the process, the free radicals formed from thermal cracking of the hdyrocarbons are reacted with the free radicals formed by the thermal cracking of a free radical forming chemical reactant, such as dimethyl ether, to yield stable low molecular weight hydrocarbon distillate products. The hydrocarbonaceous feed material is preheated to a temperature of 6000 to 700°F, and the hydrocarbon and the free radicals forming chemical, such as dimethyl ether, are passed through a flow reactor at temperature of 750 0 to 900°F, pressure of 200 to 1,000 psi, and liquid hourly space velocity of 0.3 to 5.0 LHSV. Free radicals formed from the hydrocarbon feed material and from the ether material react together in the reactor to produce low molecular weight hydrocarbon liquid materials. The weight ratio of ether material to hydrocarbon feed material is between about 0.3 and about 2.0. "Integrated Coal Liquefaction, Gasification and Electricity Production Process," Shang-I Chang - Inventor, June 10, 1986. Methods for the physical and operational integration of a carbonaceous gasification plan, a gaseous fuel synthesis plant and a power generation station to economically produce synfuel and electrical power comprising producing gases comprising carbon monoxide and hydrogen from carbonaceous raw materials in a gasification unit wherein the gasification unit utilizes exhaust steam from a power generating unit to provide various energy needs for producing synthesis gas, utilizing the hydrogen derived from the gasification unit in the liquefying and hydrogenation of coal or hydrogenation of natural gas in a fuel synthesis unit wherein the heat generated from the exothermic reactions in the fuel synthesis unit is employed to generate high pressure steam which is fed to a power generation unit to drive electrical power producing turbines wherein the exhaust steam from the turbine is used in the gasification unit as a heat source during gasification and collecting of steam condensate from the exhaust steam and recycling condensate to provide water to the fuel synthesis unit. "Conversion of High Boiling Organic Materials to Low Boiling Materials," Curtis D. Coker and Stephen C. Paspek, Jr. - Inventors, United States Patent 4,594,141, June 10, 1986. A process for the conversion of high boiling saturated organic materials is described. The method comprises contacting said high boiling organic materials at a temperature of at least about 3000C and at a reaction pressure of at least about 2,000 psi with an aqueous acidic medium containing at least one

4-53 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 olefin, and a halogen-containing comound selected from the group consisting of a halogen, a hydrogen halide, a compound which can form a halide or a hydrogen halide in the acqueous acidic medium under the process conditions, or mixtures thereof whereby the high boiling organic material and aqueous acidic medium form a substantially single phase system. Optionally the process can be conducted in a reducing atmosphere. The process of the invention is useful for producing and recovering fuel range liquids from petroleum, coal, oil shale, shale oil, tar sand solids, bitumen, and heavy hydrocarbon oils such as crude oil distillation residues which contain little or no carbon-carbon unsaturation. Preferably, the halogen compound is at least one halogen or a hydrogen halide.

"Catalyst Rejuvenation Process for Removal of Metal Contaminants," Partha S. Ganguli - Inventor, URI Inc. United States Patent 4,595,666, June 17, 1986. Spent catalysts removed from a catalytic hydrogenation process for hydrocarbon feedstocks, and containing carbon undesired metals contaminants deposits, are rejuvenated for reuse. Following solvent washing to remove process oils, the catalyst is treated either with chemicals which form sulfate or oxysulfate compounds with the metal contaminants, or with acids which remove the metal contaminants, such as 5 to 50 weight percent sulfuric acid in aqueous solution and 0 to 10 weight percent ammonium ion solutions to substantially remove the metals deposits. The acid treating occurs within the temperature range of 600 to 250°F, for 5 to 120 minutes at substantially atmospheric pressure, after which the rejuvenated catalyst containing carbon deposits can be effectively reused in the catlytie hydrogenation.

"Sampling Value for a Fixed Bed Reactor Coal Gasification Plant," Artur Richter (of West Germany) - Inventor, Ruhrkohle AG, United States Patent 4,594,904, June 17, 1986. With sampling values for gas streams or liquids, especially in coal gasification plants and with the sampling value located close to the reactor, the functional reliability of the valve and the identity of the samples with the crude gas stream are ensured by heating and/or flushing the sampling valve. The valve has several embodiments which include features which can be used in various combinations. For example, the valve stem can include a heater, a passage for the introduction of a flushing and/or heating medium into the valve chamber. The valve housing can include a second chamber therein through which a heating medium can be circulated or by which pressure differentials on the valve chamber can be minimized.

"Coking and Gasification Process," Rustom M. Billimoria and Frank F. Tao - Inventors, Exxon Research and Engineering Company, United States Patent 4,597,775, July 1, 1986. An improved coking process for normally solid carbonaceous materials wherein the yield of liquid product from the coker is increased by adding ammonia or an ammonia precursor to the coker. The invention is particularly useful in a process wherein coal liquefaction bottoms are coked to produce both a liquid and a gaeous product. Broadly, ammonia or an ammonia precursor is added to the coker ranging from about 1 to about 60 weight percent based on normally solid carbonaceous material and is preferably added in an amount from about 2 to about 15 weight percent.

"Method of Manufacturing a Purnpable Coal/Liquid Mixture," Jorgen Cleemann - Inventor, F. L. Smidth and Company AS, United States Patent 4,598,873, July 8, 1986. In order to enable a reduction of the percentage of liquid in a liquid/coal pumping mixture the coal is dry-ground in a first grinding stage to provide a relatively coarse particle size and then a fraction of the coarse ground coal is then dry-ground in a second grinding stage to a relatively fine particle size. The fine ground fraction is then mixed with the remainder of the coarse-ground fraction and with the liquid.

4-54 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL PROJECTS

COMMERCIAL PROJECTS

ADVANCED COAL LIQUEFACTION PILOT PLANT - Electric Power Research Institute (EPRI) and United States Department of Energy (DOE) (C-15) EPRI assumed responsibility for the 6 tons per day Wilsonville, Alabama pilot plant in 1974. This project had been Initiated by Southern Company and the Edison Electric Institute in 1972. Department of Energy began cofunding Wilsonville In 1976. The initial thrust of the program at the pilot plant was to develop the SRC-I process. That program has evolved over the years in terms of technology and product slate objectives. Kerr-McGee Critical Solvent Deashing was identified as a replacement for filtration which was utilized initially in the plant and a Kerr-McGee owned unit was installed in 1979. The technology development at Wilsonville continued with the installation and operation of a product hydrotreating reactor that has allowed the plant to produces No. 6 oil equivalent liquid fuel product as well as a very high distillate product yield. More recently, the Wilsonville Pilot Plant has been used to test the Integrated Two- Stage Liquefaction (ITSL) process. In the two stage approach, coal is first dissolved under heat and pressure into a heavy, viscous oil. Then, after ash and other impurities are removed in an intermediate step, the oil is sent to a second vessel where hydrogen Is added to upgrade the oil into a lighter, more easily refined product. A catalyst added in the second stage aids the chemical reaction with hydrogen. Catalytic hydrotreatment in the second stage accomplishes two distinct purposes; (1) higher-quality distillable products are produced by mild hydroconversion, and (2) high residuum content, donor rich solvent is produced for recycle to the coal conversion first stage reactor. Separating the process into two stages rather than one keeps the hydrogen consumption to a minimum. Also, mineral and heavy organic compounds In coal are removed between stages using Kerr-McGee's Critical Solvent Deashing unit before they can foul the catalyst. Research indicates that 30 percent less hydrogen may be needed to turn raw coal into a clean-burning fuel that can be used for generating electricity in combustion turbines and boilers. Distillable product yields of greater than 60 percent MAP coal have been demonstrated during stable operations on bituminous coal. Similar operations with sub-bituminous coal have demonstrated distillates yields of about 55 percent MAP. This represents substantial Improvement over the current generation of coal liquefaction processes. Recent tests at Wilsonville are concentrated on testing from both types of coals with the deashing step relocated downstream of the catalytic hydrotreatment. Results showed that previous improvements noted for the two-stage approach are achievable (no loss in catalyst activity). Lower product cost is indicated for this reconfigured operation in that the two reactor stages may be coupled as part of one system. The results from the reconfigured operation also indicated the potential for further improvements in product quality and/or productivity through use of the coupled-reactor approach. This was confirmed in the latest test which used a truly coupled, two-stage thermal- catalytic reaction system In conjunction with an improved hydrotreatment catalyst. The catalyst (AMOCAT 1-C) was developed by Amoco Corporation, a program co-sponsor. In that test, coal space velocity was increased by 60 to 90 percent over previous operations, while catalyst productivity doubled. Furthermore, an improved configuration was developed and proven out, whereby only the net vacuum bottoms are deashed, thereby reducing the equipment size substantially. Preliminary engineering evaluations project greater than a 20 percent savings in the product cost compared to previous liquefaction processes, while producing much more desirable fuels. Current research is exploring the potential benefits of adding catalyst to the first stage reactor. (Also refer to the Solvent Refined Coal Demonstration Plant (SRC-1) and the Integrated Two Stage Liquefaction projects.)

Project Cost: Construction and operating costs (through calendar 1985): $97 million AECI AMMONIA/METHANOL OPERATIONS— AECI LTD. (C-li) AECI operates a 100 ton per thy methanol facility and a 1,000 ton per day ammonia plant at its Modderfontein works near Johannesburg. The plant uses six Koppers-Totzek two-headed gasifiers operating at 1,600 0C and atmospheric pressure to generate synthesis gas from sub-bituminous South African coal of low sulfur and high ash content. The ammonia plant, which utilizes conventional technology in the synthesis loop, has been in service since 1974 while the methanol unit, which employs ICI's low pressure process, has been running since 1976. The plant is operating very satisfactorily at full capacity. A fluidized bed combustion system is presently being commissioned at the plant to overcome problems of ash disposal. The proposed system will generate additional steam, lower utility coal consumption, and reduce requirements for land for ash handling and burial.

4-55 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

AECI has successfully completed the piloting of a methanol to hydrocarbons process using Mobil zeolite catalyst. The design of a commercial scale ethylene plant using this process has been completed. AECI has also pursued development programs to promote methanol as a route to transportation fuel. Test programs include operation of a test fleet of vehicles on gasoline blends with up to 15 percent methanol, operation of other test cars on neat methanol, and operation of modified diesel trucks on methanol containing ignition promoters, trademarked "DIESANOL" by ABC!. "DIESANOL" has attracted worldwide interest and is currently being evaluated as a diesel fuel replacement in a number of countries. AECI has completed a detailed study to assess the economic feasibility of a coal-based synthetic fuels project producing gasoline and diesel using methanol conversion technology. The results of this study were encouraging and the second phase of this project has now been implemented. This involves an accurate definition of project scope and the preparation of a sanction grade capital cost estimate. The project has the potential for recovery of ethylene and other petrochemical feedstocks, co-production of ammonia and extraction of methanol for development of the methanol fuel market in South Africa. Project Cost: Not disclosed

*APPALACHIAN PROJECT -- The M. W. Kellogg Company; KEW Energy Systems Inc. (a company jointly owned by M. W. Kellogg and the Westinghouse Electric Corporation); the General Electric Company; and the Pennsylvania Electric Company (Penelec); and United States Department of Energy (C-19) At the Appalachian Project the applicants will demonstrate an advanced integrated coal gasification combined cycle (10CC) system. The project, to be located at Cairnbrook, Pennsylvania, will feature the Kellogg-Rust-Westinghouse (Flaw) ash agglomerating fluidized-bed gasification process. One KRW gasifier operating in the air-blown mode will convert 485 tons per day of bituminous coal into a low-BTU fuel gas for use in an advanced combustion turbine generator. Steam generated from the combustion turbine exhaust and from the gasifier heat recovery system will be fed to a steam turbine generator. The 60 megawatt demonstration project will feature a hot gas cleanup system which delivers fuel gas at 1,0000 to 1,2000F to the combustion turbine, thus avoiding inefficient lower temperature cleanup processes. This system uses in-bed desulfurization and a hot-sulfur-removal polishing step consisting of a zinc ferrite sorbent bed. Particulates will be removed by a sintered metal filter. The system, if demonstrated as proposed, would be highly efficient with heat rates around 7,800 BTU per kilowatt hour. Various sizes of commercial plants can be configured by using the 60 megawatt module that will be demonstrated. Other applications for the system are cogeneration and retrofit of combustion turbines and gas-fired combined cycles. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: Not Disclosed

AQUA BLACKTM COAL-WATER FUEL PROJECT -- Gallagher Asphalt Company, Standard Havens, Inc. (C-23) In response to the United States Synthetic Fuels Corporation's solicitation for coal-water fuel projects, Standard Havens, Inc. has proposed that the current Aqua Black plant located at the site of the Gallagher Asphalt Company in Thornton, Illinois in the Chicago metropolitan area be expanded in its production capability to match United States Synthetic Fuels Corporation specifications. The project would then produce 1,000 barrels crude oil equivalent per day of coal-water fuel utilizing Standard Havens' technology. Co-sponsor of the project is the Gallagher Asphalt Company. Project engineering, design, and procurement will begin shortly after February 21, 1985 and the upgraded plant will be fully operational by June 30, 1986. The fuel will be sold to a variety of industrial users. Fuel use applications are within an economic truck and barge shipping distance from the plant. On July 24, 1984 the SFC announced that the staff will recommend to the SFC Board that it designate the project as a qualified bidder under the solicitation. The SFC's January 15, 1985 decision to eliminate any SFC assistance for the "industrial" portion of the solicitation put the plans for an expanded CWS plant on hold. The existing 7 tons per hour CWS plant, located at Gallagher Asphalt Corporation, in Thornton, Illinois, will not produce CWS fuel for the 1986 asphalt production season The possibilities for coke/water fuel production are being studied.. Project Cost: Not Disclosed

4-56 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continuecfl

BEACH-WIBAUX PROJECT— (See Tenneco SNG from Coal Project) BOVFROP DIRECT COAL LIQUEFACTION PILOT PLANT PROJECT-- Federal Ministry of Research and Development of West Germany, Ruhrkohle AG, VEBA OeI AG, and West German State of North-Rhine Westphalia (C-65) After 2 years of construction the 200 tons per day catalytic liquefaction pilot plant has been in operation since November 1981. (Investment: DM220 million (1984 DM)). The coal oil pilot plant had operated with coal for about 20,000 hours. Total coal throughput was about 150,000 tons. During operation of the pilot plant the process improvements and equipment components have been tested. The operation of the large-size hydrogenation reactor with a volume of 15 cubic meters since March 1985 as an intermediate step toward industrial application has led to an increased oil yield. Besides an analytical testing program, the project involves upgrading of the coal-derived syncrude to marketable products such as gasoline, diesel fuel, and light heating oil. The hydrogenation residues were gasified either in solid or in liquid form in the Ruhrkohle/Ruhrchernie gasification plant at Oberhausen-Holten to produce syngas and hydrogen. The coal oil plant at Bottrop will run until early 1987 to optimize hydrogenation process especially to increase the oil yield further. For this purpose process units are presently modified.. The project is subsidized by the West German State of North-Rhine Westphalia and since mid-1984 by the Federal Ministry of Research and Development of West Germany. Project Cost: DM700 million (by mid-1986) BROKEN HILL PROJECT - The Broken Hill Proprietary Company Ltd. (C-75) Broken Hill Proprietary has been experimenting with a two stage continuous flow hydrogenation unit since 1976 at their Melbourne Research Laboratories in Clayton, Victoria. In the initial selection of processes, consideration was given to those that would produce good quality gasoline. However, the program has now been modified to put more emphasis on automotive diesel and aviation fuels. The unit has operated successfully for periods of up to five days continuous processing and a range of coals has been tested. Throughput is 1 kilogram coal per hour. Near- specification automotive distillates and jet fuels have been produced from coal-derived materials, and work continues to optimize the unit for the conversion of coal to transport fuels. The work is supported under the National Energy Research Development and Demonstration Program (NERD&DP) administered by the Australian Federal Government. A program on the conversion of natural gas to synthetic crude and transport fuels has been running since 1978 and is studying routes based on Fischer-Tropsch synthesis, use of zeolite catalysts and thermal cracking. Most of this work is funded by Broken Hill Proprietary and some funding is obtained under the NERD&DP. Project Cost: Not disclosed BYRNE CREEK POWER PROJECT-- (See Underground Coal Gasification - World Energy, Inc. Project) CAN DO PROJECT - Continental Energy Associates (C-85) Greater Hazleton Community Area New Development Organization, Inc. (CAN DO, Incorporated) built a facility in Hazle Township, Pennsylvania to produce low BTU gas from anthracite. Under the third general solicitation, CAN DO requested price and loan guarantees from the United States Synthetic Fuels Corporation (SFC) to enhance the facility. However, the SFC turned down the request, and the Department of Energy stopped support on April 30, 1983. The plant was shut down and CAN DO solicited for private investors to take over the facility. The facility is currently being converted into a 100 megawatt cogeneration plant. Gas produced from anthracite coal in both the original facility and in new gasifiers will be used to fuel turbo engines to produce electricity. The electricity will be purchased by the Pennsylvania Power & Light Company over a 20 years period. Steam will also be produced which will be available to industries within Humboldt Industrial Park at a cost well below the cost of in- house steam production. The project cost for this expansion is $39 million. The Pennsylvania Energy Development Authority authorized the bond placement by the Northeastern Bank of Pennsylvania and the Swiss Bank. The new facility will be operated by the Continental Energy Associates. Project Cost: $5.5 million

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CATERPILLAR TRACTOR LOW BTU GAS FROM COAL PROJECT-- Caterpillar Tractor Company (C-90) 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 standard cubic feet per day of natural gas could be produced. The plant is a two-stage, low-pressure system complete with gas cleanup. Plant construction began in September 1977. Construction of a gasifier for the East Peoria, Illinois, plant has been deferred indefinitely although the York installation is successful. Plant was completed June 1979, with start-up for debugging in September 1979. Due to an eleven-week strike in the last quarter of 1979 and some minor equipment changes that had to be made, debugging was not resumed until May 1980. Tests have been run on existing radiant tubes using producer gas with no adverse effect. The system operated from February 1981, until the July vacation shut-down. After vacation, the system was started up but later shut down in September 1982 due to reduced production schedules. Start-up date is not firm; depends on the price of natural gas and Caterpillar's production schedules.

Project Cost: $5-10 million. CHEMICALS FROM COAL -- Tennessee Eastman Co. (C-ISO) Tennessee Eastman Company, a manufacturing unit of the Eastman Chemicals Division of Eastman Kodak Company, continues to operate its chemicals from coal complex at design rates in 1986. The Texaco coal gasification process is used to produce the synthesis gas for manufacture of 500 million pounds per year of acetic anhydride. Methyl alcohol and methyl acetate are produced as intermediate chemicals, and sulfur is recovered and sold.

Project Cost: Unavailable CHIRIQUI GRANDE PROJECT - Ebasco Services Inc., United States State Department (Trade and Development Program) (C-155) Ebasco has delayed its plans to structure a $10 million, 18 month feasibility study of its 4 million tons per year methanol from coal project. The delay is indefinite pending improved resolution of trade issues between the United States and Japan combined with Japan clarifying its forecasts for future energy development. The project, to be located at Chiriqui Grande, Panama, would use either Texaco or British Gas/Lurgi slagging gasification and ICI methanol synthesis. A dedicated pipeline would transfer the methanol from the Caribbean side of Panama to the Pacific side for VLC tanker delivery to Pacific Rim countries. Feedstock is 20,000 tons per day of imported high-sulfur Illinois coal. The methanol product is slated for Japanese utility markets as a clean burning alternate fuel instead of direct firing of coal. The coal based methanol would be used in combined cycle power plants or for repowering existing units. The economics of coal based methanol firing in combined cycle units and the associated reduced environmental impacts highly favor such use.

Project Cost: $10 million (study) $3.2 billion (project) - 1984 dollars CIRCLE WEST PROJECT - Meridian Minerals Company (C-lw) Meridian (a wholly owned subsidiary of Burlington Northern) 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, McCone County, Montana. Koppers and Kellogg presented a preliminary engineering study to the Montana Department of Natural Resources and Conservation in February 1976 for a plant to produce 2,300 tons per day fertilizer grade liquid anhydrous ammonia, or 2,174 tons per day fuel-grade methanol, or about the same quantity of synthetic diesel fuel oil, or perhaps some combination of these possible products. Basin Electric Power Cooperative joined BN-Dreyer Bros. in September 1977, to evaluate the feasibility of a power plant having common coal mining facilities with BN plant. Lignite would be used in synthetic fuels or fertilizer plant or for Basin Electric plant. Main effort of Meridian was to complete a land exchange with the Department of Interior. The exchange was approved by DO] in late April 1983 and accomplished in September 1983.

Project Cost: Undetermined CITIES SERVICE/ROCKWELL PROCESS DEVELOPMENT -- Rockwell International (Energy Systems Group) and United States Department of Energy (C-iSO) The CS/R (Cities Service and Rockwell) process is based on flash hydropyrolysis (FHP) of finely pulverized materials (e.g., coal, peat, or oil shale) in single-stage, short-residence-time, entrained-flow reactors. The slate of synthetic

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fuels produced from coals depends on the severity of the FHP reactor operating conditions and the reactor residence time. Low seventies and very short times favor yielding an essentially liquid syncrude, along with modest yields of gases (e.g., CO, CU 4, C21s, C3's, etc.). High seventies and long residence times favor production of all gaseous products, predominantly CH4. At intermediate seventies and times, the heavy syncrude components are hydrocracked to light, predominantly aromatic liquids. Under certain conditions, there is a substantial yield of high- purity benzene as the sole by-product, and it can be upgraded readily to chemical-grade quality. Rockwell has studied coal hydrolique faction and hydrogasitication in 1/4- and 1-ton per hour engineering-scale reactor and process development systems under several DOE contracts. The liquefaction work, performed in four discrete phases beginning in 1975, was brought to a close in 1982 with the publication of two comprehensive final reports. These summary reports include a preliminary design study for a commercial CS/R hydropyrolysis coal liquefaction plant performed by Scientific Design Company, Inc., and signifisant work by Cities Service in characterizing FHP coal liquids. For high-BTU coal gasification, DOE awarded Rockwell an $18 million contract in 1978 to design, construct, and operate an 18-ton per day integrated hydrogasification PDU at Rockwell's Santa Susana Field Laboratory near Canoga Park, California. Construction of the IPDU was interrupted in FY 1982 when the facility was about 60 percent completed. Rockwell has restructured the project into a proposed joint DOE/private industry program, with Rockwell heading a consortium of private sector participants. Currently, this program uses the existing 1 ton per hour process development system and involves a test program designed to thoroughly investigate recent process improvements proposed by Rockwell. The restructured program resumed in May 1983 with the design of facility modifications to permit short-duration (1 to 2 hours) hydrogasification testing. The facility will accommodate hydrogasifier reactors with residence times in the range of 2 to 6 seconds when coal is fed at a nominal 1/2 ton per hour into reactors at 1,000 psia pressure. The program is schedule to extend through May 1985 and include 5 months of reactor performance testing. In May 1981, the C-E Lummus Company, under subcontract to Rockwell, completed the preliminary conceptual design of a 250-billion BTU per day, high-BTU coal gasification plant based upon the CS/R Hydrogasification Process. In addition to synthetic natural gas, the plant was designed to produce 5,310 barrels per day of chemical- grade benzene. Lummus estimated the capital and operating costs for the commercial plant, and the resulting 20- year average cost of gas was $3.68 per million BTU in mid-1979 dollars (C.!'. Braun gas cost guidelines, utility financing). Subsequent process modifications have reduced the COG to $3.38 per million BTU. In October 1982, DOE awarded Rockwell a $0.6 million contract for experimental evaluation of hydroretorting of eastern oil shale in a CS/R hydropyrolysis reactor. Reactor testing covered a range of temperatures (1,098° to 1,422°F) and residence times (67 to 211 ms) at a pressure of 1,000 pain. Carbon conversions as high as 70 percent were achieved with oil yields up to 19.0 gallons of raw liquid per ton of oil shale (50 percent above Fischer assay). Testing was followed by the performance of a conceptual process and economic study for a 50,000 barrels per day shale oil plant, using a selected operating point from the test data. The resulting 20 year average cost of product oil was estimated at $35.20 per barrel in first quarter 1983 dollars (C.F. Braun guidelines, utility financing). Project Cost: $26.1 million (PDU Studies) COALPLEX PROJECT - AECI (C-190) The Coalplex Project is an operation of AECI Chlor-Alkali and Plastics, Ltd. The plant manufactures PVC and caustic soda from anthracite, lime, and salt. The plant is fully independent of Imported oil. Because only a limited supply of ethylene was available from domestic sources, the carbide-acetylene process was selected. The plant has been operating since 1977. The five processes include calcium carbide manufacture from coal and calcium oxide; acetylene production from calcium carbide and water; brine electrolysis to make chlorine, hydrogen, and caustic; conversion of acetylene and hydrogen chloride to vinyl chloride; and vinyl chloride polymerization to PVC. Of the five plants, the carbide, acetylene, and VCM plants represent the main differences between coal-based and conventional PVC technology. Project Cost: Not disclosed

COGA-1 PROJECT - Coal Gasification (C-195) COGA-1 project has been under development since 1983. The proposed project in Macoupin County, Illinois will consume over I million tons of coal per year and will produce 500,000 tons of ammonia and 500,000 tons of urea per year. It will use the U-Gas coal gasification system developed by the Institute of Gas Technology (IGT). When completed, the COGA-1 plant would be the largest facility of its kind in the world.

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Sponsors were in the process of negotiations for loan guarantees and price supports from the United States Synthetic Fuels Corporation when the SFC was dismantled by congressional action in late December 1985. On March 18, 1986 Illinois Governor James R. Thompson announced a $26 million state and local incentive package for COGA-1 in an attempt to move the $600 million project forward. Potential project sponsors, which include Coal Gasification, Inc., Freeman United Coal Company, and the Norwegian fertilizer firm Norsk-Hydro, are currently working to complete the financing package for the facility. Project Cost: $600 million

COOL WATER COAL GASIFICATION PROJECT -- Participants (Equity Owners): Bechtel Power Corporation, Electric Power Research Institute, General Electric Company, Japan Cool Water Program (JCWP) Partnership, Southern California Edison, and Texaco Inc.; Contributors: Empire State Electric Energy Research Corporation (ESEERCO) and Sohio Alternate Energy Development Company (Sohio) (C-220) Participants have built a 1,000 tons per day commercial-scale coal gasification plant using the oxygen-blown Texaco Coal Gasification Process. The gasification system which includes two Syngas Cooler vessels, has been integrated with a General Electric combined cycle unit to produce approximately 120 megawatts of gross power. The California Energy Commission approved the state environmental permit in December 1979 and construction began in December 1981. Plant construction which took only 2.5 years, was completed on April 30, 1984, a month ahead of schedule and well under the projected $300 million budget. A five-year demonstration period is underway. Once the first stage (demonstration) of the program is completed in June 1989, Southern California Edison plans to undertake commercial operation of the facility if the economics are favorable and permits for continued operations are received. A spare quench gasifier, which has been added to the original facility to enhance the plant capacity factor, was successfully commissioned in April 1985. A Utah bituminous coal will be utilized as "the Program" coal and will be burned at all times that the facility is not burning an alternate test coal. The Program will test up to 8 different coal feedstocks on behalf of its Participant companies. Tus far, a 32,000 ton Illinois No. 6 coal test (nominal 3.5 percent weight sulfur) and a 21,000 ton Pittsburgh No. 8 coal test (nominal 2.0 percent weight sulfur) have been completed. Energy conversion rates and environmental characteristics while running the high sulfur coal are essentially the same as those observed while burning the low sulfur Utahinous bitumin. Texaco and SCE, which have contributed equity capital of $45 million and $25 million respectively to the effort, signed the joint participation agreement on July 31, 1979. The Electric Power Research Institute (EPRI) executed an agreement to participate in the Project in February 1980 and their current commitment is $69 million. Bechtel Power Corporation was selected as the prime engineering and construction contractor and also executed a participation agreement in September 1980 and have contributed $30 million to the project. General Electric signed a participation agreement in September 1980. In addition to contributing $30 million to the Project, GE will be the supplier for the combined cycle equipment. The JCWP Partnership, comprised of the Tokyo Electric Power Company, Central Research Institute of the Electric Power Industry, Toshiba CGP Corporation and lHl Coal Gasification Project Corp. signed a participation agreement on Februrary 24, 1982 to commit $30 million to the Project. ESEERCO and Betio Alternate Energy Development Company are non-equity contributors to the project, having signed contributor agreements on January 20, 1982, and April 10, 1984, respectively committing $5 million each to the Project. A $24 million project loan with a $6 million in-kind contribution by SCE of facilities at SCE's existing generating station in Daggett, California completes the $263 million funding. A supply agreement was executed with Airco, Inc. on February 24, 1984 for Airco to provide "over-the-fence' oxygen and nitrogen from a new on-site facility, thus reducing capital requirements of the Project. The Project applied to the United States Synthetic Fuels Corporation for financial assistance in the form of a price guarantee in response to the SFC's first solicitation for proposals. This was designed to reduce the risks of the existing Participants during the initial demonstration period. The Project was not accepted by the SFC because it did not pass the "credit elsewhere" test (the SFC believed sufficient private funding was available without government assistance). However, the sponsors reapplied for a price support under the SFC's second solicitation which ended June 1, 1982. On September 17, 1982, the SFC announced that the project had passed the six-point project strength test and had been advanced into Phase II negotiations for financial assistance. On April 13, 1983 the sponsors received a letter of intent from the SFC to provide a maximum of $120 million in price supports for the project. On July 28, 1983 the Board of Directors of the SFC voted to approve the final contract awarding the price guarantees to the project.

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The gasifier was started up on May 7, 1984. On May 20, 1984 syngas was successfully fed to the gas turbine and the first combined cycle system operation was accomplished on May 31, 1984. On June 23, 1984 the ten continuous day SFC acceptance test was successfully completed and the Program was declared to be in initial production on June 24, 1984. In a June 25, 1985 press release, celebrating the first anniversay of its plant's commercial production commencement date (June 24, 1984), the Program announced that among the accomplishments during the "highly successful" first year of operations were: generation of approximately 413 million kilowatt hours of electricity from about 180,000 tons of coal; a California Department of Health Services finding that the Texaco Gasification Process slag was non-hazardous (the Program already sells its by-product elemental sulfur) and the successful commissioning of a spare gasifier. The plant is often referred to as "the worl'ds cleanest coal-fired utility plant" with operations data reflecting NOx emissions of 0.061 pounds per million BTU; sulfur dioxide emissions of 0.034 pounds per million BTU (97 percent removal), and particulate emissions of 0.0013 pounds per million BTU. These emissions average about one-tenth of the allowables under the United States Environmental Protection Agency's New Source Performance Standards for coal-fired power plants. Project Cost: $263 million CYCLONE COMBUSTOR DEMONSTRATION PROJECT - Coal Tech Corporation, Pennsylvania Power and Light Company, Southern California Edison Company, State of Pennsylvania Energy Development Authority, and United States Department of Energy (C-231) This proposed project is for a 1,000 hour test to demonstrate the performance of an advanced, air-cooled, cyclone combustor with dry pulverized coal. Two Pennsylvania bituminous coals, containing 2 percent and 3 to 4 percent sulfur, and one Utah subbituminous coal containing 0.5 percent sulfur will be tested to demonstrate that this advanced combustor is capable of burning a variety of United States coals in an environmentally acceptable manner. The technical performance objectives of the proposed project are to demonstrate: (1) 90 to 95 percent coal ash retention in the combustor (and subsequent rejection), (2) NOx reductions to 100 ppm or less, (3) sulfur dioxide emission reductions of 70 to 90 percent, and (4) combustor durability and flexibility. The combustor can be adapted to new as well as retrofit boilers; it can be used for converting oil- and gas-designed boilers to coal; and it has industrial and utility applications. The Coal Tech Corporation is now constructing a 30 million BTU per hour (1 ton per hour) combustor which is nearing completion. The proposed demonstration project will be conducted at the Keeler Boiler Company/Dorr-Oliver site in Williamsport, Pennsylvania, where a 23 million BTU per hour D-tube package boiler designed for oil is available. The 27 month demonstration project includes 1,000 hours of testing. The Keeler Boiler Manufacturing Company will assist Coal Tech in the implementation of the project. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. The five sponsors will contribute 50 percent of the project cost. Project Cost: Not disclosed DOW GASIFICATION PROCESS DEVELOPMENT -- The Dow Chemical Company (C-242) Dow has developed a coal gasification process primarily for the gasification of lignite, western, and other low-rank coals. This development originated in a 12 tons per day air-blown pilot plant. In 1983 the pilot plant was modified to a 36 tons per day oxygen-blown unit and an 800 tons per day air-blown prototype plant was completed and started up. The prototype unit was modified to a 1,600 tons per thy oxygen-blown configuration in early 1984. The prototype plant has operated at rates up to capacity during 1985. Data from the prototype plant were used to complete the design of the Dow Syngas Project (Dow Chemical Company C-245). The process incorporates a Dow- developed entrained flow, slagging, slurry fed gasifier with a unique heat recovery technique for high efficiency on low-ranked coal. Also utilized is a newly developed, continuous-slag removal system. High temperature heat from the reactor off gas is recovered as high pressure superheated steam. A particulate removal system is also incorporated as a basic part of the process. The particulate-free raw syngas is suitable for further processing by a wide variety of commercially available processes to provide medium-BTU gas. The medium-BTU gas may be used as fuel or further processed to provide chemical synthesis gas, SNG, or liquid fuels. The process development stage of this project has been completed. Both the pilot plant and the prototype plant are now inactive. Data from the plants have been incorporated into the Dow Syngas Project. Project Cost: Unavailable

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DOW SYNGAS PROJECT —Dow Chemical Company (C-245) The Dow Chemical Company proposed a project to produce medium-BTU gasfrom lignite and other lower rank coals using its own technology. The proposed plant, to be sited at Dow's chemical plant in Plaquemine, Louisiana, has n nameplate capacity of 30 billion BTU of synthetic gas per day. Feedstock will initially be 2,300 tons per day of western sub-bituminous coal. Dow entrained-bed gasification, Dow Selectamine acid-gas removal, and Union Oil Selectox sulfur recovery will be used. In this application the Dow Gasification Process and the associated process units have been optimized for the production of synthetic gas for use as a combustion gas turbine fuel. The project requested price guarantees from the United States Synthetic Fuels Corporation under the third solicitation. During 1983 the project passed the SFC maturity, strength, and technical evaluations and entered Phase II negotiations for assistance. The Board of Directors of the SFC instructed their staff on February 16, 1984 to negotiate a letter of intent for $620 million in price guarantees for the project. The letter of intent was issued on April 5 and a final contract awarding $620 million to the project was signed by the SFC Board on April 26, 1984. Overall responsibility for engineering and construction has been assigned to Dow Engineering Company. Engineering is complete and all construction contracts have been awarded. As of June 1, 1986 construction was 25 percent complete. Construction is expected to be complete in the first quarter, 1987, with start-up to be in the second quarter 1987.

Project Cost: $75,000,000 DUNN NOICOTA METHANOL PROJECT --The Nokota Company (C-250) The Nokota Company is the sponsor of the Dunn-Nokota Methanol Project, Dunn County, North Dakota. Nokota plans to convert a portion of its coal reserves in Dunn County, via coal gasification, into methanol and other marketable products, including carbon dioxide for enhanced oil recovery in the Williston and Powder River Basins. Planning for the project is in an advanced position. $20 million has been spent, and 12 years have been invested in site and feasibility studies. After thorough public and regulatory review by the state of North Dakota, air quality and conditional water use permits have been approved. The Bureau of Reclamation is scheduled to release the final Environmental Statement in 1986. The Federal Water Service Contract is expected to be approved in 1987. Operation of Phase I of the project is scheduled to begin in 1992. In terms of the value of the products produced, the Dunn-Nokota project is equivalent to an 800 million barrel proven oil reserve. In addition, the carbon dioxide product from the plant can be used to recover substantially more crude oil from oil fields in North Dakota, Montana, and Wyoming through carbon dioxide injection and crude oil displacement. The Dunn-Nokota plant is designed to use the best available environmental control technology. The impacts which will occur from the construction and operation of this project will be mitigated in accordance with sound operating procedures and legal and regulatory requirements. At full capacity, the plant will use the coal under approximately 390 acres of land (about 14.7 million tons) each year. Under North Dakota law, this land is required to be reclaimed and returned to equal or better productivity following mining. Nokota will be working closely with local community leaders, informing them of the types and timing of socio-eeonolnie impact associated with this project. Dunn-Nokota would produce approximately 81,000 barrels of chemical grade methanol, 2,400 barrels of gasoline blending stock (naphtha) and 300 million standard cubic feet of pipeline quality, compressed carbon dioxide per day from 40,000 tons of lignite (Beulah-Zap bed). Additional market studies will determine if methanol production will be reduced and gasoline or substitute natural gas coproduced. Normal electrical power requirements for the plant and the mine will be provided by in-plant generation (212 megawatts). Existing product pipelines and rail facilities are available to provide access to eastern markets for the project's output access to eastern markets for the project's output. Access to western markets for methanol through a new dedicated pipeline to Bellingham, Washington, is also feasible if West Coast market demand warrants. Construction employment during the six year construction period will average approximately 3,200 jobs per year. When complete and in commercial operation, employment will be about 1,600 personnel at the plant and 500 personnel in the adjacent coal mine. Nokota's schedule for the project calls for phased construction and operation, with initial construction (site preparation) beginning in 1989 (fourth quarter) and mechanical construction beginning in 1989 on a facility producing at one-half the full capacity. Commercial operation of this phase of the project is scheduled for 1992. Construction of the remainder of the facility is scheduled to begin in 1991 and to be in commercial operation in 1994. This

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schedule is subject to receipt of all permits, approvals, and certifications required fro:n federal, state, and local authorities and upon appropriate market conditions for methanol and other products from the proposed facility. Project Cost: $2.2 billion (Phase land II) $0.4 billion (In-plant electrical generation) $0.2 billion (CO2 compression) $0.1 billion (Pipeline interconnection) $0.3 billion (mine) • EBULLATED BED COAL/OIL CO-PROCESSING PROTOTYPE -- Ohio Ontario Clean Fuels Inc., Stearns Catalytic Inc., fiR! Inc., Ohio Coal Development Office, and United States Department of Energy (C-253) This project is a prototype commercial coal/oil co-processing plant to be located in Warren, Ohio. This plant will convert high sulfur, high nitrogen, Ohio bituminous coal and poor-quality petroleum to produce clean liquid fuels. The process to be utilized is HRI, Inc.'s proprietary commercial ebullated-bed reactor technology. In this process coal is blended with residual oil and both are simultaneously converted to clean distillate fuels. A "typical" C4- 975°F distillate fuel will contain 0.1 percent sulfur and 0.2 percent nitrogen. The prototype plant will process 800 tons per day of coal, plus residual oil sufficient to yield 11,750 barrels per day of distillate product. Startup of the plant is slated for 1990. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: $217.5 million • EDGEWATER STATION LIMB DEMONSTRATION PROJECT -- Ohio Coal Development Office, United States Depart- ment of Energy and United States Environmental Protection Agency (C-258) The two part project will develop retrofit acid rain precursor control technologies. The first part is an extension of on-going Limestone Injection Multistage Burner (LIMB) testing. Babcock & Wilcox is currently conducting the full- scale demonstration of the LIMB technology on a 105 megawatt wall-fired utility boiler in a project co-sponsored by the EPA and the State of Ohio at Ohio Edison's Edgewater Station in Lorain, Ohio. The objectives of this project are to demonstrate nitrogen oxide and sulfur dioxide emissions reductions on the order of 50 to 60 percent at a capital cost at least $100 per kilowatt less than wet scrubber,. The Unit 4 boiler at the Edgewater Station was originally commissioned in 1957, and is designed to burn approximately 45 tons of coal per hour. An electrostatic precipitator designed for over 99 percent particulate emission control was installed in 1982. At the present time the plant burns a low-to-medium sulfur coal. The second part of the project will evaluate the Conoco "Coolside" process for sulfur dioxide control. This process involves dry sorbent injection/humidification technology downstream or the boiler. The "Coolside" technology has been tested in a 1 megawattt field test at DuPont's Martinsville plant. The proposed demonstration will also be done at the Edgewater Station and will provide a side-by-side comparison with LIMB. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: $27.5 million ELM WOOD COAL-WATER FUEL PROJECT-- Foster Wheeler Tennessee, Inc. (C-265) Foster Wheeler Tennessee, Inc. was organized in September 1984 to produce coal water fuel. Construction of the plant was initiated mid-April 1985, and completed September 27, 1985. Production operation began on October 31, 1985 producing coal water fuel using the patented Carbogel process. The plant, designed to produce at the rate of eight tons per hour, ran satisfactorily at higher rates, although it normally operated at lower levels of output. Product CWF burns well without support fire from alternate sources.

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TheElmwood plant has been put on a standby basis, ready to resume operations at anytime that sufficient interest justifies continuing effort on the development of this alternate fuels technology. Project Cost: Not Disclosed

FLASH PYROLYSIS OF COAL WITH REACTIVE AND NON-REACTIVE GASES - Brookhaven National Laboratory and United States Department of Energy (C-340) The purpose of this program is to perform a systematic generic study on the flash pyrolysis of coal with reactive and non-reactive gases. The result of this task is to establish a reliable data base for the rapid pyrolysis of coal over a range of reaction conditions which will be useful for development of processes based on these techniques. The yields and distribution of products are being performed in an entrained tubular reactor. The independent variables investigated include type of coal, process gas, pressure, temperature and residence time. Other dependent variables include coal particle size and gas-to-solid feed ratio. The non-reactive gases being investigated include the inert gases, He, N2 and Ar chosen for their wide range of physical properties. The reactive gases include 112, CO, H20 and CH4 chosen because they are usually produced when coal is pyrolyzed. The light gas and liquid analyses are performed with an on-line gas chromatograph and the heavier liquids and solids are collected at the end of a run to obtain a complete mass balance. The data is reduced, correlated, and applied to a kinetic model. The results indicate that there is a correlation of increasing hydrocarbon yields with heat transfer film coefficient depending on the type of gas used. The reaction of methane with coal indicated significant increases in benzene and ethylene yields. The process has been termed "flash methanolysis."

Project Cost: $250,000

PULARJI LOW BTU GASIFIER -- KRW Energy Systems Inc. (a subsidiary of Kellogg Rust Synfuels Inc.) and the Ministry of Machine Building Industry of the People's Republic of China (C-375) The KRW gasification process has been selected by the Ministry of Machine Building Industry in the People's Republic of Chania, for application at their First Heavy Machinery Works located in Fularji, Heilongjiang Province. The gasifier will utilize a domestic lignite coal to produce a medium heating value industrial fuel gas for use at this plant. The First Heavy Machinery Works is the largest heavy machinery plant in Asia. The initial plant was designed and built in the mid-1950s and has been expanded several times. Currently the plant employs approximately 17,000 people. The Fularji plant utilizes a large quantity of fuel gas, primarily for their foundry, heating treating furnaces, etc. A series of 25 Russian designed fixed bed gasifiers has been built In August 1985, a contract was signed by Kellogg Rust Synfuels, Inc. and the Ministry of Machine Building Industry to construct a KEW gasifier at the Fularji First Heavy Machine Works. Once proven, additional fluidized bed gasifiers will be installed to replace all of the existing fixed bed gasifiers at the Fularji plant. The project is envisioned to proceed in two phases. During Phase I, a single test gasifier will be installed to finalize design parameters at full scale and to verify Chinese equipment supply. Phase II would include the Installation of additional gasifiers and other auxiliary facilities (waste water treatment, etc.). The preliminary schedule for Phase I requires completion of design and the initiation of hardware procurement in 1986 and completion of construction by late 1987. This early date will be the first commercial scale operation of the KEW gasifier. The split of responsibility for Phase I is as follows: Kellogg Rust Synfuels, Inc. will provide all basic engineering services to include process design and analytical engineering, with detailed design of the gasifier to permit fabrication and construction by the First Heavy Machinery Works. Kellogg Rust Synfuels, Inc. will also provide specialized components of the gasifier and instrumentation not available in China and advisory services during construction, startup, and testing. The First Heavy Machinery Works will complete the detailed design of Phase I (except the gasifier) and will fabricate or supply and erect all equipment, using the specialized items provided by Kellogg Rust Synfuels, Inc. The First Heavy Machinery Works will also provide all necessary operating and maintenance manpower and materials necessary for startup and test operations.

4-64 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

Each KRW gasifier at Fularji must produce 140 million BTU per hour of fuel gas with a lowerheating value of 144 BTU per standard cubic feet. A single 3 meters (9.8 feet) gasifier operating at a pressure of 300 psig, will produce the fuel gas required for Phase I.

Project Cost: Not disclosed

GAS REBURNING SORBENT INJECTION DEMONSTRATION PROJECT -- Energy and Environmental Research Corporation, Gas Research Institute, State of Illinois, and United States Department of Energy (C-382) The Energy and Environmental Research Corporation (EER) intends to demonstrate a combination of natural gas reburning and sorbent injection for the control of $02 and NOx emissions from existing coal-fired boilers. Program are 60 percent NOx control and 50 percent 502 control. Gas reburning is achieved by injection of natural gas (10F, and 20 percent of the total fuel input) above the normal furnace heat release zone to produce an oxygen deficient region in the upper furnace (reburning zone). Burnout air is introduced above the reburning zone to complete the fuel combustion. A portion of the NOx produced in the main heat release zone is decomposed to molecular nitrogen In the reburning zone. Because the reburning fuel contains no sulfur, SO2 emissions are reduced in proportion to the amount of gas fired. Additional SO2 emission reductions are obtained by injecting calcium- based sorbents either with the burnout air or downstream between the air preheater and the electrostatic precipitator. Three host sites have been selected representing the three major firing configurations currently employed. These are tangential (Hennepin, Illinois site), wall-fired (Bartonville, Illinois site), and cyclone (Springfield, Illinois site). Boiler sizes are 80, 117, and 40 megawatts, respectively. A 48 month program is proposed with a 60 month period required if phase overlay is omitted. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. The sponsors have proposed to contribute 50 percent of the project cost. Project Cost: Not disclosed

GASIFICATION ENVIRONMENTAL STUDIES - University of North Dakota Energy Research Center (C-390) The University of North Dakota Energy Research Center (UNDERC) has onsite an oxygen-blown fixed-bed gasifier that is capable of operating on lignite. The slagging fixed-bed gasifier (SFBG) pilot plant provides a large-scale source of lignite-derived effluents for subsequent characterization and treatment studies. The ability to produce "representative samples" for treatment testing from lignite is critical, because lignite will be the feedstock for a number of the first-generation synfuels plants. The goals of work at UNDERC are to develop public environmental data of effluent characteristics needed to satisfy permitting and siting requirements, and proof of concept on advanced control technologies for fixed-bed gasification of lignite. The principal area of uncertainty where research activities should be focused centers around the cooling tower. The most cost-effective approach Is to feed water directly from the extraction/stripping units to the cooling tower, without intermediate biological treatment. This wastewater, however, contains several thousand milligrams per liter of COD—after phenolics and other organics are reduced to low levels. The behavior of these previously uncharacterized species in a cooling tower with respect to drift, further biological activity, and associated fouling, and their effects on the solubility of dissolved solids is unknown. To establish the effect of various degrees of pretreatment, UNDERC has installed wastewater treatment process development units which simulate commercially available technology. During the first phase of the program, wastewater was processed by solvent extraction and ammonia stripping before being fed to a cooling tower to simulate the processes to be employed at the Great Plains Gasification Plant (GPGP), In the second phase, wastewater pretreatment was enhanced by the inclusion of activated sludge as processing, followed by granulated activated carbon (GAC) adsorption, in addition to extraction and stripping, before feeding the cooling tower. Phase II testing was intended to demonstrate that aqueous gasifier effluent can be used successfully as makeup to a cooling tower, provided adequate pretreatment has been performed. Results from Phase I testing indicated that minimally treated gasifier wastewater used without corrosion inhibitor and biocide addition is not a suitable feed for a cooling tower operating at 10 cycles of concentration. After operating the tower at 10 cycles for 50 days, severe fouling was noted on heat exchanger surfaces. Corrosion rates of 10 to 15 MPY were noted for carbon steel, as well as severe pitting (4 to 6 mils deep in the 50 day test). Results from exhaust sampling indicate a significant portion of the phenol and ammonia In the makeup water (91 and 81 percent, respectively) were stripped into the atmosphere. Twenty-one percent of the methanol was also stripped.

4-65 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

Phase It biotreatment of the pretreated (solvent extracted, ammonia stripped) gasifier liquid has been successful. The pilot activated sludge unit had a mean BOD reduction of 96 percent and the system displayed good resiliency. Stripped gas liquor further treated by activated sludge (AS) and granular activated carbon (GAC) was used as cooling tower feed in Phase II. Following these pretreatment steps, this Mater had a very low organic loading of approximately 150 milligrams per liter of COD. The Phase II test was terminated April 30, 1994, after a 39 day run. Excessive corrosion rates and flow restrictions were the primary factors in the decision to stop the proposed 50 day test. The corrosion and fouling problems experienced in the Phase II test provide evidence that AS and GAC treated liquor cannot be used as cooling tower makeup without the addition of an appropriate corrosion inhibitor. A 50 day Phase Ill cooling tower test was performed using AS and GAC treated liquor from slagging gasification with addition of a zinc-chronate corrosion inhibitor and a polyphosphonate solids dispersant. Using zinc and chromate dosages of 10 ppm in the cooling water, carbon steel corrosion decreased to approximately 25 percent of the rates observed in the Phase II system without corrosion inhibitor. At temperatures of 800 to 90°F, carbon steel corrosion did not exceed 7 MPY. Corrosion rates less than I MPY had originally been anticipated with the inhibitor dosages used in this system. However, analysis of zinc, chromium, and phosphate levels in the cooling water and in deposits showed evidence of polyphosphonate degradation. Because of this degradation, polyphosphonates were not able to stabilize zinc ion in the alkaline cooling water or effectively disperse solids. In order to determine water-specific effects of cooling tower wastewater reuse, a Phase IV test was performed using stripped gas liquor (SQL) generated at the Great Plains commercial lignite gasification plant in Beulah, North Dakota. This water had been treated by processes similar to those used in pre-treatment of the slagging gasifier wastewater used as makeup for the previous Phase I test. The GPGP SGL contained phenol, fatty acid, and ammonia concentrations of 20 ppm, 700 ppm, and 1,300 ppm, respectively. In comparison, the SQL makeup used in Phase I contained roughly 150 ppm phenol, 300 ppm fatty acids, and 500 ppm ammonia. The average rate of heat transfer coefficient loss for carbon steel heat exchanger tubes was four times lower in Phase IV using GPGP SQL than in Phase I using slagging gasification SQL. Deposit accumulation in these tubes was also significantly slower; 1.0 gram deposit per square meter per day in Phase IV as compared to 9.5 grains deposit per square meter per day in Phase I. The microbial population maintained in the the Phase IV system (3 x tOO million per milliliter) was two orders of magnitude higher than that maintained during Phase I; this was found to be directly attributable to the high concentrations of biodegradable organic acids in GPGP SQL and the presence of sufficient phosphate for bacterial growth. Carbon steel corrosion in the Phase IV system was less severe than in Phase I. Rates varied from 5 to 12 mpy, and corrosion was primarily the result of localized under-deposit attack. The fraction of phenol air-stripped into the atmosphere was similar in Phases I and IV. In both cases, 90 percent of the phenol entering the system was detected in the exhaust.

Project Cost: $1.6 million for annual research Year 2 (April 1984-April 1985) $0.9 million for annual research Year 3 (April 1985-June 1986) $0.16 milion for annual research Year 4 (April 1986-April 1987)

4-66 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (ContinuecO

GECAS-D PROJECT --(See 10CC Simulation) GFI{ DIRECT LIQUEFACTION PROJECT - West German Federal Ministry for Research and Technology, Saarbergwerke AG, and Ofic Gesellschaft fur Kohieverflussigung MbH (C-400) Until 1984 Gfl{ Gesellschaft fur Kohlevertlussigung MbH, a subsidiary of Saarbergwerke AG, has dealt with the single stage, severe hydrogenation, which is still uneconomic due to high hydrogen consumption and high pressure. Furthermore only expensive low ash-coals can be processed. For this reason since 1984 GfK has conceived a unique process called PYROSOL which can produce liquid fuels at prices competitive to crude oil of $30 per barrel. The PYROSOL process is two-stage, comprising a mild hydrogenation in the first stage followed by hydropyrolysis of the residue in a second stage. At present, activities are directed to install a hydropyrolizer in the 6 tonnes per day liquefaction unit. Data to plan a large demonstration plant are expected to be available by the end of 1989. Project Cost: Not disclosed GREAT PLAINS GASIFICATION PROJECT — United States Department of Energy (C-420) Initial design work on a coal gasification plant located near Beulah in Mercer County, North Dakota commenced in 1973. In 1975, ANG Coal Gasification Company (a subsidiary of American Natural Resources Company) was formed to construct and operate the facility and the first of many applications were filed with the Federal Power Commission (now FERC). The original plans called for a 250 million cubic feet per day plant to be constructed by late 1981. However, problems in financing the plant delayed the project and in 1976 the plant size was reduced to 125 million cubic feet per day. A partnership named Great Plains Gasification Associates was formed by affiliates of American Natural Resources, Peoples Gas (now MidCon Corporation) Tenneco Inc., Transco Companies Inc. (now Transco Energy Company) and Columbia Gas Systems, Inc. Under the terms of the partnership agreement, Great Plains would own the facilities, ANG would act as project administrator, and the pipeline affiliates of the partners would purchase the gas. In January 1980, FERC issued an order approving the project. However, the United States Court of Appeals overturned the FERC decision. In January 1981, the project was restructured as a non-jurisdictional project with the SNG sold on an unregulated basis. In April 1981, an agreement was reached whereby the gas would be sold under a formula that would escalate quarterly according to increases in the Producer Price Index and the price of No. 2 Fuel Oil, with limits placed on the formula by the price of other competing fuels. During these negotiations, Columbia Gas withdrew from the project. On May 13, 1982, it was announced that a subsidiary of Pacific Lighting Corporation had acquired a 10 percent interest in the partnership; 7.5 percent from ANR's interest and 2.5 percent from Transco. Full scale construction did not commence until August 6, 1981 when DOE announced the approval of a $2.02 billion conditional commitment to guarantee loans for the project. This commitment was sufficient to cover the debt portion of the gasification plant, Great Plains' share of the coal mine associated with the plant, an SNG pipeline to connect the plant to the interstate natural gas system, and a contingency for overruns. Final approval of the loan guarantee was received on January 29, 1982. The project sponsors were generally committed to providing one dollar of funding for each three dollars received under the loan guarantee up to a maximum of $740 million of equity funds. The project, produces an average of 125 million cubic feet per day (based on a 91 percent onstream factor) of high BTU pipeline quality synthetic natural gas, 93 tons per thy of ammonia, 88 tons per day of sulfur, 200 million cubic feet per thy of carbon dioxide, potentially for enhanced oil recovery, And other miscellaneous by-products including tar, oil, phenols, and naphtha to be used as fuels. Approximately 14,000 tons per thy of North Dakota lignite is required as feedstock. Since August 1, 1985 when the sponsors withdrew from the project and defaulted on the loan, DOE has been operating the plant under a contract with the ANG Coal Gasification Company. The plant has successfully operated throughout this period and earned revenues in excess of operating costs. For the period January through June 1986 the plant produced an average of 137.5 million standard cubic feet per day of high BTU substitute natural gas (100 percent onstream factor). The gas is marketed through a 34 mile long pipeline connecting the plant with the Northern Border pipeline running into the eastern Unite States. In parallel with the above events, DOE/DOJ filed suit in the United States District Court in the District of North Dakota (Southwestern Division) seeking validation of the gas purchase agreements and approval to proceed with foreclosure. On January 14, 1986 the North Dakota Court found:

4-67 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

• That state law is not applicable and that plaintiffs (DOE/DOJ) are entitled to a summary judgment for foreclosure. A foreclosure sale was held on June 30, 1986, and DOE obtained legal title to the plant and its assets. • The defendant pipeline companies are liable to the plantiffs (DOE/DOJ) for the difference between the contract price and the market value price and granted the notion for summary judgment determining the validity of the gas purchase contract. The pipeline companies have paid all past due amounts. DOE is continuing to evaluate various options for disposition of the plant. Project Cost: $2.1 billion GREEK LIGNITE GASIFICATION COMPLEX -- Nitrogenous Fertilizers Industry SA (AEVAL) (C-430) AEVAL, a Greek state-owned company, is planning to replace its lignite gasification and ammonia plants at its existing fertilizer complex, near Ptolemais, Greece. Following a 5,000 tonne full-scale industrial test of Greek xylitic type lignite conducted by TECHNOEXPORT, a Czech state-owned company, at an existing gasification plant near Usti Czechoslovakia, TECUNOEXPORT has submitted an offer for the gas production part of the complex. The technology offered is a fixed-bed gasification technology. AEVAL has engaged Lummus Crest Inc. (USA) as a technical and economic consultant in order to conduct a detailed feasibility study and evaluate the TECHNOEXPORT proposal. After the completion of the feasibility study, AEVAL has decided to proceed with the project on the condition that a financial grant will be obtained under Greece's investment incentive laws and has applied to the competent authorities for its approval. The final processing scheme selected would produce 380,000 metric tons per year of ammonia of which about 70,000 metric tons per year would be sold to a nearby customer and the remaining would be used in the existing fertilizer facilities and in a new 1,000 metric tons per day urea plant. Project Cost: $480 million HUENXE COT COAL GASIFICATION PILOT PLANT -- Carbon Gas Technology (COT) GmbH, a joint venture of Deutsche Babcock AG, Gelsenberg AG, and Manfred Nemitz Industrieverwaltung (C-472) COT was established in 1977, with the goal of developing a coal gasification process to the point of commercial maturity and economic utilization. The COT coal gasification concept consists of the combination of two principal processes of coal gasification in a specially developed reactor. The characteristic feature of the COT Process is the integrated fluidized bed and dust gasification stages. The coal is fed into the fluidization zone of the reactor, and fluidized and gasified by the addition of the gasification media (steam and oxygen) through side nozzles. The unconverted fines exit the reactor with the 1,000°C hot product gas and are separated in a downstream cyclone as coke dust. The hot coke dust is cooled and stored in bunkers. The coke dust is then fed to the dust gasification stage at the top of the reactor and gasified with steam and oxygen in a cooled combustion chamber. The product gas exiting the combustor at high speed is directed to the fluid bed. The ash melted in the combustor flows down into the fluidized bed and is drawn off through the slag outlet. The coupling of a fluidized bed with entrained flow gasification under pressure leads to a higher specific throughput capacity with simultaneously higher efficiency. The production of tar-free product gas at the relatively low temperature of the reactor leads to various simplifications in gas purification. The overall program for the development of the COT process consists of three stages. Step 1: (1978-1981)--Plan- ning, construction, and management of checkout tests of key components of the technical process. Step 2: (1981- 1986)—Planning, construction and operation of a 4 tons per hour operating system. Step 3—Demonstration of the process at commercial scale. For the component test program, in 1979 a cold now pressurized fluid bed facility and one for an atmospheric pressure dust gasification stage were erected. In 1981, planning began for building a 4 ton per hour test facility for a multi-stage COT gasification process. The process design was agreed to in September 1982 and construction of the facility was completed on schedule in mid-1983. The component test facility and the 4 tons per hour pilot plant were erected at the site of the OP Ruhr refinery at Huenxe. The test work comprises a conceptual test program to the end of 1986. After bringing the facility on line and operating the combined fluidized bed with entrained now gasification, the complete working of the test facility with a reference coal will be carried out over the entire operating range. In the following test phases the suitability of different feed coals will be

4-58 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

checked out. In connection with the systematic test program, gasification tests with client coals for specific applications are planned. Project Cost: Not disclosed IGCC EXPERIMENTAL SIMULATION - General Electric Company (C-480) GE is using a 24 TPD, 20 atmosphere coal gasification facility to provide an accurate simulation of an integrated gasification, combined cycle (IGCC) power generation system. The plant, located at GE's Research and Development Center at Schenectady, New York, was first operated in 1976. The facility incorporates a fixed bed gasifier developed by GE, to study the gasification of highly caking fuels at reduced steam/air ratios under clinkering conditions. in addition complete fuel gas physical and chemical clean-up equipment is included, and a turbine simulator is used to evaluate combustion characteristics. The entire system is fully operational and has been evaluated over a wide spectrum of operating conditions and with a range of coal types. A test series was completed in which the gasification and cleanup system supplied clean coal- derived fuel to a turbine simulator operating at advanced gas turbine firing conditions of 2,600"!' turbine inlet temperature and a pressure ratio 12 to 1. A $9.3 million DOE program is currently underway to develop the technology base needed to ensure compatibility with the constraints imposed by end-use applications. These constraints include dynamic load response to variations in end-use demand, and compliance with environmental regulations. The first two years of this program resulted in significant achievements in these areas. Operation with sulfur capture in excess of 90 percent was maintained throughout a wide range of system conditions, and during major component and system steady state and transient tests. System liquid effluent was characterized, and the parametric influence of operating conditions on effluent now rate and composition was examined. Concepts for further improvement in emissions performance were ev aluated at a laboratory scale and facility based experiments were planned. Verification of the component models by means of realistic tests on representative hardware has provided verified dynamic models of components of an IGCC power generation system. Demonstration of operation of an IGCC power plant in a typical utility environment was accomplished in 1983. fuel plant was integrated with a software simulation of combined cycle power generation equipment. TheThe combination was linked by means of controls logic typical of a full scale IGCC plant. The resultant power plant simulation was subjected to imposed transient demands, contingencies and emergencies of the type that could be encountered in a. utility application.

niv ate ommpuz:ea Wee Oemonstration?j&dfl Project Cost: $9.3 million

INTEGRATED TWO-STAGE LIQUEFACTION - Cities Service/Lummus and United States Department of Energy (C-490) A program has been initiated between DOE and Cities Service/Lummus for study on the chemistry, mechanisms, and process conditions for the expanded bed upgrading of coal extracts. This study will be combined with the exploratory development of an Integrated Two-Stage Liquefaction (ML) process. No effect of solvent boiling (500-850°J to 740-850°F) was noted for 850°F+ conversion at a 780°F operating temperature. The range was improved with a heavier boiling solvent. The thermal effect upon 850°F+ SRC-I coal extract conversiondenitrogenation using a calcined extrudate (no metals loading) is less than would have been expected from petroleum residuum considerations. A substantial portion of the 850°F+ conversion of coal extracts is catalytic in nature. The first phase of a parametric study on total reactor pressure, space velocity, and temperature has been completed. The high content of SRC-! coal extracts obtained from the Pyro and Lafayette mines has essentially no effect on thechloride LC- Fining hydroprocessing. The influence of diffusion on catalyst performance is being measured by comparing the results from three different sized extrudates. In the Integrated Two-Stage Liquefaction process, the non-catalytic short contact time (5Cr) coal dissolution and C- E Lummus antisolvent deashing (ASDA) have been successfully combined. Using Indiana V coal, this portion of the program has demonstrated the following results: the distillate (C5-850 product contains less than 0.2 percent nitrogen and 0.2 percent sulfur; overall distillate yield is 3 barrels per ton of0y) moisture free coal; the LC-Finer catalyst activity has been maintained for over 1300 pounds of 850°F+ feed per

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(Continued)

pound of catalyst with a maximum reactor temperature of 780°F; the SCT reaction is in solvent balance and achieves over 90 percent conversion of MAP coal with a chemical hydrogen consumption of less than one percent; the heavy oil product from LC-Pining is an excellent hydrogen donor for the SCT reaction. C-E Lummus and DOE have signed a $10.31 million contract to extend the work on ITSL for an additional two years beginning July 1, 1992. Cities Service will assume an expanded role for data analysis, correlations and report writing from the iTSL pilot unit. The new contract will allow additional coals (Including Western coals and cleaned Eastern coals) to be tested in the 1/3 tons per day PDU. Reäycllng hydrogenated solvent from the upgrading unit together with liquefying coal at 800°F and I to 5 minutes In the first stage results in essentially no hydrogen being injected into the liquefier when processing Illinois No. 6 coal. The solvent is hydrogenated while the syncrude is being upgraded in the second stage. As with Indiana No. 5 coal, about 3.2 barrels of naphtha and middle distillate are produced per ton of MAP coal containing less than 0.2 percent nitrogen, 0.1 percent sulfur, and 0.5 percent oxygen. A year-long run in the PDIJ processing Illinois No. 6 coal has clearly demonstrated that the catalyst will be an insignificant part of the cost of producing coal liquids. Each pound of catalyst had been exposed to 2,000 pounds of coal extract. Catalyst deactivation is circumvented by lower temperatures and higher solvent quality. Run 3LCP9 was continued for eight months using a modified flowscheme wherein the deasher was placed downstream of the LC-Finer. The conversion activity of the extract made from Illinois No. 6 coal declined at the same rate that had been observed earlier in the run with the deasher upstream of the LC-Finer. The hydrogenation rate was unaffected by the ashy feed. The overall distillate yield, however, was higher than for the standard flowseheme because of a reduced extract loss in the deasher underflow. The deashing performance was superior to the standard flowscheme due to the improved fluidity or the deasher feed. At the end of this subtask using a modified flowscheme, the SCT reactor was operated at (a) 1,000 psig outlet pressure and (b) longer residence time and lower temperature. The low pressure had no effect on operability and yields; the longer residence time yielded more gaseous products and the extract product contained less hydrogen at slightly higher conversion to quinoline solubles. A Wyodak sub-bituminous coal was then processed in the P1)1) at C-E Lummus, New Brunswick, New Jersey. The integrated operation with Wyodak coal achieved 90 percent conversion to quinoline solubles. Hydrogen-transfer from molecular hydrogen was essentially zero, while the recycle solvent contributed almost twice the hydrogen that had been transferred during SCT runs with bituminous coals. The extract is reactive, requiring LC-Finer temperatures 500 to 70°? lower than for bituminous coals. The overall distillate (C4-850°P) yield was 2.8 barrels per ton MAP coal at a chemical hydrogen consumption of 4.2 pounds per 100 pounds MAP coal. Several preliminary conclusions may be obtained from a comparison of Wyodak sub-bituminous coal versus Illinois No. 6 bituminous coal: 1. Wyodak coal requires less hydrogen consumption and has a higher hydrogen utilization efficiency. 2. Wyodak extract is a more reactive feed to LC-Fining—can attain a high 850 0F+ conversion at the same space velocity and a lower temperature. 3. For Wyodak operation, coking of ASDA underflow appears to be an effective way of increasing liquid product yields. 4. For a fixed product rate, Wyodak requires 11 percent more coal if coking is used and 33 percent more if it is not. The last programs in these series of contracts were directed toward reducing the capital cost of an ITSL commercial plant. The SCT section was operated at 500 psig with no reduction in coal conversion or change in yield structure. This demonstrated that the recycle solvent provides all the hydrogen required for coal dissolution, which can henceforth be accomplished at low pressure. The LC-Fining section was then operated at a three-fold increase in space velocity. Excellent 850 0+17 recycle solvent was produced. The impact of this development is that the volume of the second stage expanded bed reactors can be reduced by a factor of at least three with no adverse effect on solvent quality, resulting in a significant capital reduction. The -9500-If LC-Fining product was then hydrogenated/hydrocracked in a conventional fixed bed reactor to produce a -650°? net product with less than 100 ppm sulfur plus nitrogen. The unconverted 650 0i-F feed to the fixed bed unit became the distillate portion of the SCT recycle solvent. However, before recycling, this stream is suitable as the antisolvent in the deashing step. This reduces capital and operating costs further, by eliminating all the distillation equipment previously needed for recovery of antisolvent and allows the settler to be operated at atmospheric pressure.

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The final program of this development was a bench deashing study, which showed that upflow velocity could be substantially increased while maintaining effective deashing. This will reduce the size of the settler. Project Cost: $24.2 million

JAPANESE BITUMINOUS COAL LIQUEFACTION PROJECT - New Energy Development Organization (NEDO) (C-505) Basic research on coal liquefaction was started in Japan when the Sunshine project was inaugurated in 1974, just after the first oil crisis in 1973. NEDO assumed the responsibility for development and commercialization of coal liquefaction and gasification technology. NEDO plans a continuing high level of investment for coat liquefaction R&D, involving two large pilot plants. A 50 tons per day brown coal liquefaction plant is under construction in Australia, and a 250 tons per day bituminous coal liquefaction plant is planned in Japan. The pilot plant in Australia is described in the project entitled "Victoria Brown Coal Liquefaction Project." The properties of brown coal and bituminous coal are so different that different processes must be developed for each to achieve optimal utilization. Therefore, NEDO has also been developing a process to liquefy sub-bituminous and low grade bituminous coals. NEDO had been operating three process development units utilizing three different concepts for bituminous coal liquefaction: solvent extraction, direct liquefaction, and solvolysis liquefaction. These three processes have been integrated into a single new process and NEDO has intended to construct a 250 tons per day pilot plant. In the proposed pilot plant, bituminous coal will be liquefied in the presence of activated iron catalysts. Synthetic iron sulfide or iron dust will be used as catalysts. The heavy fraction (-540°C) from the vacuum tower will be hydrotreated at about 350°C and 100-150 atm in the presence of catalysts to produce hydrotreated solvent for recycle. Consequently, the major products will be light oil. Residue-containing ash will be separated by vacuum distillation followed by steam stripping. Basic design of the new pilot plant has started. It is expected that the pilot plant will start operation in 1990. The total cost, including operations, is expected to be $400 million.

Project Cost: $400 million, not including the three existing PDU

KANSK-ACHINSK BASIN COAL LIQUEFACTION PILOT PLANTS -- Union of Soviet Socialist Republics (C-495) The Soviet Union is building a large coal-based project referred to as the Kansk-Achlnsk Fuel and Energy Complex (KATEK). The project consists of a very large open pit mine (the Berezovskiy-1 mine), a 6,400 megawatt power plant, and a coal liquefaction facility. Additionally, the small town of Sharypovo is being converted into a city with new schools, stores, housing, and transportation. A pilot plant referred to as an ST-75 installation is being built at KATE to test a catalytic hydrogenation process. Construction of the unit began in 1982. Start up of the unit was originally planned for 1984, but has been postponed to 1985 due to equipment design and delivery delays. Preliminary tests indicate that five tons of Kansk-Achinsk brown coal can produce one ton of liquid products at a cost that is 25 to 30 percent less than products that are refined from crude oil from remote Siberian regions. Additionally, a second unit referred to as the ETKh-175 is being built to test rapid pyrolysis of brown coal from the Borodinskoye deposit. The test unit will have a capacity of 175 tons of coal per hour. The process will produce coke, tar, and combustible gases. Construction of the unit was completed in December 1983, and testing using inert materials began in the Spring of 1984. However, a facility to convert .the coal tar into fuels and chemicals has not been built. Therefore, the tar will be burned as fuel in the adjacent utility. A third experimental coal liquefaction unit, ST-5, is under construction at the Belkovskaya mine of the Novomoskovsk Coal Association. The unit is intended to demonstrate a relatively low pressure hydrogenation process that reportedly operates at approximately 1,500 psig and 400 0C. A catalyst is used in the process to enhance the hydrogenation of coal into high octane gasoline. The liquid and solid are separated, and the solids are combusted to recover the catalyst. Startup of ST-5 was to occur in 1984. Project Cost: Not disclosed

KEYSTONE PROJECT - The Signal Companies (C-Sb) In response to the United States Synthetic Fuels Corporation's fourth general solicitation that ended June 29, 1984, the Signal Companies proposed a coal-to--fuel gas project. The proposed project would produce 128 million standard

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(Continued)

cubic feet per day of fuel gas fro;n 2,125 tons per day of high sulfur, caking bituminous western Pennsylvania coal. This fuel gas would be used in an adjacent combined cycle power plant to produce approximately 190 kilowatts of electricity. To be located near Johnstown, Pennsylvania, the project would use the KRW Energy System Inc., fluid bed coal gasification technology. Construction was originally scheduled to begin in November 1985 with initial production commencing in July 1988. Loan and price guarantees were requested from the SFC. On January 15, 1985 the project was determined to be a "qualified project" under the terms of the solicitation. On July 10, 1985 the project was also submitted in response to the SEC's solicitation for Eastern bituminous coal gasification projects. The SFC determined that Keystone was a qualified project under the solicitation. However, the SEC was abolished by Congress on December 19, 1985 before financial assistance could be awarded to the project. Since that time, Signal has been evaluating options for restructuring the project. A modified project, the Appalacian Project, was submitted to DOE's Clean Coal Technology Program, and selected for funding. Project Cost: Not Disclosed K-FUEL COMMERCIAL FACILITY -- Energy Brothers Inc. (C-518) Energy Brothers, licensor of the K-Fuel process, is building a plant located next to the Fort Union Mine near Gillette, Wyoming. The plant will use the process invented by Edward Koppelman and developed further by SRI International. In the K-Fuel process, low-grade coal or peat is dried and mildly pyrolyzed in two coupled reactors that operate at elevated temperatures and at a pressure of 800 psi. The process produces a pelletized coal, and by- product water and fuel gas. K-Fuel pellets contain 60 percent more energy (approximately 27 million BTU per ton) and 40 percent less sulfur than the raw coal. The fuel gas from the process is utilized on site to provide the needed heat for the process. The proposed facility will utilize 4 modules each capable of producing 350,000 tons per year of K-Fuel. Wisconsin Power and Light has agreed to a 10-year purchase agreement for "a substantial portion" of the output of the plant. The K-Fuel will be tested at Wisconsin Power and Light's Rock River generating station near Beloit in south-central Wisconsin. For the test Wisconsin Power and Light will purchase the fuel at the cost of production, which has yet to be determined but is estimated to be over $30 per ton. If the test is successful, Wisconsin Power and Light has the option to invest in the process. The utility is expected to begin taking shipments of K-Fuel in May 1986. Wisconsin Power and Light is interested in burning K-Fuel to eliminate the need to install expensive equipment to reduce sulfur emissions from the power plant. The upgraded coal is also less expensive to ship and store due to its improved heating value.

Project Cost: $90 Million

KILnGAS PROJECT - Allis-Chalmers, KILnOAS R & D, Inc., State of Illinois, United States Department of Energy, Electric Utility participants are: Central Illinois Light Company, Electric Power Research Institute, Illinois Power Company, Monongahela Power Company, Ohio Edison Company, The Potomac Edison Company, Union Electric Company, West Penn Power Company (C-520) The KILnGAS process is based on Allis-Chalmer's extensive commercial experience in rotary kiln, high temperature minerals processing. A 600 tons per day KILnGAS Commercial Module (KCM) has been installed near East Alton, Illinois adjacent to Illinois Power's Wood River Power Station. The plant provides low-BTU (160 BTU per standard cubic foot) gas to the Wood River station. Gilbert/Commonwealth Associates, Inc., was the architect-engineer. Construction management was provided by J.A. Jones Construction. Scientific Design contributed to the process design. The KCM includes a pressurized gasifier which is a 170 foot long by 12 foot diameer rotary kiln. Coal, transported through the gasifier by inclination and rotation of the kiln, is progressively dried, pre-heated, and devolatilized by counterfiowing hot gases. Air and steam is injected through a unique system of ports located along the length of the gasifier and reacts chemically with carbon in the hot coal to form hydrogen and carbon monoxide, the primary combustibles in low-BTU gas. The gas, which leaves by both the feed and discharge end of the gasifier, is cooled and passed through a sulfur removal process. Particulates and tars, which are rich in carbon, are separated from the gas and recycled to the gasifier to improve carbon conversion efficiency. The objectives of the KILnOAS program are: (1) demonstrate system performance in a utility environment; (2) obtain data to confirm process design; (3) utilize KCM operating data to forecast commercial gas generation costs; and (4) establish a data base to proceed with design of commercial plants in the 2,000 to 5,000 tons per day range. The KCM, for which construction was completed in mid-1983, is used to support these objectives.

4-72 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

Spanning a period from mid-1983 through late 1985, the KCM has undergone performance testing, demonstration runs, and is currently in the first phase of a Reliability, Availability, and Maintainability Program, RAM I. The more significant accomplishments to date are: (a) high-sulfur Illinois coal has been successfully gasified; (b) an Illinois Power Company boiler has been successfully fired from 11CM-generated gas; (c) carbon conversion efficiencies exceeding 90 percent have been achieved; (d) an average of 90 percent total sulfur removal has been accomplished; (e) a wide range of performance, reliability, availability and maintainability improvements has been designed, installed, commissioned, and is undergoing evaluation testing as part of RAM I; (f) excellent winter startup and cold weather operating experience under RAM 1 has been gained for commercial design use. The RAM I program concluded in April 1986. A second Phase, RAM II, will extend the program through mid-1987. Total funding for the program, through Ram I is shown as follows. Funding of $14.91 million for RAM I1 has been appropriated by Congress to match continuing support from electric utilities and the State of Illinois; federal funds are administered through the United States Department of Energy. Funding through RAM 1: Electrical Utility $ 42.0 million State of Illinois 28.3 million Allis-Chalmers 115.3 million United States Department of Energy 7.4 million EPRI (testing only) 5.8 million Total $204.3 million KLOCKNER COAL GASIFIER - CRA (Australia), Klockner Kohlegas, West German Federal Government (C-535) A 850,000 tonnes per year commercial plant using the Klockner coal gasification process is under construction at Bremen, West Germany. Approximately 1.7 billion cubic meters of gas is the anticipated product. Start-up Is scheduled for 1985. A currently-operating pilot plant has reported up to 90 percent lower sulfur emissions. The project is receiving $80 million from the West German government. When operational, the plant will be the second large-scale gasification plant in Germany (see Rhelnbraun I-ITW Project for details of the larger facility). The Klockner Kohiegas molten iron bath technology has been proposed for the Penn/Sharon/Klockner project in the United States.

Project Cost: $325 million

KOHLE IRON REDUCTION PROCESS DEMONSTRATION PROJECT -- Weirton Steel Corporation and United States Department of Energy (D-543) This project will involve a demonstration of the Kohle Reduction process which was developed by Korf Engineering (a Federal Republic of Germany company). The process replaces the two-step coke oven/blast furnace approach to producing pig iron from iron ore and metallurgical coal with an integrated two component oxygen-blown blast furnace system capable of operation on a variety of United States coals. The system consists of an upper "reduction shaft" and a lower "melter-gasifier" component, Iron ore, along with an appropriate flux (e.g., limestone), is fed into the top of the reduction shaft where it is reduced to sponge iron by the off-gas from the lower melter-gasifier section. The lower section is an oxygen-blown fluidized bed coal gasifier. In this section the sponge Iron is melted and the resulting pig iron and slag are separated and tapped as in a blast furnace. The low/medium-BTU, sulfur-tree off-gases from the process (sulfur is captured by the limestone and remains in the slag) are scrubbed to remove particulates and are available for site use. The Kohle Reduction process has been tested in a 66,000 tons per year pilot plant using a wide range of coals and iron ores. The proposed project calls for the design and construction of a 330,000 tons (iron) per year demonstration plant at the Weirton Steel plant in Weirton, West Virginia. The plant will operate on a variety of United States feedstocks. A plant of the same technology and size in South Africa is to be completed in late 1987. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Weirton Steel intends to fund nearly 65 percent of the cost of the project. Project Cost: Not disclosed

4-73 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

KRW ENERGY SYSTEMS INC. ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERATION - Kellogg Rust Inc., United States Department of Energy, and Westinghouse Electric (C-no) In April 1984 Westinghouse sold controlling interest in the Synthetic Fuels Division and its coal gasification technology to Kellogg Rust Inc.; the new name is KRW Energy Systems Inc. DOE awarded a $27 million contract to KRW Energy Systems to fund continued development of the KRW coal gasifier. KEW will also contribute $6.7 million to the 32-month effort, which will be conducted largely at the Waltz Mill test facility southeast of Pittsburgh, Pennsylvania. The present program will focus on linking the 25 tons per day gasifier to an advanced hot gas cleanup system for applications to integrated coal gasification combined cycle power generation. The hot gas cleanup technology to be tested is a process developed at DOE's Morgantown Energy Technology Center using regenerable zinc ferrite to absorb hydrogen sulfide. Other components of the program include a study of multiple injection ports for the gasifier and in-bed sulfur removal by injecting limestone. The KRW coal gasification pilot plant, located at the Waltz Mill Site near Pittsburgh, Pennsylvania has been operated since 1975 and has accumulated more than 10,000 hours of hot operation with a broad range of coals. The range of coal types includes highly caking eastern bituminous, western subbituminous, and lignites, high ash and low ash, high moisture and low moisture. The pilot plant utilizes a single stage fluidized bed gasifier with ash agglomeration and hot fines recycle. The pilot gasifier is operated at temperatures between 1,550°? and 1,950°F and pressures between 130 psig and 230 pslg, with air feed to produce low-BTU gas and oxygen feed to produce medium-BTU gas. Pilot plant coal capacity ranges between 20 and 35 tons per day, depending on coal type. The pilot plant has been integrated with prototype combustion turbine test passages, and tests were conducted with coal gases covering a broad range of heating values. In 1983, successful tests were conducted to demonstrate hot fines recycle. They showed a 23 percent increase in carbon conversion for Wyoming Sub-C coal (8 percent for Pittsburgh No. 8), and a 38 percent decrease in oxygen consumption (26 percent for Pittsburgh No. 8). A commercial gasifier-size cold flow fluidized bed scale-up facility began operation in 1981, the purpose being to develop a data base sufficient to reduce risks associated with scale-up to acceptable levels. Several commercial demonstration projects are currently being evaluated for application of the KRW coal gasification system to various industrial and utility applications. Included is the Appalacian Project which is to be located near Cairnbrook, Pennsylvania involving a coal gasification combined cycle facility. The first commerical-scale operation of KRW gasification will take place in the Peoples Republic of China at Fularji in northeast China. (See the Fularji Low-BTU Gasifier project). Project Cost: Not disclosed

LAPORTE LIQUID PHASE METHANOL SYNTHESIS - Air Products & Chemicals, Chem Systems Inc., Electric Power Research Institute, Fluor Engineers and Constructors, and United States Department of Energy (C-550) Air Products is testing a 5 tons per day PDU located near LaPorte, Texas. The unit is being run as part of a program sponsored by the DOE and will be used to evaluate the liquid phase methanol synthesis technology developed by Chem Systems. In the process, synthesis gas is injected in the bottom of a reactor filled with light oil in which a methanol synthesis catalyst is suspended. The oil acts as a large heat sink, thus improving temperature control and allowing the use of more active catalysts and/or a more concentrated synthesis gas. Additionally, a wider range of synthesis gas compositions can be used, thereby allowing the use of low hydrogen/carbon ratio gases without the need for synthesis gas shift to produce more hydrogen. While the technology is particularly suitable to syngas derived from coal, the concept will be tested initially using hydrogen and carbon monoxide produced from natural gas. In spring 1985, the liquid phase methanol PDU located near LaPorte, Texas was started, with the initial objective of a 40 day continuous run. During the run, the LaPorte unit was operated under steady-state conditions using carbon monoxide-rich gas representative of that produced by advanced coal gasifiers. During the run, the plant achieved a production rate of up to 8 tons per day with a total production of approximately 165 tons of methanol (50,000 gallons). The plant, including the slurry pump and a specially designed pump seal system, operated very reliably during the run. Additional testing of the unit is currently underway. A 10-day test in July 1985 was conducted at higher catalyst concentrations (35 to 45 weight percent). The unit was operated with balanced gas for 1 day, and carbon monoxide-rich gas for 9 days. The PDU demonstrated excellent operability with 100 percent on-stream reliability, but catalyst activity maintenance was somewhat lower than laboratory predictions.

4-74 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

The next step is scale-up to a larger unit. TVA's facility at Muscle Shoals, Alabama, where actual synthesis gas from a Texaco gasifier could be used, Is a potential host site. Project Cost: DOE: $15.6 million Private participants: $1.8 million LFC COAL LIQUEFACTION/COGENERATION PLANT --501 International (C-557) 501 International is developing a 30.75 megawatts electric cogeneration and coal liquids production facility to be located near Colstrip, Montana. This facility is designed to utilize the Liquids from Coal (LFC) process, developed by SGI International. An LYC/cogeneration plant consists of an electric generation unit combined with LFC process equipment in one cogenerating system. According to the developers, 501's LFC process is an adaptation of existing reliable equipment and utilization of state-of-the-art technology. Compared with other coal conversion processes where high temperatures and pressures are required, the LFC process operates at low pressures and less severe thermal process conditions, some of which require only low-grade and medium-grade heat (1400 to 600°F). In the system, the electric generation unit supplIes waste heat to meet these LFC process thermal loads, while the solid waste by-products from the LFC process are used to fuel the electric generation unit. 301 has obtained a long-term (35 year) power sales agreement with Montana Power Company. The estimated project cost is $72.5 million. Drava Engineers, Inc. of Atlanta, Georgia has been selected by SO! International to perform the design and construction of the LFC Cogeneration Plant. Proposals will soon be solicited for major equipment components leading to placement of orders in the fall of 1986. Site work is scheduled to commence in fall-1986 with the entire facility complete by late-1988. Once in full operation, the facility will employ a staff of 30 to 35. Project Cost: See above

LIBIAZ COAL-TO-METHANOL PROJECT - Krupp Koppers and Polish Government (C-568) Erection of a coal gasification project in Poland is to resume in 1987. The plant is to be built by Krupp Koppers at Libiaz In southern Poland. Equipment for the plant has been stored at Llbiaz for several years. The project, which began in 1980, has been stalled due to "political difficulties" in Poland. The Llbiaz project will reportedly use approximately I million metric tons per year of high sulfur coal. Synthesis gas produced by the Koppers Totzek technology will be utilized to produce methanol. Project Cost: Approximately $300 million

LULEA MOLTEN IRON COAL GASIFICATION PILOT PLANT -- KHD Humboldt Wedag AG and Sumitomo Metal Industries, Ltd (C-580) KHD and Sumitomo have agreed to jointly build and operate a 240 tonnes per day pilot plant to test the molten iron coal gasification processes independently developed by both companies. Construction of the pilot plant was completed in Lulea, Sweden at the country's steel research center in mid-1985, with operation scheduled to last through 1987. The pilot plant will be designed for operation at pressures up to 5 atmospheres. In the process, pulverized coal and oxygen are injected into a bath of molten iron at temperatures of 1400 to 1600°C. Potential advantages of the technology include simple coal and oxygen feed controls and low carbon dioxide production. Project Cost: Not Disclosed

LU NAN AMMONIA-FROM-COAL PROJECT -- China National Technical Import Corporation (C-SB?) The China National Technical Import Corporation awarded a contract to Bechtel for consulting services on a commercial coal gasification project In the People's Republic of China. Bechtel will provide assistance in process design, design engineering, detailed engineering, procurement, construction, startup, and operator training for the installation of a Texaco gasifier at the 200 metric tons per day Lu Nan Ammonia Complex in Tengxian, Shandong Province. When completed in early 1987, the Lu Nan modification will replace an obsolete coal gasification facility with the more efficient Texaco process. Project Cost: Not Disclosed

4-75 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

MILD GASIFICATION PROCESS DEMONSTRATION UNIT -- United Coal Company and United States Department of Energy (C-622) United Coal Company (13CC) has built a Mild Gasification Process Demonstration Unit at its research center in Bristol, Virginia. The unit Is capable of processing I ton per day of coal or coal waste. Under the sponsorship of the United States Department of Energy (DOE), 13CC has developed a process that is primarily aimed at recovering the energy value contained In wastes from coal cleaning plants. To utilize this waste, UCC developed a mild gasification/coal liquid extraction process. UCC's demonstration facility became operational in October 1985 with the first coal waste test commencing In November. The unit can utilize coal preparation waste, bituminous coal, or subbituminous coal as feedstocks. A high-quality hydrocarbon liquid has been produced, along with a substantial amount of good quality char. The coal liquid can be used as a replacement for or additive to diesel, gasoline, boiler, or turbine fuels. Experimental data with both diesel and gasoline engines have shown excellent performance, using a mixture of the coal liquids and petroleum-based products. The char also has a number of applications, such as in pulverized and/or fluidized-bed industrial and utility boilers, blast furnaces, and foundry coke blending systems. The process design developed by 13CC concentrated primarily on constructing a test unit of sufficient size to obtain a reasonable quantity of liquids for test purposes. The mild gasification unit includes a 1 ton coal storage bin, four loading hoppers, four 8 inch diameter by 8 foot long tapered reactor tubes, a constant controlled furnace, four banks of condensors, four hydraulic rams for char removal, and appropriate storage containers for char and coal liquids. Since the initial start-up of the mild gasification demonstration unit, several shake-down tests have been conducted. The furnace, tapered reactor tubes, char removal and break system, electronic controls, water quench system, and flare system have each performed well. The condensing system has been modified several times to optimize liquid recovery. UCCis emphasizing this area of the plant so that the coal liquids can be separated according to their quality during the condensing phase and thus eliminate the need for distillation. United Coal Company believes that the mild gasification process unit Is sufficiently flexible to allow for tests with different coals, catalysts, steam injections, coal/residual oil cracking, waste products mixed with coal, char chlorination, etc. They expect that the forthcoming testing program will determine the commercial viability of the • process design. in addition, sufficient quantities of liquids will be produced to allow for gasoline, diesel, and turbine engine testing to prove the market acceptability of the products. The char will also be evaluated in various markets. Project Cost: Not disclosed MINING AND INDUSTRIAL FUEL GAS GROUP (MIFGA) GASIFIER - American Natural Service Company; Amerigas; Bechtel Incorporated; Black, Sivalls, Bryson; Burlington Northern; Cleveland-Cliffs Iron Company; Davy McKee Corpora- tion; Dravo Corporation; EPRI; The Manna Mining Company; Peoples Natural Gas Company; Pickands Mather & Company; Reserve Mining Company; Riley Stoker Corporation; Rocky Mountain Energy; Stone and Webster; USBM-Twin City Metallurgical Research Center; United States Department of Energy; U.S. Steel Corporation; Western Energy Company; Weyerhaeuser (C-630) The then Pellet Energy Group, United States Bureau of Mines, and DOE installed a 36 tons per day Wellman-Galusha coal gasifier at the Twin Cities Metallurgical Research Laboratory (Minn.) in March 1977. The 6' 6" diameter gasifier, supplied by Manna Mining Co., provides low-BTU fuel gas for a 12 tons per day pilot grate-kiln taconite pellet induration furnace presently operating at the Center. The Bureau of Mines' goal is to determine whether iron ore pellet firing with raw, low-BTU coal gas is technically feasible and practical, while DOE and participating companies are 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 1979 with Kentucky bituminous, Western sub-bituminous and North Dakota lignite in September-October 1979. A test with "briquetted" sub-bituminous coal fines was started October 1979, but was aborted after 10 hours. Modifications to the gasifier facility were completed and testing began in October 1980. A 30 day continuous operation with North Dakota "Indian Head" lignite was completed in November 1980. The test used approximately 1,000 tons of lignite, and included pellet testing. Ten day around-the-clock tests completed in mid-1981 included tests with North Dakota "Indian Head" lignite fines (3/4" x 1/4 11), Texas lignite, and Colorado sub-bituminous coal. "Simplex" Briquettes testing was performed in October 1981.

4-76 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continuec)i

In May 1982, Black, Sivalls & Bryson, Incorporated (BS&B) was awarded the operational contract to plan, execute, and report gasification test performance data from this small industrial fixed-bed gasification test facility. BS&B has teamed with the Particle Technology Laboratory of the University of Minnesota who is primarily responsible for gas sampling including the data acquisition and analysis. BS&B is responsible for program administration, test planning, test execution, and all documentation of program activities and test reports. BS&B has initiated an effort to identify and contact all State Agencies associated with the promotion of coal utilization within the continental United States. The objective is to solicit the widest variety of coals which are potential feedstock for industrial fixed-bed gasifiers applied within and beyond metallurgy processing throughout the United States. Major advancements have been made with the gasifier operation and gas sampling and analysis system. Quality of the data derived from testing has significantly Improved. Tar/oil from high volume bituminous coals are consistently in the range of 15 to 16 percent. The 1983 test series involved a total of 108 days of testing using 8 different coals/solid fuels. Gasification testing In 1984 has involved five different fuels with a total of 40 days testing. During the next several months, the facility will be upgraded for the 1985 test series. The 1985 test series will include fundamental studies of gas clean-up, desulfurization, and utilization of gaseous and liquid fuels derived from coal. DOE funded: $5,176,000 corresponding to 7 years of industrial coal gasification research and development. MIFGA member contributions have amounted to approximately $2,596,150. Bureau of Mines: $4,559,760.

Project Cost: $12,331,910 (spanning 7 years)

MONASH HYDROLIQUEFACTION PROJECT - BP United Kingdom Ltd. and Monash University (C-665) The Chemistry, Chemical Engineering, and Physics Departments at Monash University at Clayton, Victoria are conducting a major investigation Into hydroliquefaction of Victorian brown coal. Both batch autoclave studies and continuous hydrogenation in a bubble column and a stirred tank reactor are being conducted. BP United Kingdom Ltd. is continuing to fund for an additional two years a collaborative research project with Monash University on brown coal conversion using synthesis gas. Substantial funding for the continuous flow research has been provided by the Australian Government's National Energy Research, Development and Demonstra- tion Council. The batch autoclave work has been largely supported by the Victorian Brown Coal Council. Batch autoclave studies have established that Victorian brown coal ion-exchanged with iron- or tin-salt solutions shows enhanced activity for hydrogenation in tetralin compared with untreated coal. The Monash studies show that a mixed metal catalyst system, which Is predominantly iron-based with trace amounts of tin, displays a significant synergistic effect when compared with hydrogenation results for experiments using only or tin-based catalysts of comparable metal concentrations to the mixed metal system. Mossbauer studies are helping to understand the role of iron and tin in the early stages of reaction. Other mixed metalm systems, some with an iron base, am showing good catalytic activity. The studies have now been extended to the use of coal-derived solvents ratherre than also tetralin. The continuous bench-scale bubble-column and stirred tank reactor facility has been successfully operated at 1 to 2 liters per hour of coal slurry using tetralin as the vehicle solvent in the presence of hydrogen gas. This unit is providing data on the effects of temperature, residence time, and catalytic treatment on coal conversion and product yields, together with providing reasonable quantities of products for further studies. Coupling of the two reactors in series has been achieved and conversion studies began in coal-derived solvents other than tetralin. Mathematical modelling of the process has also proved successful.

Project Cost: $1.8 million (Australian) since commencement

MOUNTAIN FUEL COAL GASIFICATION PROCESS - Ford, Bacon & Davis; Mountain Fuel Resources, Inc.; United States Department of Energy (C-670) The sponsors constructed a process development unit for research and development on components of a high temperature, oxygen blown, entrained flow gasifier. The gasifier operates at slagging temperatures (about 2,8000?),

4_77 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1996) (Continued)

and 300 psig. The plant produces 2 million cubic feet per day of 300 BTU gas. Both radiant and convective heat exchangers are used to recover heat from the process. An $8.9 million, 52 month cost-sharing contract was awarded. Construction was completed in October and start-up tests started in November 1982. The unit has been running on coal since February 1983, conducting component and process evaluation tests. Coal variation tests, sustained operation tests, and all experimental works were completed in November 1984. The project was completed and the final report issued to DOE in April 1986. Project Cost: $8.9 million

NATIONAL COAL BOARD LIQUID SOLVENT EXTRACTION PROJECT - British Department of Energy and National Coal Board (C-690) 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 tons per day of liquids. In the process, a hot, coal-derived solvent is mixed with coal. The solvent extract is filtered to remove ash and carbon residue, followed by hydrogenation to produce a syncrude boiling below 300°C as a precursor for transport fuels and chemical feedstocks. Economic studies, supported by Badger, Ltd. have confirmed that the process can produce maximum yields of gasoline and diesel very efficiently. Work on world-wide coals has shown that it will liquefy economically most coals and lignite and can handle high ash teed stocks. The National Coal Board is proceeding with the design and construction of a 2.5 tons per day plant at the Point of Ayr site financed by the National Coal Board with support from the European Economic Community. Limited private industry and British Department of Energy support Is under discussion. Following a preliminary design phase carried out by Babcock Woodall-Duckham Ltd., construction started at the beginning of 1986.

Project Cost: 16 million British pounds (1985 prices) construction cost plus 16 million British pounds (1985 Prices) operating costs NATIONAL COAL BOARD LOW BTU GASIFICATION PROJECT - British Department of Energy and National Coal Board (C-Too) The National Coal Board is developing a fluidized bed gasifier to produce a low-BTU gas, primarily intended, combined with fluidized bed combustor for firing a gas turbine for power generation, or generally standing alone for onsite generation of gas for industrial application. Small pilot-plant studies leading to the design of a pilot/demonstration plant of a capacity of S ton per hour of coal are in hand. A joint study with the Central Electricity Generating Board led to recommendations to proceed but It is likely that work on this application will be limited to design studies over the next few years. Work is being concentrated by the NCB on developing the gasifier for the industrial market. A 0.5 ton per hour demonstration plant financed by the NCB and the European Economic Community is now being tested.

Project Cost: Construction and testing of 0.5 ton per hour plant - 2 million British pounds NATIONAL SYNFUELS PROJECT - Elgin Butler Brick Company and National Synfuels Inc. (C-705) The NSI gasifier has been installed at Elgin Butler Brick Company's brick making plant in Elgin, Texas. Production of 30 million BTU per hour low-BTU gas is expected from lignite feedstock. NSI technology uses a multi-stage gasifying process, physically segregating steps for fuels drying/devolatilizatlon, char gasification, and thermally cracking pyrolysis tars and oils. The gasifier was to start up during April 1984, with full operation anticipated by year end. However, a number of mechanical problems prevented full startup in 1984. Recent tests and operation indicate 150 BTU per standard cubic feet gas can be available. Further development Is still in progress. Project Cost: $2 million NEW MEXICO COAL PYROLYSIS PROJECT - Energy Transition Corporation (C-no) Energy Transition Corporation (ETCO) has proposed a coal pyrolysis project to be built in northwest New Mexico. The proposed plant would use Union Carbide's hydrocarbonization pyrolysis process to convert 20,000 tons per day of coal into crude oil and char. Coal for the project would be supplied by Utah International's Navajo Mine, and product char would be used at nearby electric power generation plants. A study conducted by ETCO for the New Mexico Energy Research and Development Institute indicated the plant would achieve a favorable economic return at $28.50 per barrel for product oil and $0.70 per million BTU for coal/char.

4-78 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued

Tests using the Navajo coal were conducted in a modified synthane PDU operating at hydrocarbonizat ion conditions at DOE's Pittsburgh Energy Technology Center during January 1985. ETCO is seeking additional equity partners for the project. Project Cost: $770 million NYNAS ENERGY CHEMICALS COMPLEX -- AGA, A. Johnson & Company, Superfos Group, and the Swedish Investment Bank (C-754) A group of four Danish and Swedish companies has agreed to build a coal-based ammonia plant In Sweden. The Nynas Energy Chemicals Complex (HEX) will utilize the Texaco coal gasification process to produce synthesis gas for ammonia production. Initially, the facility will produce 450,000 tonnes of ammonia per year, hot water for the Southern Stockholm district heating system, and industrial gases (oxygen, nitrogen, and argon). Also, Nynas Petroleum's refinery in Nynashamn will switch to fuel gas from NEX. Other related process options will be Implementated later. The plant is scheduled to go on stream in the Fall 1989 at a cost of $450 million (United States dollars). Participants in the project are: AGA, the Swedish industrial gas group; A. Johnson and Company, a privately-owned Swedish trading and industrial group; the state-owned Swedish Investment Bank; and the Superfos Group, Denmark's largest industrial group and one of Europe's leading producers of fertilizers. The Investment Bank and Johnson are equal partners in a new company, Nynas Kombinate AB, which will own 30 percent of NEX. AGA, whose stake in NEX will be 30 percent, will build on their own the air separation plant for the facility. Superfos, will have a 20 percent interest In the HEX with an option for an additional 10 percent, and will purchase a major portion of the plant's ammonia production under a long-term contract. The remaining 10 to 20 percent of NEX will be divided among a number of other shareholders. Project Cost: $450 million (1984 dollars) OBERHAUSEN COAL GASIFICATION PROJECT -- Ruhrkohle Oil & Gas GmbH, Ruhrchemie AG (C-755) A coal gasification pilot plant was commissioned at the Oberhausen site in April 1978, built and operated jointly by Ruhrkohle Get & Gas and Ruhrchemie. A total of 22,000 hours of operation was achieved; the longest run lasted 1,500 hours. Seventeen different coals and residues from coal liquefaction processes (described under Bottrop Project) were successfully gasified. Good yields were obtained and no technological problems occurred. The coal- based synthesis gas was fed to Ruhrchemie's oxo-synthesis plant and was judged to be well suited. Much of the pilot plant costs were funded by the West German Ministry of Science and Technology. In the meantime pilot plant operation has been terminated.

Project Cost: $10 million (pilot plant) OHIO-1 COAL CONVERSION PROJECT -- Energy Adaptors Corporation, Hoechst-Uhde Corporation, and Wentworth Brothers Incorporated (C-756) Energy Adaptors Corporation, Hoechst-Uhde Corporation, and Wentworth Brothers Incorporated a project to produce energy-grade methanol (METHYL FUEL) and anhydrous ammonia. In mid-i!

..ao V'ii4iflaLu. j im project wilt oe constructed on a site In Lawrence County in southern Ohio. This plant will use high grade sulfur coal from existing mines in the area. The proposed project will utilize a High Temperature Winkler (HTW) fluidized bed gasifier to produce raw synthesis gas. The gas is cleaned by one or more cyclones and subsequent scrubbing. The cleaned gas is then cooled in a steam generator or boiler feed water heat exchanger to recover available energy for use in the plant. Solids removed by the cyclone(s) are recycled to the gasifier to improve the carbon conversion efficiency. Carbon conversions of approximately 96+ percent are expected. The raw gas, cleaned of particulate matter, is processed in the synthesis section.

4-79 SYNTHETIC FUELS REPORT, SEPTEMBER 1986. STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986)

(Con tinueD

Construction is scheduled to start early in the third quarter of 1987, with completion and initial operation scheduled for the first quarter of 1989. This plant has been estimated to cost $260 million.

Project Cost: $260 million

PRENFLO GASIFICATION PILOT PLANT -- Gesellschaft fuer Kohle-Technologie mbH (01(T) (C-798) GIlT, of Essen, West Germany are presently operating a 48 tons per day demonstration plant and designing a 1,006 tons per day demonstration nodule for the PRENFLO process. The PRENFLO process is pressurized version of GIlT's Koppers-Totzek (1(T) entrained flow gasifier. In 1973, the parent company of GKT started experiments using a pilot KT gasifier with elevated pressure. In 1974, an agreement was signed between Shell Internationale Petroleum Maatschappij DV and GIlT for a cooperation in the development of the pressurized version of the KT process. A demonstration plant with a throughput of 150 tons per day bituminous coal and an operating pressure of 435 psia was built and operated for a period of 30 months. After completion of the test program, Shell and GKT agreed to continue further development separately, with each partner having access to the data gained up to that date. GKT's work has led to the PRENFLO process. GET has decided to continue development with a test facility of 48 tons per day coal throughput. The plant is located at Fuerstenhausen, West Germany. Simultaneously with the pilot test program, the design and engineering of a demonstration plant with a capacity (coal feed rate) of 1,060 tons per day will be carried out. The engineering of the 1,600 tons per day gasifier module ("ready for construction") is expected to be completed in 1988. Project Cost: Not disclosed

RHEINBRAUN HIGH-TEMPERATURE WINKLER PROJECT - Rheinische Braunkohlenwerke AG, Uhde OmbU, West German Federal Ministry for Research & Technology (C-803) Rhelnbraun and Uhde have been cooperating since 1975 on development of the High Temperature Winkler fluidized bed gasification process. On the basis of preliminary tests in a bench scale plant at Aachen Technical University near Cologne, the sponsors commissioned a pilot plant in July 1978 at the Wachtberg plant site near Cologne. Following an expansion in 1930/1981, feed rate was doubled to 1.3 tons per hour dry lignite. By end of June 1985 the test program was finished and the plant was shut down. From 1978 until June 1985 about 21,000 tonnes of dried brown coal were processed in about 38,000 hours of operation. The specific synthesis gas yield reached 1,580 standard cubic meters per tonne of brown coal, MAP, corresponding to 96 percent of the thermodynamically calculated value. At feed rates of about 1,800 kilograms per hour coal, the synthesis gas output of more than 7,700 standard cubic meters per hour per square meter of gasifier area was more than threefold the values of atmospheric Winkler gasifiers. Rheinbraun has been constructing a demonstration plant for the production of 300 million cubic meters syngas per year. All engineering for gasifier and gas after-treatment including water scrubber, shift conversion, gas clean up and sulfur recovery was Performed by Uhde; Linde AG is contractor for the Rectisol gas cleanup. The synthesis gas to be produced at the site of Rheinbraun's VillefBerrenrath briquetting plant is to be pipelined to Rheinbraun's Union Kraftstoff subsidiary for methanol production. The plant was started up in early 1986. Up to now in several processing periods quite good efficiency data corresponding to the results of the HTW pilot plant could be reached in the gasifier. Nearly all steps of gas aftertreatment had been operated. In the meantime studies for further development of the HTW process for higher pressures up to about 20 bar are performed including optimization of the processing system as well as operation in a recycling fluidized bed especially in respect to utilization for combined power production. Project Cost: Undisclosed

RHEINDRAUN HYDROGASIFICATION OF COAL TO SNG -- Rheinische Braunkohlenwerke AG, Lurgi GmbH, Ministry of Research & Technology of the Federal Republic of Germany (C-475) The hydrogasification process developed by Rheinbraun is a pressurized fluidized bed technique. Engineering partner in this project is Lurgi. The project is subsidized by the Ministry of Research & Technology of the Federal Republic

4-80 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1985) (Continued)

Of Germany. A PDU for the hydrogasification was engineered and built by Lurgi company, Frankfurt, on the site of Union Kraftstoff at Wesseling. This plant with a throughput of about 5 tons per day dried brown coal or anthracite has been operated from 1975 to September 1982. More than 1,780 tons of dried brown coal and about 14 tons anthracite have been gasified during 12,235 hours at temperatures between 820 0 to 1,000°C and pressures between 55 and 95 bar. A methane content of nearly 50 percent by volume in the dry crude gas has been reached. The longest continuous test period of operation has been 31 days. A pilot plant with a throughput of about 240 tons per day of dried brown coal at pressures up to 120 bar was constructed from 1979 to 1982. This pilot plant includes an Amisol plant for washing out sour gas components and a Linde cryogenic separation unit for isolation of SNG from hydrogen for recycle Into the gasifier. For large-scale plants the hydrogen needed additionally can be generated in the HTW process with a following shift conversion of the carbon monoxide in the raw gas to hydrogen, or a part of the produced methane is catalytically reactor.converted in a methane stream reformer being heated with process heat from a high temperature gas cooled nuclear

The pilot plant went onstream in Spring 1983. Up to the end of April 1986 about 26,300 tons of dried brown coal were processed in about 5,800 hours of operation. The selected process design as a whole has proved successful; especially under 120 bar gasification pressure maximum 5,000 standard cubic meters per hour of methane were produced corresponding to 6,400 standard cubic meters per square meter of gasifier and hour. Also the gas after-treatment was operated with success including recovering of unconverted hydrogen in a cryogenic separation unit and returning it to the gasification process. Up to 100 bar nearly the same efficiency data were reached as in the small PDU, for 120 bar even better results as above mentioned. So the upscaling of the process was successful. Project Cost: Not disclosed SASOL TWO AND SASOL THREE - Sasol Limited (C-SW) Sasol Two and Three are commercial projects, based on the success of Sasol One, for the manufacture of mainly liquid fuels, ethylene, tar products, ammonia, sulfur, and other chemicals. The plants are situated on the eastern high veld of Transvaal. Coal (low grade) consumption at full production is 30 million tons per year from the Secunda Collieries. The facilities include boiler house, Lurgi gasifiers, oxygen plant, Rectisol gas purification, reactors, gas reformers, and refineries. The hydrocarbon synthesis uses Sasol's Synthol process. Managingsynthol contractor was Fluor Engineers. Construction of Sasol Two is completed and all units were commissioned by the end Of 1980. Production of first "crude" oil at Sasol Two started on March 13, 1980. Sasol Three is completed and began producing synthetic oil on May 10, 1982. Refined products from this plant have been marketed since the beginning of August 1982.

Project Cost: SASOL Two $2.9 Billion SASOL Three $3.8 Billion 'At exchange rates ruling at construction

SCOTIA COAL SYNFUELS PROJECT - DEVCO (A Federal Crown Corporation); Alastair Gillespie & Associates Limited; Gulf Canada Products Company (a subsidiary of Gulf Canada Limited); NOVA, an Alberta Corporation; Nova Scotia Resources Limited (a Provincial Crown Corporation); and Petro-Canada (a Federal Crown Corporation) (C-822) The consortium is conducting a feasibility study of a coal liquefaction plant in Cape Breton, Nova Scotia using local coal to produce gasoline and diesel fuel. The plant would be built either in the area of the Gulf Point Tupper Refinery or near the coal mines. The 25,000 barrels per day production goal would require approximately 2.5 million tonnes of coal per year. The plant start-up could be in 1989/1990. Additional funding of $750,000 requested from the Oil Substitution Fund (a fund jointly administered by the Canadian Federal Government and the Provincial Government of Nova Scotia) to evaluate two-stage process options was announced by the Nova Scotia government on October 3, 1984. A contract has been entered into with Chevron Research Inc. to test the coals in their two-stage direct liquefaction process (CCLP). Feasibility report has been completed. Financeability options are being discussed with governments concerned and other parties.

Project Cost: Approximately $4 million for the feasibility study Approximately $1.5 billion for the plant

4-81 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1988) (Continued)

SCRUBORASS - Scrubgrass Associates (C-825) Scrubgrass Associates (SGA) planned to build a 2,890 barrels per thy coal-to-methanol-to-gasoline (and other products) plant, to be located in Scrubgrass Township, Venango County, Pennsylvania. The sponsors submitted a request for loan and price guarantees from the United States Synthetic Fuels Corporation under the solicitation for Eastern Province or Eastern Region of the Interior Province Bituminous Coal Gasification Projects. The technology consists of three basic processes: high pressure GKT entrained-flow coal gasification, ICI methanol synthesis, and the Mobil methanol-to-gasoline (MTG) process. On November 19, 1985, the SFC dropped the project from further consideration. Scrubgrass Associates has converted the project from production of liquid fuels to the production of electric power, at the same location. Environmental work had largely been completed for the previous plan. The capacity of the plant is 100 MEG. The plan Is to use circualting fluidized bed technology, fueled with up to 6 percent sulfur coal. No federal assistance of any kind Is sought. The estimated total project costs, including start-up, commissioning, engineering, procurement, and construction, and financing costs, are $195,000,000. Financial closing is anticipated prior to the end of 1986. Project Cost: See above

SHELL COAL GASIFICATION PROJECT - Royal Dutch/Shell Group and Shell Oil Company (U.S.) (C-840) Shell Oil Company (U.S.) and the Royal Dutch/Shell Group are continuing joint development of the pressurized, entrained bed, Shell Coal Gasification Process. A 6 tons per day pilot plant has been in operation at Shell's Amsterdam laboratory since December 1976. A number of different coals and petroleum cokes have been successfully gasified at 300 to 600 psi. This pilot plant has now operated for over 10,000 hours. A 150 tons per thy prototype plant has been operating at the German Shell Hamburg/Harburg refinery since 1978 with over 6,000 hours of operation logged. its experimental program now complete, the plant has successfully gasified different types of coal in runs as long as 1,000 hours and has demonstrated the technical viability of the process. Further development of the Shell process is continuing through active pursuit at other Shell facilities. Shell Oil Company, The Electric Power Research Institute, and Lummus Crest, Inc., recently announced plans to build a demonstration unit for making medium-BTU gas, using the Shell Coal Gasification Process. Engineering was done by Lummus Crest's Bloomfield Division to incorporate all the advanced features of the Shell process and will be located at Shell's Deer Parkt Manufacturing Complex. Lummus Crest, Inc., is a subsidiary of Combustion Engineering, Inc. Shell Development Company, a division of Shell Oil, will operate the facility. The facility's gasifier will use pure oxygen and Is designed to process a broad range of coals, including about 250 tons per thy of high sulfur bituminous coal, or about 400 tons per thy of lignite. The medium-BTU gas and steam produced will be consumed within Shell's adjacent manufacturing complex. Construction Is underway with startup planned for early 1987. Project Cost: Not disclosed

S1MPLWIED iGCC DEMONSTRATION PROJECT -- General Electric Company, Burlington Northern Railroad, Empire State Electric Energy Research Corporation, New York State Energy Research and Development Authority, Niagara Mohawk Power Corporation, Ohio Department of Development, Peabody Holding Company, and United States Department of Energy (C-895) This project will use a coal gasification, steam-injected gas turbine power plant to demonstrate the feasibility of simplified integrated gasification combined cycle (10CC) systems for commercial coal-to-electricity applications. The simplified system is configured to reduce components in each of the major sub-systems: gasification, gas cleanup, and gas turbine power generation systems, while retaining commercial hardware and design philosophy for many of the sub-system components. The technology uses an air-blown moving bed gasifier, high temperature sulfur removal technology, hot cyclones, and the "LMn series (aircraft derivative) gas turbine/generator package. Key elements are the high-temperature gas cleanup systems which can allow significant reduction of contaminant levels without degradation of plant efficiency. The system will be demonstrated at different sizes at two site locations—a 5 megawatt plant in Dunkirk, New York owned by Niagara Mohawk Power Corporation and a 50 megawatt General Electric plant in Evendale, Ohio.

4-82 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

A prime objective of the demonstration program is the establishment of a high-performance, cost-competitive environmentally compliant, coal-fired power plant in the less-than 200 megawatt size. This option will significantly reduce the financial risk associated with the addition of large capacity increments to fleet projected needs. The demonstration program is proposed as a five-year project. The phasing will permit the 5 megawatt plant to come on-line three years after project initiation. The initial checkout and system characterization of the 50 megawatt plant will start three years into the program with full-scale operaton at the industrial site in tour and one-half years. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: $156 million

SLAGGING GASIFIER PROJECT - British Gas Corporation (C-850) The British Gas Corporation (BCC) constructed a prototype high pressure slagging fixed bed gasifier In 1974 at Westfield, Scotland. (This gasifier has a throughput of 350 tons per day.) The plant has been successfully operated since that date on a wide range of British and American coals, including strongly caking and highly swelling coals. The ability to use a considerable proportion of fine coal in the teed to the top of the gasifier has been demonstrated as well as the injection of further quantities of fine coal through the tuyeres into the base of the gasifier. By- product hydrocarbon oils and tars can be recycled and gasified to extinction. The coal is gasified in steam and oxygen. The slag produced is removed from the gasifier in the form of granular frit. Gasification is substantially complete with a high thermal efficiency. A long term proving run on the gasifier has been carried out successfully. A new phase started in November 1984, is the demonstration of a 600 tons per day (equivalent to 70 megawatts) gasifier with a nominal I.D. of 8 feet. Within this demonstration program a three month run will be carried out to demonstrate gasifier operability, gas purification, and methanation to make SNG. It is also planned to carry out a number of tests for EPRI and the Gas Research Institute. Integrated combined cycle tests will be carried out with an 8K 30 Rolls Royce Olympus turbine to generate power for the grid. The turbine will be supplied with product gas from the plant. It has a combustor temperature of 1,960°F, a compression ratio of 10, and a thermal efficiency of 31 percent. 8CC is prepared to grant licenses for plants utilizing Slagging Gasifiers of sizes up to 8 feet diameter and will provide full commercial guarantees.

Project Cost: Not available

SOLVENT REFINED COAL DEMONSTRATION PLANT (SRC-0 -- International Coal Refining Company (Air Products and Chemicals Inc./Wheelabrator_Frye Inc., partnership), Kentucky Energy Cabinet, and United States Department of Energy (C-860) An SRC pilot plant was operated on the site of Southern Company's E.C. Gaston Steam Plant near Wilsonville, Alabama. It was designed, built, and is operated by Catalytic, Inc. under funding of the Electric Power Research Institute and DOE. The process dissolves coal under pressure in the presence of hydrogen. The products are clean solid and liquid fuels with heating values of approximately 16,000 BTU per pound (150,000 BTUper gallon) and gasoline naphtha. The sulfur content is reduced to a maximum of 0.8 percent. Plant capacity is 6 tons per day of coal. Data from the Wilsonville, and Ft. Lewis, Washington, SRC plants have been correlated, and eleven coals tested. The conceptual design of a 6000 tons per day SRC-1 demonstration plant was completed July 31, 1979 and submitted to DOE. To carry out the project, Air Products and Wheelabrator-Frye established the International Coal Refining Company (ICRC). Under terms of a cost sharing agreement, ICRC will invest $90 million in the project, the Commonweath of Kentucky will invest $30 million and the Department of Energy will fund the balance. A site for the demonstration plant at Newman, Daviess County), Kentucky is under option. Feedstock is 6,000 tons per day high-sulfur Illinois basin coal. Products include 20,000 barrels per day (oil equivalent) of solids, liquids, and gases. SRC fuel in the 850°F and lighter fractions will be used to displace No. 6 fuel oil. SRC liquids include heavy oil (650 0 to 850°F fraction oils), a 400° to 600°F middle distillate that can replace No. 2 fuel oil, and naphtha (C5-400° p fraction oils) for reformer feed for high-octane, unleaded gasoline blendstock or BTX chemicals. The Final Environmental Impact Statement was released in July 1981. The project baseline was transmitted to Congress in May 1982. The DOE allocated funds to continue detailed design and generic coal liquefaction technology development. This work was completed in December 1984. The revised cost estimate specified in the report Indicates project costs to be $2.2 billion (escalated for inflation). Although

4-83 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAl. CONVERSION PROJECTS (Underline denotes changes since June 1986)

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previous cost estimates were approximately $2.0 billion, the project revenues are expected to exceed expenditures by $200 million in the first 2 1/2 years of operation. Plant startup is contingent upon future government funding. Estimated Project Cost: $2.2 billion (Demonstration Project) SOUTH AUSTRALIAN COAL GASIFICATION PROJECT - Government of South Australia (C-865) The South Australian Government is continuing to assess the feasibility of building a coal gasification plant utilizing the low rank brown coal of the Northern St. Vincent Basin deposits, north of Adelaide. The plant being studied would be integrated with two 300 MW combined cycle power station nodules and is one possible option for meeting additional power station capacity requirements in the mid- 1990s. Coal has been tested in a number of processes including the Sumitomo CGS (molten iron bath), Westinghouse, Shell- Koppers and Texaco, and studies are continuing in conjunction with Sumitomo, Uhde-Steag, and Krupp-Koppers. Heads of Agreement have been signed with a consortium headed by Uhde GmbH to test coal from the Bowmans deposit in the Rheinbraun HTW gasifier and perform a detailed design and feasibility study for a 600 MW gasification combined cycle power station. Ten tonnes of coal were satisfactorily gasified in the small scale Process Development Unit at Aachen, PRO, in August 1985. Contracts have been entered into to gasify 1,000 tonnes of Bowmans coal in early 1987 in the Rheinbraun Pilot Plant at Frechen-Wachtherg, P11G. if satisfactory results are achieved in those tests, a report on project feasibility, based on costing to quotation standard, is due by mid-1988. Project Cost: DM 7.5 million

SYNTHESEGASANLAGE RUUR (SAR) - Ruhrkohie Get and Gas GmbH Ruhrcheinie AG (C-869) Based on the results of the pressurized coal-dust gasification pilot plant using the Texaco process, which has been in operation from 1978 to 1985, the industrial gasification plant Synthesegasanlage Ruhr has been completed on Ruhrchemie's site at Oberhausen-Ilolten. The Synthesegasanlage Ruhr is in start-up phase. Approximtely 250,000 tons of German hard coal will be gasified per year to produce 400 million cubic meters synthesis gas and hydrogen yearly for chemical use. The project is subsidized by the Federal Minister of Economics and by the West German State of North-Rhine Westphalia. Project Costs: DM220 million for construction TENNECO SNG FROM COAL - Tenneco Inc. (C-870) Tenneco, through subsidiary companies intake Water Company and Tenneco Coal Company, has been 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. The final Environmental Impact Statement for the diversion works and the selected reservoir site has been issued by the Bureau of Reclamation, and the diversion works and the selected reservoir site has been issued by the Bureau of Reclamation, and Section 10 and 404 Permits have been issued by the Corps of Engineers. Tenneco Coal Gasification Company, a subsidiary of Tenneco, Inc., filed its first annual Long-Range Plan under the Montana Major Facility Siting Act in April 1980 for a gasification plant to produce 280 million cubic feet per thy pipeline quality gas using Lurgi coal gasification technology. Feedstock would be approximately 40,000 tons per day lignite from Wibaux County and Golden Valley (North Dakota). Tenneco filed its latest annual Long-Range Plan in April 1984 calling for full gas production by the end of 1994. However, on July 25, 1984 tenneco announced the closing of its Glendive, Montana office and suspension of all activities associated with the gasification project. This suspension is due to the static demand for natural gas, flat energy prices, and the lack of national dedication to energy independence for the United States. The project will remain shelved until there Is a change in the energy picture. Tenneco does not expect to file another Long-Range Plan for four or five years—approximately 10 years before the facility's forecasted in-service date. Tenneco Coal Company will maintain its coal leases, and intake Water Company will continue to perfect its water rights, all being done from the Tenneco Corporate headquarters in Houston, Texas. Project Cost: $2.8 billion in 1982 dollars

4-84 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

TEXACO COAL GASIFICATION PROCESS -- Texaco Inc. (C-890) The commercial status of the Texaco Coal Gasification Process has been a result of extensive development at Texaco's facility in Montebello, California since the 1973 oil embargo. During this period, Texaco spent more than $8 million to expand and improve its existing gasification facilities at Montebello. There are now two complete gasifier trains, each capable of processing more than 20 tons per day coal, at pressures ranging from 300 to 1,200 psig, in either the quench or gas cooler modes of operation. The facilities include coal grinding, slurry preparation, and gas scrubbing units which are capable of producing a clean syngas product in continuous operation. This pilot plant has processed a wide variety of coals and has provided design information for a number of commercial projects in operation and under construction. In addition, pilot plant operations are conducted to Improve and enhance Texaco's gasification technology. Texaco's development activities were complemented during the 1978 to 1985 period by operations at three licensed demonstration plants. These plants are owned by Ruhrkohle AG/Ruhrchemie AG, Tennessee Valley Authority, and Dow Chemical, and are located in Oberhausen—Holten In the Federal Republic of Germany, Muscle Shoals, Alabama, and Plaquemine, Louisiana, respectively. The Texaco Coal Gasification Process is currently employed for the commercial production of electric power and a variety of products, and has application for a wide range of chemicals which can be manufactured from synthesis gas. Commercial projects currently in operation utilizing the Texaco Coal Gasification Process include the 900 tons per day Tennessee Eastman plant which manufactures methanol and acetic anhydride, the 1,000 tons per day Coot Water plant which manufactures electricity, and the 1,650 tons per thy Ube Ammonia plant which manufactures ammonia. Additionally, the 770 ton per day BAR plant in Oberhausen, West Germany has begun operation for the manufacture of oxo-chemicals. Commercial projects currently In detailed design and construction include the 440 ton per day LuNan Coal Gasification Plant in China to manufacture ammonia, and the 2,700 ton per thy Nynas Energy Chemicals complex in Sweden. A number of United States utilities are actively considering coal gasification for future electric power capacity additions, and several are working with Texaco on detailed site-specific studies of the Texaco process. Project Cost: Not applicable •TIDD PRESSURIZED FLUIDIZED BED DEMONSTRATION PROJECT -- American Electric Power Service Corporation, Ohio Coal Development Office, Ohio Power Company, and United States Department of Energy (C-895) The American Electric Power Service Corporation (AEP), on behalf of the Ohio Power Company, will construct and operate a 70 megawatt Pressurized Fluidized Bed Combustion (PFBC) Combined Cycle Demonstration Plant in Brilliant, Ohio. The project will use technology developed by ASEA-PPB, a Swedish firm that supplies major utility components. AEP has designed the Tidd PFBC Demonstration Plant with a capability of 70 megawatts, to be located in the town of Brilliant, Ohio. Its design is based on almost a decade of research and development by ASP and its partners. The schedule calls for having the plant start operation in late 1989 and run for a demonstration period of five to ten years, during which time enough data about the technology and equipment will be acquired to confidently build large, commercial power plants. The PFBC process involves burning coal in a fluidized bed of coal, dolomite (a form of limestone), and Inert material. Sulfur in the coal Is absorbed by the dolomite, resulting In a dry, granular by-product ash which is removed from the bed. The hot, pressurized, sulfur-free gas flows through a dust collector then through an ASEA STAL GT120 gas turbine to drive an air compressor and a generator to produce electric power. Immersed in the bed are tubes to generate steam which flows through a steam turbine that drives a second generator to produce additional electric power. The clean, cooled gas is released throush the stack in full compliance with environmental requirements. The combined cycle plant will operate at 1,580"F and a pressure of 12 atmospheres. The demonstration plant will be a retrofit of a mothballed coal-fired power plant and will utilize the existing steam turbine and other site utilities. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: $175.6 million TOSCOAL PROCESS DEVELOPMENT - Tosco Corporation (C-900) TOSCO has completed development in 1983 of an atmospheric, low-temperature (800-910°F) coal pyrolysis system, named the TOSCOAL Process, at their 25 tons per day pilot plant facilities, located near Golden, Colorado. The

4-85 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1086) (Continued)

TOSCOAL Process is an adaptation of the TOSCO II oil shale retorting process to coal carbonization. The process products are char for power plant consumption, high-BTU gas, and oil. Coals tested in the pilot plant to date are Wyodak sub-bituminous, Illinois No. 6 bituminous, and Utah bituminous coal. Process evaluations show that a plant designed to process nominally 10,000 tons per day of coal will produce as major products 7,800 tons of readily combustible char, 11,500 barrels of hydrotreated oil, 500 barrels of vacuum residual and fuel gas. Economic analyses indicate that, relative to coal liquefaction technologies, the capital cost per daily barrel of product from the TOSCOAL Process is substantially less. TOSCO is actively seeking industrial and utility participation in the demonstration and commercialization of the TOSCOAL process. Project Cost: Undetermined TVA AMMONIA FROM COAL PROJECT - Tennessee Valley Authority (C-940) 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 was retrofitted to an existing 225 tons per day ammonia plant. Plant construction was completed In mid-1980. Capital costs total $46 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 done by TVA. The coal gasifier can 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 was Illinois No. 6 seam coal. The gasifier was dedicated and started up at the TVA's 13th Demonstration of Fertilizer Technology conference in October 1980 and continued In itermittent operation until 1981. However, actual production of feed gas for ammonia manufacturer was not accomplished because of mechanical problems. The plant was shut down while modifications were made to the gasifier and other downstream processes and equipment The plant was restarted in April 1982. Operations continued Intermittently through November 1982 and culminated In a 5-day performance test. Although the plant did not meet all the contract performance requirements, particularly in the sulfur recovery area, the facility did provide synthesis gas for the production of ammonia. Plant operations continued for 12 days, prior to being shut down at the end of the performance test. Total operating time was approximately 1,600 hours. The plant was not operated again until July 1983 primarily because of budget limitations. A 5-thy coal test was made in July and was followed by a 20-thy test using LOS residues. Additional tests were made in late 1984, and others are planned for 1985. The plant was restarted and operated for 20 days in mid-1984. TVA hopes to attract additional private sponsors to join the project. Project Cost: $60 million total TWO-STAGE LIQUEFACTION - (See Integrated Two-Stage Liquefaction) UBE AMMONIA-FROM-COAL PLANT -- Ube Industries, Ltd. (C-952) Ube Industries, Ltd., of Tokyo recently completed the world's first large scale ammonia plant based on the Texaco coal gasification process ("TCOP'9. There are four complete trains of quench mode gasifiers in the plant. In normal operation three trains are used with one for stand-by. Ube began with a comparative study of available coal gasification processes in 1980. In October of that year, the Texaco process was selected. 1981 saw pilot tests run at Texaco's Montebello Research Laboratory, and a process design package was prepared in 1982. Detailed design started in early 1983, and site preparation in the middle of that year. Construction was completed in just over one year. The plant was commissioned in July 1984, and a first drop of liquid ammonia from coal was obtained in early August 1984. Those engineering and construction works and commissioning were executed by Ube's Plant Engineering Division. Ube installed the new coal gasification process as an alternative "front end" of the existing steam reforming process, retaining the original synthesis gas compression and ammonia synthesis facility. The plant thus has a wide range of flexibility in selection of raw material depending on any future energy shift, it can now produce ammonia from coals, naphtha and LPG as required. The gasification plant has operated using four kinds of coal-Canadian, Australian, Chinese, and South African. The overall cost of ammonia is said by Ube to be reduced by fore than 20 percent by using coal gasification. Furthermore, the coal gasification plant is expected to be even more advantageous if the price difference between crude oil and coal increases. Project Cost - Not disclosed

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UNIVERSITY OF MINNESOTA LOW-BTU GASIFIER FOR COMMERCIAL USE - United States Department of Energy and University of Minnesota (C-970) In February 1977, DOE awarded a five-year cost-sharing contract to the University of Minnesota for design, construction, and operation of a 72 tons per day Foster Wheeler Stoic gasifier to be located at Duluth, Minnesota. Foster Wheeler provided the engineering services. The two-stage gasifier utilizes technology licensed by Foster Wheeler from Stoic Combustion Ltd. of Johannesburg, South Africa. The 180 BTU per standard cubic feet gas Is used to fire a boiler for heating/cooling of campus buildings. The process produces fuel oil as a coproduct which will be used as boiler fuel during gasifier maintenance. The Stoic gasifier was started initially in October 1978. Altogether five different western sub-bituminous 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 partially the fuel needs for the campus heating plant. Operation changes from western coal to Western Kentucky Bituminous coal to Improve economics of operation. Cooperative agreement with Department of Energy ended August 1982. Plant operation now entirely funded by University of Minnesota. Project Cost: $6,401,551.30; DOE share $2,819,940.00 VICTORIA BROWN COAL LIQUEFACTION PROJECT - Brown Coal Liquefaction (Victoria) Pty. Ltd. (C-975) SCLV is constructing a pilot plant at Morwell in southeastern Victoria to process the equivalent of 50 tons per day of dry ash free coal. BCLV is a subsidiary of the Japanese-owned Nippon Brown Coal Liquefaction Company (NBCL), a consortium involving Robe Steel, Mitsubishi Chemical Industries, Nissho Iwal, Idemitsu Rosen, and Asia OIL The project Is being run as an Inter-governmental cooperative project, involving the Federal Government of Australia, the State Government of Victoria, and the Government of Japan. The program is being fully funded by the Japanese government through the New Energy Development Organization (NEDO). NBCL is entrusted with Implementation of the entire program, and BCLV will carry out the Australian components. The Victorian government is providing the plant site, the coal, and some personnel. Construction of the drying, slurrying, and primary hydrogenation sections comprising the first phase of the project began In November 1981 and is now In operation stage. The remaining sections, consisting of solvent deashlng and secondary hydrogenation, are expected to be completed during 1986. The planned life of the pilot plant is five years, with NEDO providing the estimated A$100 million necessary to cover operating costs during this period. (Construction Cost: A$145 million). The aim of the pilot plant is to provide data on a Catalytic Solvent Refined coal liquefaction process developed since 1971 by members of the consortium. Tentative plans call for construction beginning near the end of this decade of a demonstration plant consuming about 5,000 tons per day of dry coal equivalent, this being the first unit of a six unit commercial plant. The pilot plant is being built adjacent to the Morwell open cut brown coal mine. Davy McKee Pacific Pty. Ltd., is providing the Australian portion of engineering design procurement and construction management of the pilot plant. Project Cost: Undisclosed WUJING TRIGENERATION PROJECT -- Shanghai Wujing Chemical Corporation (C-992) The Shanghai Wujing Chemical Corporation (SWCC) is considering a trigeneratlon project to produce coal-derived fuel gas, electricity, and steam. The proposed plant will be constructed near the Shanghai Coking and Chemical plant in Wujing, a suburb south of Shanghai. SWCC contracted with Bechtel on June 6, 1986 to conduct a technical and economic feasibility study of the project. The proposed project will consist of coal gasification facilities and other processing units to be installed and operated with the existing coke ovens in the Shanghai Coking and Chemical Plant. The facility will produce 3 million cubic meters per day of 3,800 Kcal per cubic meter of town gas (106 million cubic feet per day of 427 BTU per cubic foot); 50 to 60 megawatts of electricity; 100 metric tons per hour of low pressure steam; and 300,000 metric tons per year of 99.85 percent purity chemical grade methanol. The project will be constructed in stages.

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It is anticipated that the study will be approximately eight months in duration. Bechtel will be paid from a $800,000 grant to SWCC from the United States trade and development program ITUPT International Development Cooperation Agency.

Project Cost: Not disclosed

UNDERGROUND COAL CONVERSION PROJECTS

UNDERGROUND COAL GASIFICATION, BRAZIL -- Companhia Auxiliar de Ernpresas Electricas Brasileiras and United States Department of Energy (C-1002) On January 21, 1985 the United States and Brazil signed a bilateral agreement to jointly study underground coal gasification (UCG). The objective of the agreement is to undertake a joint analytical and test program for the development of UCG technology utilizing the site of the Triunfo coal deposits in Rio Grande do Sul. The program will consist of three phases of work: (1) coal and site characterization; (2) test design and feasibility studies; and, (3) test operations and evaluation. During the first phase DOE will provide geologic specifications, preliminary evaluations of samples of Brazilian coals, technical experts on site, site characterization methods and tools, and data evaluation to develop a preliminary process design. CAEEB will provide needed data to DOE and will be responsible for actual site characterization studies and field tasks such as drilling and seismic studies. During the test design and feasibility study phase (Phase 2), DOE will provide information and technical experts to assist in the preparation of the preliminary design of an actual field test. During this second phase CAEEB agrees to be in charge of the preliminary feasibility test program, and for all subcontracting. In Phase 3, which consists of test operations and evaluation, DOE agrees to provide technical experts to the CAEEB during the operation and evaluation of the UCG test. DOE may also loan data aquisition hardware and software and related instrumentation to assist in monitoring the test. CAEEB will provide to DOE all information on the design and results of the field test. DOE and CAEEB will each bear their own costs of their participation in the activities under the agreement: The agreement will continue for a five year period, and may be extended by mutual agreement of both countries. Project Cost: Not Disclosed

UNDERGROUND COAL GASIFICATION, BYRNE CREEK - Dravo Constructors, Inc. and Energy Investments, Inc. (C-lob) On August 31, 1981, Extractive Fuels executed a 50-50 joint venture agreement with World Energy, Inc. of Laramie, Wyoming. Extractive Fuels agreed to put approximately 26,000 acres of its coal property located in the Southern Powder River basin into the joint venture and World Energy, Inc. has committed the use of their licenses and patents, and technical application ability in the in situ coal gasification technology for the express purpose of developing and building the first commercial in situ gasification synfuels plant. The companies have further agreed to share the organizational cost on an equal basis. World Energy applied to the SEC for loan guarantees and price supports for an underground gasification project. According to the original SEC application, the Fischer-Tropsch synthesis would be used for the production of refinable liquids. However, they did not meet the SEC deadline for additional information. The project sponsors - reapplied for a loan guarantee under the SEC's second solicitation ending June 1, 1982. The revised project proposed to utilize UCG technology to produce 14 billion BTU of SNG and 436 barrels of light oils per day. The project did not pass the SEC's project maturity test. Under the SEC's third solicitation, the sponsors proposed to develop an underground coal gasification project to produce 198 million KWH annually (450,000 BOE per year) of electricity, 46,000 barrels per year of light oils (44,000 BOE per year) and 110,000 tons annually of carbon dioxide. The facility will be located in Uintah County, Wyoming near Evanston. Feedstocks will be 614 tons per day coal and 300 tons per day oxygen. Construction is planned for May 1985 pending acquisition of all necessary state permits, with plant start-up projected for Spring 1987. In March 1983 the project passed the SEC's maturity review. On May 26, 1983 the project passed the SEC strength evaluation and was advanced into Phase II negotiations for financial assistance. Loan and price guarantees were requested. On

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February 24, 1984 the SFC announced that the project had been dropped from further consideration under the third solicitation. The sponsors resubmitted a proposal to the SFC for loan and price guarantees under the fourth general solicitation that closed June 29, 1984. However, on January 15, 1985 the project was again dropped from further consideration.

Project Cost: $89 million

UNDERGROUND COAL GASIFICATION OF DEEP SCAMS - Groupe d'Etudes de Ia Gazeificatlon Souterraine (GEGS) consisting of Bureau de Recherches Geologiques et Minieres, Charbonnagcs de France, Gaz de France, and Institut Francais du Petrole (C-1160) The goal of the GEGS (Study Group on Underground Gasification of Coal) project is to achieve gasification of coal at depths of approximately 1,000 meters which is inaccessible, on an economic and human point of view, by current mining methods. In France and in west European countries, the coal reserves of this type are rather large. In France, they are estimated at about 2 billion tons. The process investigated involves In situ gasification with oxygen to obtain a high BTU gas by further enrichment above ground. Because at great depth the coal permeability to gas is very low, the process requires a first step of creating a link between the two wells of the Injection-production doublet. The program of research has a total duration of six years, from 1979 to 1985. It includes theoretical studies (modelling), laboratory work, and experiments on site. - The first tests on site were conducted from March 1980 to July 1981 from a deep level of an existing conventional mine just before its closure (Bruay-en-Artois) in the Nord-Pas de Calais mining region. The different steps of these tests consisted In: (1) geological and structural appraisal or the site, (2) creating a link between the wells by hydraulic fracturing, and (3) initiation of a reverse combustion. A new site, operated directly from above ground, was selected In the Nord-Pas de Calais mining region (Haute- Deule). Three exploratory wells were drilled at this new site in 1982 and two of them equipped as Injection- production wells; the spacing between these wells is 60 meters. The tests, scheduled to last three years, will be more ambitious than at the Bruay site. The two first steps of drilling/geological reconnaissance of the site and of creating a link by hydraulic fracturing were achieved with good results. The third step, reverse combustion, occurred at the end of 1984. Results were not sufficient to carry on with the fourth step (gasification). Additionally, tests have been conducted in 1982 and 1983 in a shallow coal seam In the Loire mining region (l'Echaux) to study the technical feasibility of electrolinking. Such a linking was successfully achieved between two wells located 10 meters apart. The design of a new experimental program is now planned for the gasification of rather thick (about 10 meters) coal seams. The linking between the wells will be achieved by the technique of horizontal drilling. A call for new partners sent by GEGS at the end of 1985 has not brought positive answers up to now. GEGS has decided to postpone all operations until an agreement has been reached to finance the new program. Project Cost (1979-1985): Approximately $28 million Proposed Project Cost (1986-1988): Approximately $10 million

UNDERGROUND COAL GASIFICATION, ENGLISH MIDLANDS PILOT PROJECT -- National Coal Board (C-lola) The United Kingdom's National Coal Board (NCR) is planning a test of underground coal gasification (UCG). The experimental project will be located in the English Midlands near Newark. Up to 60,000 tonnes of coal will be gasified in a test program lasting five to six years. The tests will use deviated drilling techniques to access a six foot thick coal seam at a depth of 2,000 feet. Estimated cost of the program is 15 million pounds sterling (approximately $22 million). The purpose of the tests is to develop methods to exploit coal deposits located offshore under the North Sea. Very large reserves of coal (reportedly billions of tonnes) are located in the undersea deposits in seams up to 70 feet thick. Previous tests of UCG were conducted in the Midlands in the late 1950s. Results of the PS trial at Newman Spinney were not particularly encouraging in that the product gas had a low heating value. However, the coal seam used In the test was only 3 feet thick. The researchers believe that the thicker coal seam to be used in the newly proposed tests, in combination with recent advances in UCG technologies, will produce more favorable results. Project Cost: $22 million

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UNDERGROUND COAL GASIFICATION, INDIA --India Oil and Natural Gas Commission (C-1045) The government of India has appropriated $40 million to test the potential of underground coal gasification (UCG) for domestic coal. The proposed site for the test in central India contains large reserves of subbituminous coal that could be amenable to UCG. Also, the site is near a petroleum fireflood project. Hence, equipment and trained personnel are already located near the planned UCG test site. However, experts Iron the United States, Belgium, and West Germany concluded that the depth of the coal—approximately 2,000 feet—could cause problems with the proposed test as it was originally designed. Therefore, they recommended that the Indian researchers utilize the Controlled Retracting Injection Point (CHIP) technology developed by the Lawrence Livermore National Laboratory. The first information well (UCG-1) is currently being drilled through the Mehsana City structure located in North Gujarat. The further course of action will be decided based on the analysis of the core samples from this well. Project Cost: $40 million appropriated UNDERGROUND COAL GASIFICATION, JOINT BELGO-GERMAN PROJECT - Belgium, European Economic Com- munity, and Federal Republic of Germany (C-1150) A Belgo-German trial project is being conducted in Belgium at Thulin, in a coal deposit at 860 meter depth. The goal of the trials is to create an underground gas generator which can operate at a pressure of 20 to 30 bar. Investigation of the potential for developing underground gasification of deposits at great depth was begun in Belgium at the end of 1974. The first effort has grown since 1976, when a Belgo-German cooperation agreement was signed which resulted in the execution of an experimental underground gasification project sited at Thulin. The site chosen lies at the western end of the Borinage coalfield, in an area where the deposits are still unworked because of the considerable tectonic disturbances present between the surface and the 800 meter level. Work began In 1979 and is planned to continue into 1987. The first reverse combustion experiment was executed from April to October 1982 without the formation of a linking channel. The test had to be halted due to self-ignition of the coal, after 3.5 days. In November 1982 the fire was extinguished by injection of water and nitrogen. Before starting a second experiment of reverse combustion, the wells have been restored and various improvements were brought to the equipment to eliminate the self-ignition of the coal in the vicinity of the injection hole and to prevent the accumulation of water at the bottom of the gas recovery hole. This second experiment started in September 1982 and was stopped in early May 1984. The experiment suffered from 4 interruptions due to tubing breakage by corrosion. The trials demonstrated that it is not possible to avoid self-ignition of the coal in the vicinity of the injection well, but after scattering of this fire, the oxygen content of the exhaust gases increased to a level where it should be possible to again develop reverse combustion starting from the recovery well. The trials made during February-May 1984 demonstrated that this concept can be successful. It was possible to start coal burning by self-ignition in the vicinity of the recovery well on March 20 and April 19, injecting ca. 500 cubic meters per hour air and 50 cubic meters per hour carbon dioxide under 250 bar and keeping a backpressure of 100 bar at the outlet. During the last trial, the combustion evolved to gasification, producing 150 cubic meters per hour of lean gas during 12 days. A careful analysis, however, of the available data (flow/pressure, tracer tests) did not show any evidence that a channel had been started. The experiment has been stopped, while intensive work is devoted to solving the corrosion problems (the tubing has to withstand both cold and hot corrosion), and to preparing a trial with strongly deviated drillings, starting from the existing wells. This trial has been made with success in September 1985: a drainhole of 40 meters length (27 meters in coal) has been drilled from Well I in the direction of Well II, and a flexible liner has been set inside this drainhole. However, the azimuth control was poor. It is planned to drill a sidetrack from Well It and to link It with the drainhole In early 1986; this delay is due to the long delivery time of the special, corrosion resisting material to be set inside Well II. In December 1985 and January 1986, a sidetracked hole was drilled from the level 670 of Well II and crossed the seam at about 1 meter from the drainhole. The coal plug between the wells has been expelled by high pressure water on February 4, 1986. The final completion of the wells was done in March-April 1986.

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STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (ContinuecO

Project Cost: Not disclosed

UNDERGROUND BITUMINOUS COAL GASIFICATION PROJECT -- Morgantown Energy Technology Center and United States Department of Energy (C-1070) The Morgantown Energy Technology Center is continuing R & U activities to assess the potential of using underground coal gasification to provide clean gaseous fuels from Eastern bituminous coals. The overall goal for the research oriented project is to establish a data base for the recovery of energy from swelling bituminous coals that are presently uneconomical to mine and use by current conventional methods. Project emphasis is on the deep, thin seam, swelling, high sulfur bituminous coals located in the eastern half of the United States. In 1982, a study performed by Williams Brothers Engineering Company for DOE revealed UCG-amenable bituminous coal resources in ten states. The report suggested prime target resources for field test sites in Illinois, Kentucky, and Ohio. Responses from a widely advertised request for expressions of interest indicated high interest in cooperative support for this project, including the states as well as several industrial and private concerns. The intial site selection effort involved the screening of over forty potential outcrop/higtiwall and deep seam test sites which were recommended by the three states. Evaluation of these sites, using available geographic, geologic, and hydrologic data, resulted in a ranking relative to the desirability for use as a test site. Final selection will be made upon ascertaining the availability of the sites and the interest in project participation by the coal owners. Assessing viable quantities of coal In an economically and environmentally acceptable manner must be considered thoroughly. Large areas may be required for the eventual commercialization of bituminous coal seams and these areas may extend under rough terrain or near regions of relatively high population density. Therefore, site selection and characterization is a critical factor prior to the proposed field research activities. Establishing and maintaining a permeable channel between process wells must be evaluated also. Of prime Interest is the application of directional drilling techniques to establish long horizontal boreholes within the coal seam. By investigating various borehole channel length-to-diameter ratios, through laboratory and outcrop tests, a viable channel may be established to permit continuous gasification with tar condensation in this swelling resource. Stabilizing the link through reverse combustion or electroliriking techniques may also be required. A data base will be developed through a coordinated program consisting of (1) supporting research Involving laboratory studies and modeling, and (2) field tests involving open seam outcrop/highwall tests, and deep seam tests. A strong initial federal role is planned; however, as the technical risks are reduced, a decreasing federal role with an increasing role by the state and Industrial participants is anticipated. The METC Bituminous UCG Project was funded in fiscal year 1983 and fiscal year 1984 to determine the potential for the project, to select a site for field testing, and to establish the supporting research activities. Project Costs: $0.450 million, fiscal year 1983 $0.825 million, fiscal year 1984 $0.900 million, fiscal year 1985 UNDERGROUND COAL GASIFICATION, LLNL STUDIES -- Lawrence Livermore National Laboratory (C-1092) The LLNL has been working on in situ coal gasification since 1972, under the sponsorship of DOE and predecessor organizations. Tests that have been conducted include three underground coal gasification tests at the Hoe Creek site near Gillette, Wyoming; five small field tests ("Large Block Tests") at an exposed coal face in the WIOCO coal mine near Centralia, Washington; and a larger test at the same location (the "Partial Seam CHIP Test"). Previous LLNL work involved development of the packed bed process, using explosive fracturing. A field test, Hoe Creek No. 1, was conducted during FY1976-1977, to test the concept. A second, experiment, carried out during FY1977-1978, Hoe Creek No. 2, was gasified using reverse combustion and produced 100 to 150 BTU per standard cubic foot gas using air injection, and 250 to 300 BTU per standard cubic foot gas during a two day steam-oxygen Injection test. The third experiment, Hoe Creek No. 3, was carried out during FY1978-1979, using a drilled channel to provide the link between the process wells. The test ran for 57 days, 47 consecutive days using steam and oxygen, during which 3,800 tons of coal were gasified with an average heating value of 215 BTU per standard cubic foot. The test showed that long-term use of steam-oxygen underground gasification is technically feasible, operationally

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simple and safe. The use of steam and oxygen is crucial because the medium heating value gas produced by steam- oxygen gasification is readily converted to chemical synthesis gas or to pipeline quality, which is the objective of this project. The "Large Block Tests" in P11982 were designed to carry the concepts of the laboratory tests to a larger size in the field and still retain the ability to visually examine the burn cavities by simple excavation. The tests were very successful in providing detailed data which were used to develop a 3-fl cavity simulation model, CAYSM. The results from the Block tests led to the design of the Centralia Partial Seam CRlF test which was carried out in FY1983-1984. Over 2,000 tons of coal were gasified with steam and oxygen to produce a gas with an average heating value of 240 BTU per standard cubic foot. The test was designed to test the Controlled Retracting injection Point (GRIP) concept in a coal seam with real commercial potential but on a scale small enough to allow the test to be completed within 30 days. Oxygen-steam injection was used through a 900 foot tong well drilled from the coal face parallel to the dip of the seam. The product gas was produced first through an intersecting vertical well, and second, for the CRIP cavity, through a slant well drilled from the exposed face. Two distinct gas qualities were achieved --- a relatively high level after the CRIP maneuver and lower levels during the first cavity burn and after the roof collapse of the second burn. Even though some directional control problems were encountered in drilling the slant holes, the overall success of the Partial Seam test was very encouraging for the future of IJCG at the Centralia site. The CHIP concept adds one more degree of control to the process in that the average heating value of the produced gas can be controlled by controlling the position of the injection point. A large scale test, Rocky Mountain I is being planned for completion in late P11981 at Hanna, Wyoming. The test will provide a direct comparison of the CRIP method with a vertical Injection well method, and will operate long enough to give resource recovery data from a multiple cavity burn. Both test modules will utilize directional drilled links and will use horizontal production wells. One module will have a CRIP injection system while the other will use vertical injection wells. Agreements have been signed with both Spain and Brazil for aid and assistance in developing underground coal conversion projects in those countries. LLNL has been training Spanish engineers and expects to continue to Interact with their program in an advisory capacity. Work Is to get started in P11986 on a feasibility study with Brazil. Negotiations are underway and agreements in principle have been made with India and Yugoslavia. At the present, DOE is only being asked to provide consulting to the Indian program, which is being completely financed by the Indian government. The Yugoslavian program has asked for some training similar to that done for the Spanish program. Objectives for PY1987 include: 1. Continue to support the Rocky Mountain I field test at Hanna, Wyoming including active participation in the operational phase. Goals of the experiment are to determine the technology for larger scale operation and to refine the economics for commercial gasification. 2. Continue the modelling program with emphasis on cavity growth simulation comparison with field results. 3. Continue to support the DOE and State Department in technology transfer through agreements with foreign countries such as Spain, Brazil, and India.

Project Cost: Not disclosed UNDERGROUND COAL GASIFICATION, LEIGH CREEK -- State Government of South Australia (C-1097) A study sponsored by the State Government of South Australia projects favorable economics for underground gasification to coal to produce electric power from the Leigh Creek deposit. Confirmatory drilling to test geotechnical assumptions made for the feasibility study was conducted during October 1984. Because significant capital is required and because government and utility trust expenditures are presently committed to other coal-related programs, the test panel burn that was planned for 1986/1987 has been postponed. However, discussions with Shedden Pacific are continuing. Shedden Pacific Pty. Ltd., conducted the feasibility study, which found that at least 120 million metric tons of coal at Leigh Creek could be used for UCG. These reserves are unlikely to be economically recoverable by open pit or underground mining methods, and would support a 250 megawatts power station for approximately 25 years. The preliminary design laid out in the study is based on a gasification panel consisting of a coal seam 13 meters thick, with dip angle of 100 to 130, into which one blast air borehole and two production boreholes are drilled horizontally. Each panel is 400 meters long and 80 meters wide with the blast air borehole located along the central axis and the production bores spaced equally on either side.

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The blast air and production boreholes are drilled down dip using deviated drilling techniques. At the down dip end of the panel are located four vertical ignition bores equally spaced across the panel. A blast borehole in the seam has the great potential advantage that, provided that it does not burn back by reverse burn, it will always deliver the blast to the bottom of the active gasification zone. Project Cost: Approximately $1 billion (1983 Australian dollars) total capital costs *UNDERGROUND COAL GASIFICATION, ROCKY MOUNTAIN 1 TEST -- Amoco Production Company, Electric Power Research Institute, Gas Research Institute, Rocky Mountain Energy Company, and United States Department of Energy (C-1099) A field test of the Controlled Retracting Injection Point (CRIP) technology will be conducted In 1997 near Hanna, Wyoming. The test, named "Rocky Mountain 1," will be funded by the United States Department of Energy (DOE) and a four member industrial consortium. The consortium, headed by the Gas Research Institute, also includes the Electric Power Research Institute, Amoco Production Company Research Center, and Rocky Mountain Energy Company. The test will take place about two miles south of Henna, Wyoming, near a site used in the 1970s by the government to conduct some of the United States' first underground coal gasification tests. The CRIP technique was conceived by LLNL in the late 1970s to improve the efficiency, boost resource recovery, and increase the reliability of underground coal gasification. The CRIP method uses a horizontal well drilled along the base of a coal seam that is lined with a thin-walled metal pipe to supply oxygen to the coal to support the gasification process. To gasify the coal, successive sections of the well liner are burned away and the coal seam is ignited by & propane burner inserted In the horizontal well. The coal gasifies from the bottom of the seam upward producing medium-BTU gases. The gases are transported to the surface either through a second horizontal well near the top of the seam or through widely spaced vertical wells bored Into the coal seam. As sections of the coal scam gasify, a cavity forms and ultimately reaches the top of the seam. Then, the Ignition device Is moved, or "retracted," to a fresh section of coal, and the process is repeated. A 30 day field test of the CRIP technique was conducted in 1983 at an exposed coal face in the WIDCO coal mine near Centralia, Washington. The upcoming Rocky Mountain 1 test will create multiple cavities in two parallel rows 350 feet underground In a 30 foot thick subbituminous coal seam. One row will consist of a 300 foot long CRIP module. The other will use vertical injection wells similar to those in previous underground field tests. As much as 20,000 tons of coal-10,000 tons per row—could be gasified in the 100 day test. A companion effort will evaluate the ecological and environmental aspects of underground coal gasification. Construction for the test is to begin in late 1986 and is expected to be completed In approximately 12 months. Drilling of the horizontal wells through the 300 foot long section of the seam will take about two months. Actual gasification Is scheduled for late Summer 1987. Project Cost: $9.85 million UNDERGROUND GASIFICATION OF ANTHRACITE, SPRUCE CREEK —Spruce Creek Energy Company: a joint venture of Gilman Company, Geosystems Corporation, and Bradley Resources Corporation (C-hoe) Spruce Creek Is planning a test of underground gasification of anthracite at a site near Tremont in eastern Pennsylvania. The technology to be used will be similar to the gasification-of-steeply-dipping-beds technique used by Gulf at tests near Rawlins, Wyoming. The volatiles and sulfur content of the anthracite is low, thus reducing the costs of treating the product gas. Preliminary drilling at the site was originally scheduled for mid-1984, but permitting delays forced the drilling to be rescheduled for early spring 1986. The tests are expected to last until mid-1987. Project Cost: Not disclosed

UNDERGROUND COAL GASIFICATION, STEEPLY DIPPING BED DEMONSTRATION MODULE - Energy International, Inc., Stearns Catalytic Corporation, Rocky Mountain Energy Company (a subsidiary of Union Pacific Corporation), and United States Department of Energy (C-ills) This project involves a proof-of-concept/pilot demonstration of underground coal gasification (UCG) technology applied to the steeply dipping bed subbituminous coal deposits near Rawlins, Wyoming. The pilot demonstration will operate for 180 days, gasify 36,000 tons of coal, and produce up to 2,000 to 4,000 barrels of middle distillate liquids

4-93 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL CONVERSION PROJECTS (Underline denotes changes since June 1986) (Continued)

using a fixed bed indirect liquefaction technology. The demonstration represents one module of a commercial plant which would ultimately produce 4,000 barrels per day of liquids and 60 million standard cubic feet of substitute natural gas (SNG). The commercial plant will utilize underground coal gasification technology to produce a synthesis gas feedstock for a gas-to-liquids conversion for the production of middle distillates. The three year proposed demonstration project will provide the additional process, economic, and environmental data required to reach the commercialization decision. The project was selected by DOE for financial assistance in the Clean Coal Technology Program. Project Cost: Not disclosed

4-94 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 COMPLETED AND SUSPENDED PROJECTS

Project Sponsors Last Appearance in SPIt

A-C Valley Corporation Project A-C Valley Corporation June 1984, page 4-59 Acurex-Aerotherm Low-BTU Gasifier Acurex-Aerotherm Corporation September 1981; page 4-52 for Commercial Use Glen-Gery Corporation United States Department of Energy ADL Extractive Coking Process Arthur D. Little, Inc. March 1978; page 8-23 Development Foster-Wheeler United States Department of Energy Agglomerating Burner Project Battelle Memorial institute September 1978; page 3-22 United States Department of Energy Air Products Slagging Gasifier Air Products and Chemicals, Inc. September 1985; page 4-61 Project

Alabama Synthetic Fuels Project AMTAR inc. June 1984; page 4-60 Applied Energetics Inc. Amax Coal Ossification Plant AMAX, inc. March 1983; page 4-85 Arkansas Lignite Conversion Dow Chemical Company, December 1984; page 4-84 Project Electec Inc. International Paper Company Australian SRC Project CSR Ltd. September 1985, page 4-62 Mitsui Coal Development Pty, Ltd. Beacon Process Standard Oil Company (Ohio) March 1985, page 4-62 TRW, Inc. Bell High Mass Flux Gasifier Bell Aerospace Textron December 1981; page 4-72 Gas Research institute United States Department of Energy Beluga Methanol Project Cook inlet Region, Inc. December 1983; page 4-77 Placer U. S. Inc. 81-GAS Project United States Department of Energy March 1985, page 4-63 Breckinridge Project Bechtel Petroleum, inc. December 1983; page 4-78 Burnham Coal Gasification El Paso Natural Gas Company September 1983; page 4-62 Project Calderon Fixed-Bed Slagging Project Calderon Energy Company December 1985, page 4-73 Car-Mox Low-BTU Gasification Pike Chemicals, inc. March 1980; page 4-53 Project

Catalytic Coal Liquefaction Gulf Research and Development December 1978; page 8-25 Celanese Coastal Bend Project Celanese Corporation December 1982; page 4-83 Celanese East texas Project Celanese Corporation December 1982; page 4-83 Central Arkansas Energy Project Arkansas Power & Light Company June 1984; page 4-63 Central Maine Power Company Central Maine Power Company June 1984; page 4-63 Sears island Project General Electric Company Stone & Webster Engineering Texaco inc. Chemically Active Fluid Bed Central & Southwest Corporation (four December 1983; page 4-80 Project utility companies) Environmental Protection Agency (EPA) Foster Wheeler Energy Corporation Chemicals from Coal Dow Chemical USA March 1978; page 3-24 United States Department of Energy Cherokee Clean Fuels Project Bechtel Corporation September 1981; page 4-55 Mono Power Company Pacific Gas & Electric Company Rocky Mountain Energy

4-95 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance in SPa

Chesapeake Coal-Water Fuel ARC-COAL, Inc. March 1935; page 4-64 Project Bechtel Power Corporation COMCO of America, Inc. Dominion Resources, Inc. Chokecherry Project Energy Transition Corporation December 1983; page 4-91 Clark Synthesis Gas Project Clark Oil and Refining Corporation December 1992; page 4-85 Clean Coke Project United States Department of Energy December 1978; page 8-26 U.S. Steel USS Engineers and Consultants, Inc. Coalcon Project Union Carbide Corporation December 1978; page 8-26 Coalex Process Development Coalex Energy December 1978; page 8-26 COGAS Process Development COGAS Development Company, a joint December 1982; page 4-88 venture of: Consolidated Gas Supply Corporation FMC Corporation Panhandle Eastern Pipeline Company Tennessee Gas Pipeline Company Columbia Coal Gasification Columbia Gas System, Inc. September 1982; page 4-72 Project Combined Cycle Coal Gasification Consumer Energy Corporation December 1982; page 4-86 Energy Centers Composite Gasifier Project British Gas Corporation September 1981; page 4-56 British Department of Energy Conoco Pipeline Gas Demonstra- Conoco Coal Development Company September 1981; page 4-57 tion Plant Project Consolidated Gas Supply Company Electric Power Research Institute Gulf Mineral Resources Company Natural Gas Pipeline Co. of America Panhandle Eastern Pipeline Company Sun Gas Company Tennessee Gas Pipeline Company Texas Eastern Corporation Transcontinental Gas Pipeline Corporation United States Department of Energy Cresap Liquid Fuels Plant Fluor Engineers and Constructors December 1979; page 4-67 United States Department of Energy Crow Indian Coal Gasification Crow Indian Tribe December 1983; page 4-84 Project United States Department of Energy Crow Indian Coal-to-Gasoline Crow Indian Tribe September 1984; page C-8 Project TransWorld Resources CS/a Hydropyrolysis Process Cities Service Research & Development September 1981; page 4-58 Development Rockwell International DeSota County, Mississippi Mississippi Power and Light September 1981; page 4-58 Coal Project Mississippi, State of Ralph M. Parsons Company Dow Coal Liquefaction Process Dow Chemical Company December 1984; page 4-70 Development BUS Process Anaconda Minerals Company June 1985, page 4-83 ENI Electric Power Research Institute Exxon Company USA Japan Coal Liquefaction Development Co. Phillips Coal Company Ruhrkohle A.G. United States Department of Energy

4-96 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance in SP

Emery Coal Conversion Project Emery Synfuels Associates: December 1983; page 4-84 Mountain Fuel Supply Company Mono Power Company Enrecon Coal Gasifier Enrecon, Inc. September 1985, page 4-66 Exxon Catalytic Gasification Exxon Company USA December 1984; page 4-73 Process Development Fairmont Lamp Division Project Westinghouse Electric Corporation September 1982; page 4-76 Fast Fluid Bed Gasification Hydrocarbon Research, Inc. December 1982; page 4-90 United States Department of Energy FiatfAnsaldo Project Ansaldo March 1985; page 4-66 Fiat TTG 1(11W Energy Systems, Inc. Flash Pyrolysis Coal Occidential Research Corporation December 1982; page 4-91 Conversion United States Department of Energy Florida Power Combined Cycle Florida Power Corporation December 1983; page 4-87 Project United States Department of Energy Fuel Gas Demonstration Plant Foster-Wheeler Energy Corporation September 1980; page 4-68 Program United States Department of Energy Gas Turbine Systems Development Curtiss-Wright Corporation December 1983; page 4-87 United States Department of Energy General Electric Company Grants Coal to Methanol Project Energy Transition Corporation December 1983; page 4-89 Grefco Low-BTU Project General Refractories Company December 1983; page 4-91 United States Department of Energy Gulf States Utilities Project KRW Energy Systems March 1985, page 4-74 Gulf States Utilities Hampshire Gasoline Project Kaneb Services December 1983; page 4-91 Hoppers Company Metropolitan Life Insurance Company Northwestern Mutual Life Insurance H-Coal Pilot Plant Ashland Synthetic Fuels, Inc. December 1983; page 4-92 Conoco Coal Development Company Electric Power Research Institute Hydrocarbon Research Inc. Kentucky Energy Cabinet - Mobil Oil Corporation Ruhrkohle AG Standard Oil Company (Indiana) United States Department of Energy Hillsborough Day Coal-Water ARC-Coal Inc. September 1985; page 4-69 Fuel Project Bechtel Power Corporation COMCO of America, Inc. Howmet Aluminum Howmet Aluminum Corporation March 1985, page 4-74 H-R international Syngas Project H-a international, inc. December 1985, page 4-80 The Slagging Gasification Consortium Hydrogen from Coal Air Products and Chemicals, inc. December 1978; page B-31 United States Department of Energy HYGAS Pilot Plant Project Gas Research Institute December 1980; page 4-86 Institute of Gas Technology United States Department of Energy ICGG Pipeline Gas Demonstra- Illinois Coal Gasification Group September 1981; page 4-66 tion Plant Project United States Department of Energy

4-97 SYNTHETIC FUELS REPORT, SEPTEMBER 1996 Project Sponsors Last Appearance in SPa

I'll' Coal to Gasoline Plant International Telephone & Telegraph December 1981; page 4-93 J. W. Miller United States Department of Energy Kaiparowits Project Arizona Public Service March 1978; page B-IS San Diego Gas and Electric Southern California Edison Kennedy Space Center Polygeneration National Aeronautics & Space June 1986; page 4-85 Project Administration Ken-Tex Project Texas Gas Transmission Corporation December 1983; page 4-95 King-Wilkinson/Hoffman Project E. J. Hoffman March 1985, page 4-80 King-Wilkinson, Inc. Lake DeSmet SNG from Coal Texaco Inc. December 1982; page 4-98 Project Transwestern Coal Gasification Company Latrobe Valley Coal Lique- Rheinisehe Braunkohlwerke AG December 1983; page 4-96 faction Project LC-FlnIng Processing of SEC Cities Service Company December 1983; page 4-96 United States Department of Energy Liquefaction of Alberta Alberta/Canada Energy Resources March 1985, page 4-81 Subbituminous Coals, Canada Research Fund Alberta Research Council Low-BTU Gasifiers for Com- Irvin Industrial Development, Inc. June 1979; page 4-89 mercial Use-Irvin Industries Kentucky, Commonwealth of Project United States Department of Energy Low/Medium-BTU Gas for Multi- Bethlehem Steel Company December 1983; page 4-98 Company Steel Complex United States Department of Energy Inland Steel Company Jones & Laughlin Steel Company National Steel Company Northern Indiana Public Service Company Union Carbide Corporation Low-Rank Coal Liquefaction United States Department of Energy March 1984; page 4-49 Project University of North Dakota Lummus Coal Liquefaction Lummus Company June 1981; page 4-74 Development United States Department of Energy Mapco Coal-to-Methanol Project Mapco Synfuels December 1983; page 4-98 Mazingarbe Coal Gasification Project Cerchar (France) September 1985, page 4-73 European Economic Community Gas Development Corporation Institute of Gas Technology Medium-BTU Gas Project Columbia Coal Gasification September 1979; page 4-107 Medium-BTU Gasification Project Houston Natural Gas Corporation December 1983; page 4-99 Texaco Inc. Memphis Industrial Fuel Gas CBI Industries Inc. June 1984; page 4-79 Project Cives Corporation Foster Wheeler Corporation Great Lakes International Houston Natural Gas Corporation Ingersoll-Rand Company Memphis Light, Gas & Water Division Methanol from Coal UGI Corporation March 1978; page B-22 Methanol from Coal Wentworth Brothers, Inc. March 1980; page 4-58 (19 utility and industrial sponsors) Midrex Electrothermal Direct Georgetown Texas Steel Corporation September 1982; page 4-87 Reduction Process Midrex Corporation

4-98 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance in SFR

Millmerran Coal Liquefaction Australian Coal Corporation March 1985; page 4-82 Minnegasco High-Bit) Gas Minnesota Gas Company March 1983; page 4-108 from Peat United States Department of Energy Minnegasco Peat Biogasification Minnesota Gas Company December 1981; page 4-88 Project Northern Natural Gas Company United States Department of Energy Minnegasco Peat Gasification Gas Research Institute December 1983; page 4-101 Project Institute of Gas Technology Minnesota Gas Company Northern Natural Gas Company United States Department of Energy Mobil-M Project Mobil Oil Company September 1982; page 4-88 Molten Salt Process Development Rockwell International December 19831 page 4-101 United States Department of Energy Mulberry Coal-Water Fuel Project CoaLiquid, Inc. March 1985, page 4-85 NASA Lewis Research Center Coal-to- NASA Lewis Research Center Gas Polygeneratlon Power Plant December 1983; page 4-102 New England Energy Park Bechtel Power Corporation Deceibber 1983; page 4-104 Brooklyn Union Gas Company Eastern Gas & Fuel Associates EG&G Westinghouse Corporation United States Department of Energy New Jersey Coal-Water Fuel Ashland Oil, Inc. March 1985; page 4-86 Project Babcock & Wilcox Company Slurrytech, Inc. Nices Project Northwest Pipeline Corporation December 1983; page 4-104 North Alabama Coal to Methanol Air Products & Chemicals Company March 1985; page 4-86 Project Raymond International Inc. Tennessee Valley Authority North Dakota Synthetic Fuels InterNorth December 1983; page 4-106 Project Minnesota Gas Company Minnesota Power & Light Company Minnkota Power Cooperative Montana Dakota Utilities North Dakota Synthetic Fuels Group North Dakota Synthetic Fuels Project Northwestern Public Service Ottertail Power Company Wisconsin Power & Light Ohio I Coal Conversion Alberta Gas Chemicals, Inc. Marhc 1985; page 4-88 North American Coal Corporation Wentworth Brothers Ohio Valley Synthetic Fuels Consolidated Natural Gas System March 1982; page 4-68 Project . Standard Oil Company of Ohio Ott Hydrogeneratlon Process Carl A. Ott Engineering Company Project December 1983; page 4-107 Peat-by-Wire Project FEW Corporation March 1985; page 4-89 Peat Methanol Associates Project ETCO Methanol Inc. June 1984; page 4-85 J. B. Sunderland Peat Methanol Associates Transco Peat Methanol Company Penn/Sharon/Klockner Project Kleckner Kohlegas GmbH March 1985; page 4-72 Pennsylvania Engineering Corporation Sharon Steel Corporation

4-99 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance In SFR

Philadelphia Gas Works Synthesis Philadelphia Gas Works December 1983; page 4-108 Gas Plant United States Department or Energy Phillips Coal Gasification Phillips Coal Company September 1984; page C-28 Project Pike County Low-STU Gasifier Appalachian Regional Commission June 1981; page 4-78 for Commercial Use Kentucky, Commonwealth or United States Department of Energy Plasma Arc Torch Swindell-Dresser Company December 1978; pAge 9-33 Technology Application Service Corporation Port Sutton Coal-Water Fuel Project ARC-Coal, Inc. December 1985, page 4-86 COMCO of America, Inc. Powerton Project Commonwealth Edison March 1979; piée 4-86 Electric Power Research Institute Fluor Engineers and Constructors Illinois, State of United States Department of Energy Purged Carbons Project Integrated Carbons Corporation December 1983; page 4-108 Pyrolysis Demonstration Plant Kentucky, Commonwealth of December 1978; page 9-34 Occidental Research Corporation Tennessee Valley Authority Pyrolysis of Alberta Thermal Coals, Alberta/Canada Energy Resource March 1985, page 4-90 Canada Research Fund Alberta Research Council Riser Cracking of Coal Institute of Gas Technology December 1981; page 4-93 United Sates Department of Energy RIJHR100 Project Ruhrgas AG September 1984; pigs C-29 Ruhrkohle AG Steag AG West German Ministry of Research and Technology Saarbergwerke-Otto Gasification - Saarbergwerke AG June 1994; page 4-86 Process Dr. C. Otto & Company Savannah Coal-Water Fuel Projects Foster Wheeler Corporation September 1985, page 4-77 Sesco Project Solid Energy Systems Corporation December 1983; page 4-110 Sharon Steel Kleckner Kohlegas GmbH March 1985; page 4-92 Pennsylvania Engineering Corporation Sharon Steel Corporation Slagging Gasification Consortium Babcok Woodall-Duckham Ltd. September 1985; page 4-78 Project Big Three Industries, Inc. The BOC Group plc British Gas Corporation Consolidation Coal Company Sohio Lima Coal Gasification/ Sohio Alternate Energy Development March 1985; page 4-93 Ammonia Plant Retrofit Project Company Solution-Hydrogasification General Atomic Company September 1978; page 9-31 Process Development Stone & Webster Engineering Company Southern California Synthetic C. F. Braun March 1981; page 4-99 Fuels Energy System Pacific Lighting Corporation Southern California Edison Company Texaco Inc. Steam-Iron Project Gas Research Institute December 1978; page 8-35 Institute of Gas Technology United States Department of Energy

4-100 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance in SFR

Synthane Project United States Department of Energy December 1978; page 9-35 Synthoil Project Foster Wheeler Energy Corporation December 1978; page 9-36 United States Department of Energy Sweeny Coal-to-Fuel Gas Project The Signal Companies, Inc. March 1985; page 4-94 Tennessee Synfuels Associates Koppers Company, Inc. Mobil-M Plant December 1983; page 4-112

Transco Coal Gas Plant Transco Energy Company December 1933; page 4-113 United States Department of Energy Tri-State Project Kentucky Department of Energy December 1983; page 4-113 Texas Eastern Corporation Texas Gas Transmission Corporation United States Department of Energy TRW Coal Gasification Process TRW, Inc. December 1983; page 4-114 Two-Stage Entrained Gasification Combustion Engineering Inc. June 1984; page 4-91 System Electric Power Research institute United States Department of Energy Underground Coal Gasification United States Department of Energy June 1935, page 4-75 University of Texas Underground Coal Gasification, Alberta Research Council Canada September 1994; page C-37

Underground Coal Gasification, Rocky Mountain Energy Company June 1985, page 4-75 Hanna Project United States Department of Energy Underground Coal Gasification Lawrence Livermore Laboratory December 1983; page 4-119 Hoe Creek Project United States Department of Energy Underground Coal Gasification Mitchell Energy March 1985, page 4-98 Republic of Texas Coal Company Underground Coal Gasification ARCO December 1983; page 4-120 Rocky Hill Project Underground Gasification of Basic Resources, Inc. December 1993; page 4-121 Texas Lignite, Tennessee Colony Project Underground Gasification of Texas A & M University December 1983; page 4-121 Texas Lignite Underground Coal Gasification, In Situ Technology March 1985, page 4-102 Thunderbird II Project Wold-Jenkins Underground Coal Gasification, Sandia National Laboratories March 1983; page 4-124 Washington State UCG Site Selection and Characterization Underground Gasification of Basic Resources, Inc. March 1995, page 4-101 Texas Lignite, Lee County Project Union Carbide Coal Conversion Union Carbide/Linde Division June 1984; page 4-92 Project United States Department of Energy University of North Dakota United States Department of Energy June 1978; page B-33 University of Minnesota University of Minnesota March 1983; page 4-119 Low-BTU Gasifier for Commer- United States Department of Energy cial Use Utah Methanol Project Quester Synfuels Corporation December 1985, page 4-90 Verdigris Agrico Chemical Company September 1984; page C-35 Virginia PoNer Combined Cycle Project Consolidation Coal December 1985, page 4-90 Electric Power Research institute Slagging Gasification Consortium Virginia Electric and Power Company

4-101 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Project Sponsors Last Appearance in SPa

Watkins Project Cameron Engineers, Inc. March 1978; page 8-22 Westinghouse Advanced Coal KRW Energy Systems Inc. September 1985; page 4-80 Gasification System for Electric Power Generation Whitethorne Coal Gasification United Synfuels Inc. September 1984; page C-36. Wyoming Coal Conversion Project WyCoalcas, Inc. (a Panhandle Eastern December 1982; page 4-112 Company) Zinc halide Hydrocracking Conoco Coal Development Company June 1981; page 4-86 Process Development Shell Development Company

4-102 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 STATUS OF COAL PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

AECI Ltd. AECI Ammonia/Methanol Operations 4- 55 Coalplex Project 4- 59 AGA Nynas Energy Chemicals Complex 4- 79 Air Products and Chemicals, Inc. Laporte Liquid Phase Methanol Synthesis 4- 74 Solvent Refined Coal Demonstration Plant (SRC-I) 4- 83 A. Johnson & Company Nynas Energy Chemicals Complex 4- 79 Allis-Chalmers KILnGAS Project 4- 72 American Electric Power Service Corporation Tidd Pressurized Fluidized Bed Demonstration Project 4- 85 American Natural Service Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 Amerigas, Inc. Mining and Industrial Fuel Gas Group Gasifier 4- 76 Asia Oil Victoria Brown Coal Liquefaction Project 4-. 87 Australia, Federal Government of Victoria Brown Coal Liquefaction Project 4- 87 Bechtel Inc. Cool Water Coal Gasification Project 4- 60 Mining and Industrial Fuel Gas Group Gasifier 4- 76 Belgium, Government of Underground Coal Gasification, Joint Belgo-German Project 4- 90 Black, Sivalls & Bryson, Inc. Mining and Industrial Fuel Gas Group Gasifier 4- 76 BP United Kingdom, Ltd. Monash Hydroliquefaction Project 4- 77 Bradley Resources Corporation Underground Gasification of Anthracite, Spruce Creek 4- 93 British Department of Energy National Coal Board Liquid Solvent Extraction Project 4- 78 National Coal Board Low-BTU Coal Gasification Project 4- 78 British Gas Corporation Slagging Gasifier Project 4- 83 Broken Hilt Pty. Broken Hill Project 4 57 Brookhaven National Laboratory Flash Pyrolysis of Coal with Reactive and Non-Reactive Gases 4- 64 Brown Coal Liquefaction Pty. Ltd. Victoria Brown Coal Liquefaction Project 4- 87 Burlington Northern, Inc. Circle West Project 4- 59 Mining and Industrial Fuel Gas Group Gasifier 4- 76 Simplified IGCC Demonstration Project 4- 82 Bureau de Recherehes Geologiques Underground Coal Gasification of Deep Seams 4- 89 at Minieres

Carbon Gas Technology Huenxe CGT Coal Gasification Pilot Plant 4- 68 Caterpillar Tractor Company Caterpillar Tractor Low BTU Gas From Coal Project 4- 58 Central Illinois Light Co., Inc. KILnGAS Project - 4- 72 Charbonnages de France Underground Coal Gasification of Deep Seams 4- 89 Chem Systems, Inc. Laporte Liquid Phase Methanol Synthesis 4- 74

4-103 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

China National Technical Import Lu Nan Ammonia-from-Coal Project 4- 75 Corporation

Cities Service Integrated Two-Stage Liquefaction 4- 69 Cleveland-Cliffs Iron Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 Coal Gasification COGA-1 Project 4- 59

Coal Tech Corporation Cyclone Combustor Demonstration Project 4- 61 Companhia Auxillar de Empresas Underground Coal Gasification, Brazil 4- 88 Electricas Brasileiras Continental Energy Associates Can Do Project 4- 57

CRA (Australia) Kloechner Coal Gasifier 4- 73 Davy McKee Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 76 Deutsche Babcock AG Huenxe CGT Coal Gasification Pilot Plant 4-.68 DEVCO Scotia Coal Synfuels Project 4- 81 Dow Chemical Dow Gasification Process Development - 4- 61 Dow Syngas Project 4- 72 Drava Engineers and Constructors Mining and Industrial Fuel Gas Group Gasifier 4- 76 Underground Coal Gasification, Byrne Creek 4- 88 Ebasco Services, Inc. Chiriqui Grande Project 4- 58

Electric Power Research Institute Advanced Coal Liquefaction Pilot Plant 4- 55 Cool Water Coal Gasification Project 4- 60 KILnGAS Project 4- 72 Laporte Liquid Phase Methanol Synthesis 4- 74 Mining and Industrial Fuel Gas Group Gasifier 4- 76 Elgin Butler Brick Company National Synfuels Projects 4- 78

Empire State Electric Energy Cool Water Coal Gasification Project 4- 60 Research Corporation (ESEERCO) Simplified 10CC Demonstration Project 4- 82 Energy Adaptors Corporation Ohio-I Coal Conversion Project 4- 79 Energy and Environmental Research Gas Reburning Sorbent Injection Demonstration Project 4- 65 Corporation Energy Brothers Inc. K-Fuel Commercial Facility 4- 72 Energy Investment Inc. Underground Coal Gasification, Byrne Creek 4- 88

Energy Transition Corporation New Mexico Coal Pyrolysis Project 4- 78 European Economic Community Underground Coal Gasification, Joint Belgo-German Project 4- 90

Fluor Engineers and Constructors Laporte Liquid Phase Methanol Synthesis 4- 74

Ford, Bacon & Davis Mountain Fuel Coal Gasification Project 4- 77 Foster Wheeler Tennessee Inc. Elmwood Coal-Water Fuel Project 4- 63

4-104 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

Gallagher Asphalt Company Aqua-Black Coal-Water Fuel Project 4- 56 Gas Research Institute Gas Reburning Sorbent Injection Demonstration Project 4- 65

Gaz de France Underground Coal Gasification of Deep Seams 4- 89 Gelsenberg AG Huenxe CGT Coal Gasification Pilot Plant 4- 68 General Electric Company Appalachian Project 4- 56 Cool Water Coal Gasification Project 4- 60 10CC Simulation 4 69 Simplified 10CC Demonstration Project 4- 82 Geosysterns Corporation Underground Gasification of Anthracite, Spruce Creek 4- 93 Gesellschaft fur Kohle-Technologie PRENFLO Gasification Pilot Plant 4- 80 GfK Gesellsehaft fur Kohleverflussigung GFK Direct Liquefaction Project 4- 67 Gillespie, Alastair & Associates, Ltd. Scotia Coal Synfuels Project 4- 81 Oilman Company Underground Gasification of Anthracite, Spruce Creek 4- 93 Group d'Etudes de Is Gazeification Underground Coal Gasification of Deep Seams 4- 89 Souterraine (GEGS)

Gulf Canada Products Company Scotia Coal Synfuels Project 4- 81 Hanna Mining Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 Hoechst-Uhde Corporation Ohio-I Coal Conversion Project 4- 79 SRI Inc. Bbullated Bed Coal/Oil Co-Processing Prototype 4- 63 Idemitsu Kosan Victoria Brown Coal Liquefaction Project 4- 87 Illinois Power & Light Company KILnGAS Project 4- 72 Illinois, State of Gas Reburning Sorbent Injection Demonstration Project 4- 65 KILnGAS Project 4- 72 lnstitut Francais du Petrole Underground Coal Gasification of Deep Seams 4- 89 International Coal Refining Co. Solvent Refined Coal Demonstration Plant (SRC-l) 4- 83 Iowa Power & Light Company KILnGAS Project 4- 72 Japan, Government of Victoria Brown Coal Liquefaction Project 4- 87 Japan Cool Water Program Cool Water Gasification Project 4- 60 (JCWP) Partnership

Kellogg Company, The M. W. Appalachian Project 4- 56 Kellogg Rust Inc. Fularji Low BTU Gasifier 4- 64 KRW Energy Systems Inc. Advanced Coal Gasification 4- 74 - System for Electric Power Generation

Kentucky, Commonwealth of Solvent Refined Coal Demonstration Plant (SRC-l) 4- 83

KHD Industries Lulea Molten Iron Pilot Plant 4- 75

4-105 SYNTHETIC FUELS REPORT, SEPTEMBER 1988

C- Company or Organization Project Name Page

KILnGAS a & D, Inc. KILnOAS Project 4- 72 Klochner Kohlegas Kiochner Coal Gasifier 4- 73

Kobe Steel Victoria Brown Coal Liquefaction Project 4- 87 Krupp Koppers Libiaz Coal-to-Methanol Project 4- 75 KRW Energy Systems Inc. Appalachian Project 4- 56 Fularjl Low BTU Gasifier 4- 64 KRW Energy Systems Inc. Advanced Coal Gasification 4- 74 System for Electric Power Generation

Lawrence Livermore Laboratory Underground Coal Gasification - LLNL Studies 4- 91

Lummus Company Integrated Two-Stage Liquefaction 4- 89 Lurgi Kohle & Mineraloltechnik, GmbH Itheinbraun Ilydrogasification of Coal to SNG 4- 80 Manfred Nemitz Industrieverwaltung Huenxe COT Gasification Pilot Plant 4- 69

Meridian Minerals Company Circle West Project 4- 58 Ministry of Machine Building Industry Falarji Low BTU Gasifier 4- 64 Mitsubishi Chemical Industries Victoria Brown Coal Liquefaction PMject 4- 87 Monash University Monash Hydrolique faction Project 4- 77 Monongahela Power Company KILnGAS Project 4- 72 Morgantown Energy Technology Center Underground Coal Gasification - Bituminous Project 4- 91

Mountain Fuel Supply, Inc. Mountain Fuel Coal Gasification Process 4- 77 National Coal Board National Coal Board Liquid Solvent Extraction Project 4- 78 National Coal Board Low-BTU Coal Gasification Project 4- 78 Underground Coal Gasification English Midland Pilot Project 4- 89 National Synfuels Inc. National Synfuels Projects 4- 78

New Energy Development Organization Japanese Bituminous Coal Liquefaction Project 4- 71

New York State Energy Research & Simplified IGCC Demonstration Project 4- 82 Development Authority Niagara Mohawk Power Corporation Simplified IGCC Demonstration Project 4- 82 Nippon Brown Coal Liquefaction Co. Victoria Brown Coal Liquefaction Project 4- 87 Nissho Iwai Victoria Brown Coal Liquefaction Project 4- 87 Nitrogenous Fertilizers Industry SA Greek Lignite Gasification Complex 4- 68 Nokota Company Dunn Nokota Methanol Project 4- 62 North-Rhine Westphalia, State of Bottrop Direct Coal Liquefaction Pilot Plant 4- 57 Synthesegasanlage Ruhr (SAR) 4- 84 Texaco Coal Gasification Process 4- 85 NOVA Scotia Coal Synfuels Project 4- 81

4-106 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

Nova Scotia Resources Limited Scotia Coal Synfuels Project 4- 81

Ohio Coal Development Office Ebullated Bed Coal/Oil Co-Processing Prototype 4- 63 Edgewater Station LIMB Demonstration Project 4- 63 Tidd Pressurized Fluidized Bed Demonstration Project 4- 85 Ohio Department of Development Simplified 10CC Demonstration Project 4- 82 Ohio Edison Company KILnGAS Project 4- 72 Ohio Ontario Clean Fuels Inc. Ebullated Bed Coal/Oil Co-Processing Prototype 4- 63 Ohio Power Company Tidd Pressurized Fluidized Bed Demonstration Project 4- 85

Peabody Holding Company Simplified 10CC Demonstration Project 4- 82 Pennsylvania Electric Company Appalachian Project 4- 56 Pennsylvania Energy Development Authority Cyclone Combustor Demonstration Project 4- 61 State of

Pennsylvania Power and Light Company Cyclone Combustor Demonstration Project 4- 61 Peoples Natural Gas Company Mining and Industrial Fuel Gas Group Gasifier 4- 76

Petro-Canada Scotia Coal Synfuels Project 4- 81 Pickands Mather & Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 Polish Government Libiaz Coal-to-Methanol Project 4- 75 Potomac Edison Company KILnGAS Project 4- 72

Reserve Mining Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 Rheinische Braunkohlwerke Rheinbraun Hydrogasification of Coal to SNG 4- 80 Rheinbraun High Temperature Winkler Project 4- 80

Riley Stoker Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 76 Rockwell International Cities Service/Rockwell Process Development 4- 58 Rocky Mountain Energy Company Mining and Industrial Fuel Gas Group Gasifier 4- 76

Royal Dutch/Shell Group Shell Coal Gasification Project 4- 82

Ruhrkohle AG Texaco Coal Gasification Process 4- 85 Ruhrkohle Gel & Gas GmbH Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 57 Oberhausen Coal Gasification Project 4- 79 Synthesegasanlage Ruhr (SAR) 4- 84 Ruhrchemie AG Oberhausen Coal Gasification Project 4- 79 Synthesegasanlage Ruhr (SAlt) 4- 84 Texaco Coal Gasification Process 4- 85 Saarbergwerke AG GFK Direct Liquefaction Project 4- 67

Sasol Limited Sasol Two and Sasol Three 4- 81 Scrubgrass Associates Scrubgrass Project 4- 82

4-107 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

501 International LFC Coal Liquefaction/Cogeneration Plant 4- 75 Shanghai Wujing Chemical Corporation Wujing Trigeneration Project 4- 87 Shell Oil Company Shell Coal Gasification Project 4- 82 Signal Companies, The Keystone Project 4- 71 Sohlo Alternate Energy Development Cool Water Coal Gasification Project 4- 60 Company South Australia, Government of South Australian Coal Gasification Project 4- 84 Underground Coal Gasification, Leigh Creek 4- 92

Southern California Edison Cool Water Coal Gasification Project 4- 60 Cyclone Combustor Demonstration Project 4- 61

Spruce Creek Energy Company Underground Gasification of Anthracite, Spruce Creek 4- 93

Standard Havens, Inc. Aqua Black Coal-Water Fuel Project 4- 56 Stearns Catalytic Inc. Ebullated Bed Coal/Oil Co-Processing Prototype 4- 63 Stone & Webster Engineering Group Mining and Industrial Fuel Gas Group Gasifier 4- 76

Sumitomo Metal Industries, Inc. Lulea Molten Iron Pilot Plant 4- 75 Superfos Group Nynas Energy Chemical Complex 4- 79 Swedish Investment Bank Nynas Energy Chemicals Company 4- 79

Tenneco, Inc. SNG from Coal 4- 84 Tennessee Eastman Company Chemicals From Coal 4- 58 Texaco Inc. Cool Water Coal Gasification Project 4- 60 Texaco Coal Gasification Process 4- 85

TOSCO Corporation TOSCOAL Process Development 4- 85 Twin Cities Metallurgical Mining and Industrial Fuel Gas Group Gasifier 4- 76 Research Center TVA TVA Ammonia-From-Coal Project 4- 86 Ube Industries, Ltd. Ube Ammonia-from-Coal Plant 4- 86 Uhde GmbH Rheinbraun High Temperature Winkler Project 4- 80

Union Electric Company KILnGAS Project 4- 72 Union of Soviet Socialist Republics Kansak-Achinsk Basin Coal Liquefaction Pilot Plants 4- 71

University of Minnesota University of Minnesota Low-BTU Gasifier for Commercial Use 4- 87 University of North Dakota Gasification Environmental Studies 4- 65

USBM - Twin Cities Metallurgical Mining and Industrial Fuel Gas Group Gasifier 4- 76 Research Center United Coal Company Mild Gasification Process Demonstration Unit 4- 76

4-108 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 Company or Organization Project Name Page

United States Department of Energy Advanced Coal Liquefaction Pilot Plant 4 55 Appalachian Project 4 56 Cities Service/Rockwell Process Development 4- 58 Cyclone Combustor Demonstration Project 4- 61 Ebullated Bed Coal/OIL Co-Processing Prototype 4- 63 Edgewater Station LIMB Demonstration Project 4- 63 Flash Pyrolysis of Coal With Reactive and Non-Reactive Gases 4- 64 Gas Reburning Sorbent Injection Demonstration Project 4- 65 Great Plains Gasification Project 4- 67 Integraged Two-Stage Liquefaction 4- 69 KILnGAS Project 4- 73 Kahle Iron Reduction Process Demonstration Project 4- 73 KRW Advanced Coal Gasification System for Electric Power Generation 4- 74 Laporte Liquid Phase Methanol Synthesis 4- 74 Mild Gasification Process Demonstration Unit 4- 76 Mining and Industrial Fuel Gas Group Gasifier 4- 76 Mountain Fuel Coal Gasification Process 4- 77 Simplified IGCC Demonstration Project 4- 82 Solvent Refined Coal Demonstration Plant (SRC-I) 4- 83 Tidd Pressurized Fluidized Bed Demonstration Project 4- 85 University of Minnesota Low-BTU Gasifier for Commercial Use 4- 36 Underground Coal Gasification Brazil Project 4_ 39 Bituminous Coal Gasification Project 4- 91 United States Environmental Edgewater Station LIMB Demonstration Project 4- 63 Protection Agency

United States State Department Chiriqui Grande Project 4- 53 U.S. Steel Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 76

Veba Oil GmbH Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 57 Victoria, State Government of Victoria Brown Coal Liquefaction Project 4- 87 Weirton Steel Corporation Kohle Iron Reduction Process Demonstration Project 4- 73 Wentworth Brothers Inc. Ohio-1 Coal Conversion Project 4- 79

Western Energy Company Mining and Industrial Fuel Gas Group Gasifier 4- 76 West German Federal Government Kloeckner Coal Gasifier 4- 73 Texaco Coal Gasification Process 4- 85 Underground Coal Gasification, Joint Belgo-German Project 4- 90 West German Federal Ministry for Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 57 Research & Technology GRK Direct Liquefaction Project 4- 67 Rheinbraun High Temperature Winkler Project 4- 80 Rheinbraun Hydrogasification of Coal to SNG 4- 80 Synthesegasanlage Ruhr (SAR) 4- 73

West Penn Power Company KILnGAS Project 4- 86

Westinghouse Electric Appalachian Project 4- 56 KRW Advanced Coal Gasification System for Electric Power Generation 4- 74 Weyerhaeuser Mining and Industrial Fuel Gas Group Gasifier 4- 76

Wheelabrator-Frye Solvent Refined Coal Demonstration Plant (SRC-1) 4- 83

4-109 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 V. ______APPENDIX

Description of Clean Coal Projects Proposed to DOE 5- 1 APPENDIX

DESCRIPTION OF CLEAN COAL PROJECTS PROPOSED TO DOE

PROPOSAL CATEGORY lR$IOER: PROPOSER PROCESS IDENTIFICATION CAPACITY

07 AMERICAN MINERALS. INC. Cool reclaiming using conventional physical cleaning 1600 TPD FEED COAL 400 TPD PRODUCT PREPARATION 54 NORTH MARION DEW., INC/MADIFCO Cool reclaiming using conventional and advanced physical 30-80 'P11 ATtI cleaning and developmental flot6tian chemicals WASTE 16 STIRLING ENERGIES INC. Upgrading cool washing facilities. continous coke making NOT SPECIFIED RECOVERY 24 WESTERN ENERGY COMPANY Superheated steam drying and physical beneficiation of lignite 50 TPII and sub-bituminous cool 29 UNITED COAL COMPANY Cool reclaiming using advanced physical cool cleaning PROPRIETARY (microbubble flotation) 32 COMMUNITY CENTRAL ENERGY CORP. Physical cool cleaning (e.g.. dry electrostatics) to prepare 5 TPII cool for industrial boiler 33 ATLANTIC RESEARCH CORPORATION Microbial cool cleaning for sulfur and ash removal 24 TPD 38 COAL TEChNOLOGY CORP. Cool reclaiming using conventional physical cleaning 5000 TPD 42 MCaOWIELL DOUGLAS ENERGY SYS. Microbubble flotation coal beneficiatian S Tl'hI 52 CIIEMION CORPORATION Upgrading or coal quality by chemical extraction of NOw and SOw 5 TPII

ADVANCED 21 COMBUSTION ENGINEERING. INC. cetustion characterization of deep physical Cleaned cool 20 IPH COMBUSTION for utility PC boilers 23 UNIVERSITY OF FLORIDA tilt and gas reburning in conventional oil-fired industrial boiler 10 TPII with external combustor 26 TRW INC. Slogging combustor w/sarbent injection in bailer 69 We 38 COAL TECH. CORP. Slogging combustor w/sorbent injection in combustor I IPII

ATISPIIIRIC 08 CITY OF TALLAHASSEE Circulating AFO utility retrofit 250 Mile FLUIDIZED-BED 10 UNIVERSITY OF CINCINNATI Modified (swirling flow) circulating AFO for industrial steam 100,000 LaS! COMBUSTION HR STEAM 12 ENERa0TECHN0EOGy CORP. Coal cleaning coupled w/AFO retrofit to conventional PC boiler 60 TPII 13 COLORADO-UTE ELECTRIC ASSOC. Circulating AF0 utility retrofit 110 Me 27 COMMUNITY CENTRAL ENERGY CORP. Anthracite-culm fired AFO for industrial steam 130 TPD CULM - 36 CURATORS/UNIV. OF MISSOURI Bubbling LEO w/multisolids bed for industrial steam 200.000 LOS! hR STEAM 39 SOUTHWEST PUBLIC SERV. CO . Circulating Arm utility retrofit 250 lIsle

PRESSURIZED 04 AMERICAN ELECTRIC POWER SERV. PEP combined cycle utility retrofit 70 We FLUIDIZED-BED Ii PEP turbocharged cycle utility retrofit COMBUSTION WISCONSIN ELECTRIC POWER CO. 80 We

RilE GAS 03 THE DAOCOCIC & WILCOX CaI'AhlY LIMO extension and 'coolside' sorbent duct injection 506 We CLEANUP 17 NOISO CORPORATION Dry. simultaneousNow and SOx absorption S We 34 ENERGY I ENVIRONMENTAL RES. CORP. Gas reburning and sorbent Injection retrofit to utility boiler 117. 80. 40 We 40 RECOVERY SYSTEMS LIMITED Combined NOw and SO, removal with a phospate by-product 100 We 45 TENNESSEE VALLEY AUTHORITY Lime spray dryer/baghouse on eastern coal-fired boiler 150 Me 49 FMC CORPORATION NOw and S02 removal by injection of dry sodium compounds lao we 53 cHARWILL CORPORATION NOw and SOw reduction by wet scrubbing of stock gases with a NOT GIVEN borate solution

5-1 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

DESCRIPTION OF CLEAN COAL PROJECTS PROPOSED TO DOE (Continued) COAL TYPE ------ENERGY CONSUMPTION SECTOR ------START ENO DURATION UTILE- IICUS- C0*?CR- RESIDEN- TRANSPOR- sun- DATE DATE (NONTUIS) TIES TRIAL dAt TIAL TATION ANTHRACITE BITUMINOUS BITUMINOUS LIGNITE

9/30/68 9/30/93 84 P

9/1168 9/1/89 36 p P

OfT/OS 811/93 - 04 P 3/1/87 3/1/69 24

10/1/86 10/1/68 74 p '(low sulfur)

1/1187 3/1/69 26

p p 9/I/86 5/1/08 20 P P 6/30106 2/29/68 20 ' p 1011/86 7/1/90 45 0/15186 0/15/66 24 - p p

1011/86 10/1/89 36 4 P

9/1/86 9/1/89 36 p 4 P p p 4

10/1/87 10/1/90 36 P p 10/1/86 1/1/69 27 p p

10/1106 2/1/91 52 P p P p 6/11/86 8/11/89 36 P p

9/30/88 9130191 60 p p p p p 9/1/06 2/1/90 40 p p P P 10/1/86 10/1/89 36 p p (cus) p 10/1/86 10/1/07 12 p P p

8/1/66 1/1195 100 * P p

4/30/86 8/30/92 76 p 9/I/OS 9/1/94 84 ' p p

9/1/86 4/1/90 43 P 10/1/08 10/1/08 24 p p 1/1/07 1/1/91 40 1/2/67 312190 36 P P 1/1187 1211190 41 P 4 NOT GIVEN NOT GIVEN 2 * NOT GIVEN NOT GIVEN NOT GIVEN I

5-2 SYNTHETIC FUELS REPORT, SEPTEMBER 1986 DESCRIPTION OF CLEAN COAL PROJECTS PROPOSED TO DOE (Continued) PROPOSAL CAPACITY' CATEGORY NIflThR: PROPOSER PROCESS IDENTIFICATION

5.000 05dM GAS GASIFICATION 01 ELGIN BUTLER BRICK CO. Integration e( tour Clean tool technologies For power generation 750 LflS/ fIR DISTILLATE 200.000 IPY COKE for power generation from coke production gases 05 PENNSYLVANIA COAL 1(011. INC. clean gas II We 06 CONSOL-FW Fluid-bed gasifier. hot gos cleanup integrated combined cycle 30 l'IWe system 200.000 11)5/ DR STEAM gos production and hot gas 50 NYc 09 CALDERON ENERGY COMPANY Fixed-bed coking/go.ificati011 for (1101 cleanup combined cycle 60 NYc 09 THE M.W. KELLOGG COAWANY Fluid-be'1 gasifier. hot gos cleanup integrated combined cycle ty.teul 70 lIn 010/1111 BRAVO WELtMAN CO. Clean low-Otu fuel gos from cool 30 100 itlI 010/1111 30 SANITECII, INC. Moving grate gasifier for fuel gas production Entrained-bed gasifier w/cold cleanup for fuel go. and methanol 30 IPO 46 GUESTAR SYNFIJELS CORPORATION —m production SO We; S Me 48 GENERAL ELECTRIC C0fANY Fixed-bed go.ifier, hot gos cleanup with advanced turbine for electricity production

50 KWe GASIFICATION! 37 ZTEC CORPORATION Solid oxide rirconia fuel cell for eventual integration Into cool FUEL gasifier. 375 KWe CELLS AT PPO INDUSTRIES Phosphoric acid fuel cell fueled by hydrogen 1.5 Me 43 WESTINGhOUSE ELECTRIC CORP. Phosphoric odd fuel cell coupled w/coal-derived fuel go.

200 TPD IN-SITU 20 ENERGY INTERNATIONAL, INC. Steeply-dipping bed underground go.ificatlon integrated GASIFICATION wfindirect liquefaction

11,150 BPD LIQUEFACTION 25 01110 ONTARIO CLEAN FUELS INC. Cool-oil ca-processing to produce refinery product. DISTILLATE 10 TPD 44 CIIEICOAL ASSOCIATES coal liquefaction under mild catalytic conditions using phenolic solvent 55 TPO METHANOL 47 TENNESSEE VALLEY AUTIIORITY Entrained-bed gasifier w/cold cleanup coupled with liquid-phase methanol production for peaking

Direct iron ore reduction to replace coke oven/blast furnace ' 330, coo TPY IRON IPOIJSTRIAL 02 STATE OF MINNESOTA 60 IPO SILICON DOW CORNING CORPOIOATIOPI Waste energy and byproduct recovery PROCESSES IS ALLOY 'ei/blast furnace , 330,000 IPY IRON 22 WEIRTON STEEL CORPORATION Direct iron are reduction to replace coke iv

Compressed air energy storage for electric utility peaking power 50 NYc OTHER 05 CLEVELAND ELEC. ILLUMINATING CO. N/A 51 NATIONAL LIPE ASSOCIATION General support of technologies utilizing lime

5-3 SYNTHETIC FUELS REPORT, SEPTEMBER 1986

DESCRIPTION OF CLEAN COAL PROJECTS PROPOSED TO DOE (Continued) COAL TYPE ENERGY CONSI$WTION SECTOR ------START END DURATION UUhT- PIOUS- COMER- RESIDEN- TRANSPOR DATE DATE (MONTHS) TIES TRIAL CIAL TIAL TATION ANTHRACITE OITUNLNOUS OLTUMINOUSlull LIGNITE

GO AHEAD 42

9/15/98 7/15/90 45

11I/87 1/1/90 56 0 0 p 0

6/1/88 6/1/92 72 p 10/1/86 1/1/90 63 * 913/66 411/90 42 * 10/1/86 10/1/89 36 * p p 7/1/86 7/1/90 40 1/2/07 1/2/92 60

1906 1992 72 I P 9/2/06 9/2192 72 9/1/86 11(1/90 50 0

9/15/88 9/15/89 36 P P P

8/1/86 12/1/90 52 I

0/1/06 0/1190 48 P I P P 0 10/1186 3/1/90 41 *

1/1/87 2/1/93 73 • All cools if bI.nd.d for Low volotil. piotter I/i/O? 811194 04 P

1/1/87 9/1/91 56 p All coolu if bl.nd,d for low yolatil. oiottpr

11/1/86 11/1/93 84 P 0 N/A N/A N/A N/A N/A N/A N/A

5-4 SYNTHETIC FUELS REPORT, SEPTEMBER 1986