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VOLUME 23 - NUMBER 4 — DECEMBER 1986

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Em Reposiro J:urLpfrng Library

0 THE PACE CONSULTANTS INC.

®Reg. U.S. Pt. OFF. Pace Synthetic 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 ; reproduction of any part of the publication requires the express permission of The Pace Con- sultants Inc. The Pace Consultants Inc., has provided energy consulting and engineering services since 1955. The company's experience includes resource evalua- tion, 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

MANAGING EDITOR Jerry E. Sinor Past Office Box 649 Niwot, 80544 (303) 652-2632

BUSINESS MANAGER Ronald L. Gist Post Office Box 53473 , 77052 (713) 669-8800 Telex: 77-4350 CONTENTS

HIGHLIGHTS A-i

I. GENERAL

CORPORATIONS

Import Fee Gathers Support 1-1 API Accepts Concept of Import Fee 1-2

GOVERNMENT

Western Governors Urge Import Fee 1-3 DOE Synfuels Budget Cut 22% for 1087 1-3 Department of Energy Promotes Cooperative Ventures 1-3

ENERGY POLICY AND FORECASTS

Chemical Engineers Push for Synthetic Fuels Funding 1-5 G RI Forecast Features Adequate Gas Supplies at Lower Prices 1-5 Bankers Trust Forecasts New High in Oil Imports 1-6 Conoco Forecast Sees Continuing Fall in U.S. Domestic Oil Supply 1-7

TECHNOLOGY

Methanol to Ethanol Route May have Advantages i-lU

INTERNATIONAL IEP and Idemitsu Kosan Report Process for Higher Alcohols from Syngas 1-12 Japan's RAPAD Reports R&D Progress in Synthetic Fuels 1-13

ENVIRONMENT

Chemical Basis for Mutagenicity in Synthetic Fuels Traced 1-18 BLM Proposes New Procedures for Areas of Critical Environmental Concern 1-20

RESOURCE

IGT Calculates World Reserves of Fuels 1-23

RECENT GENERAL PUBLICATIONS/PATENTS 1-26

COMING EVENTS 1-27 II.

PROJECT ACTIVITIES

Eastern Oil Shale Project Completes Blast Test 2-1 Cliffs Engineering, Allis-Chalmers Complete Indiana Cost Estimate 2-1 Unocal Restarts Parachute Creek Plant After Turnaround 2-2 White River Project Turned Over to BLM 2-3

SYNTHETIC FUELS REPORT, DECEMBER 1986 CORPORATIONS

New Oil Shale Development Corporation Formed 2-4 New Oil Shale Association Formed 2-4 GOVERNMENT

DOE Oil Shale Program Focuses on Year 2000 Feasibility 25 TECHNOLOGY

Phillips Patents Recycle Retorting System 2-8 Additives Increase Yield from Beneficiated Shale 2-0 Effect of Nitrogen on FCC Catalysts Clarified 2-13 Patent Issued for Retorting Process Using Coal 2-14 INTERNATIONAL

Petrosix Studies Fluid Bed of Retorted Shale 2-17 SPP/CPM Excavate Bulk Sample of Stuart Oil Shale for Testing 2-18 Ships Oil Shale to China 2-18 Israel Electric Joins Oil Shale Power Plant Project 2-18 Oil Shale Pyrolyzed in Spouted Bed 2-18 Combustion of Australian Spent Compared 2-20 ENVIRONMENT

BL M Issues Final EIS for Tract C-a Offsite Lease 2-21 Draft ElS Issued for Wolf Ridge Mine 2-26 Colorado Wildlife Commission Approves Wildlife Mitigation Banking 2-30 BLM to Prepare New Wilderness EIS in Northwest Colorado 2-30 WATER

Compromise Developed to Protect Endangered Fish in Colorado River 2-32 RESOURCE

Court Supports Ute Tribe in Case 2-34 New Paraho Corporation Sets Utah Land Exchange 2-34 Oil Shale Land Transfers Finalized 2-35

RECENT OIL SHALE PUBLICATIONS/PATENTS 2-37

STATUS OF OIL SHALE PROJECTS 2-42 III. OIL SANDS

PROJECT ACTIVITIES

PanCanadian Frog Project Detailed 3-1 AOSTRA Gets Underground Drill Rig 3-2 Shell Dedicates Peace River Expansion Project 32 Government Assistance Finalized for Biprovincial 3-3 Syncrude May Delay Completion of Expansion 3-3 CORPORATIONS

Solv-Ex Details Process Development Activities 3-4 ORS Corporation Reports Progress on Projects 3-5 Suncor Sees Loss in Oil Sands, Shelves Burnt Lake 3-6 Shell Canada Notes Drop in Earnings 3-6

ii SYNTHETIC FUELS REPORT, DECEMBER 1986 Re-Structured Gull Canada Shows Changes in Earnings 3-7 Oleophilic Sieve Seeks Interest in Public Offering 3-8 GOVERNMENT

DOE Small Business Program Solicits EOR and Tar Sands Projects 3-11 Alberta Provides Aid Package for Oil Industry 3-12 AOSTRA Issues Ten-Year Review 3-12

ENERGY POLICY & FORECASTS

Unitar Sees Favorable Outlook for Heavy Crude and Tar Sands 3-13 Suncor Estimates Operating Costs at C820/Barrel 3-14

ECONOMICS

Heat Pipe Process Could Produce Syncrude for Operating Cost of 513.32/13111, 3-16 Lewin Estimates Two Billion Barrels of U.S. Tar Sand Recoverable at Mid $ 2 0fRB L 3-19 TECHNOLOGY

In Situ Hydrogenation Process Developed by WorldEnergy Systems 3-22 Horizontal Well Technology Advances 3-25 Heavy Liquid Beneficiation Developed for Alabama Tar Sands 3-30 Texaco Patents Horizontal Well Technique 3-31

INTERNATIONAL

China Shows Increasing Interest in Heavy Oil and Oil Sands 3-34 WATER

Water Treatment Needs Calculated for In Situ Tar Sands Production 3-36 RESOURCE

Tar Sands Units Dissolved, Formed 338 Utah Tar Sands Resources to Be Mapped 3-38 Trapper Canyon Deposit Illustrates Travails of Tar Sand Development 3-38

RECENT OIL SANDS PUBLICATIONS/PATENTS 3-41

STATUS OF OIL SANDS PROJECTS 3-43

IV. COAL

PROJECT ACTIVITIES

Second Phase of KILnGAS RAM Program to Be Completed in December 1986 4-1 Dow Syngas Project on Schedule for 1907 Start Up 43 Shell Coal Gasification Process to Start Up in 1987 4-5 Cool Water Program Passes Half-Way Point 4-6 Rheinbraun High-Temperature Winkler Plant Starts Up 4_8 PRENFLO Gasifier Starts Up in August 4-9 Scotia Synfuels to Buy Nova Scotia Refinery 4-11 CORPORATIONS

Sasol Reports Increase in Profit for 1985-86 4-12 SGI Montana Project Delayed, Others Planned 4-13 Coal Extraction Research Center Reports Successful Year 4-14

iii SYNTHETIC FUELS REPORT, DECEMBER 1986 G u V E K N M ENT

DOE Solicits Interest in Coal R&D Activities 4-16

ENERGY POLICY & FORECASTS

10CC to Be Favored Option for Utility Power Plants 4-17 ECONOMICS

Uses Found for Gasification Slag 4-20 Army Studies Economics of Coal Gasification/ Cell 4-22

TECHNOLOGY

SCI's LFC Process Planned for Scaleups 4-27 IGT Tests Internally Recirculated Gasification Catalyst 4-3t) Improved Sulfur Removal Processes Evaluated for 10CC 4-32 r,i PG International to ri arket Kinetic Extruder 4-34 INTERNATIONAL

MIP Process Tests Coal Gasification in Liquid Bath 4_37 USSR Sees Advantages for Fluid fled and Underground Coal Gasifiers 4-38 USSR Studies Plasmatron Coal Gasification Process 4-39 Nynacs Gasification Complex Hit with Setbacks 4-39 South Australia to Build High-Temperature Winkler Gasifier 4-40 Israeli Co-Retorting of Coal and Oil Shale Would Break Even at $22/Barrel 4-40 ENVIRONMENT

EPA Questions Whether Clean Coal Awards Meet Acid Rain Criteria 4-41 EPA Relaxes Waiver on Methanol/ Blends 4-42 EPA Proposes Emission Standards for Methanol Vehicles 4-43 EPA Develops Low-BTU Gasification Wastewater Document 4-44 RESOURCE

Ten Year Deadline on Federal Coal Leases Expires December 31, 1986 4-45

RECENT COAL PUBLICATIONS/PATENTS 4-46

STATUS OF COAL PROJECTS 4-53 V. APPENDIX

Terms and Conditions of Sodium Leases 5-1

iv SYNTHETIC FUELS REPORT, DECEMBER 1986 HIGHLIGHTS

Capsule Summaries of the More Significant Articles in this Issue

Import Fee Gathers Support

A growing number of companies and organizations representing the oil and gas industry appear to be changing their historic opposition to government involvement in oil pricing. Several have either endorsed or accepted the idea of a fee on imported oil. The articles on page 1-1 to 1-3 sum- marize some of the policy statements which have been made recently.

DOE Synfuels Budget Cut 22% for 1987

Fiscal year 1987 funding for synthetic fuels research and development in the U.S. Department of Energy was cut 22 percent from 1986 levels. A summary Table appears on page 1-3.

Department of Energy Promotes Cooperative Ventures

The U.S. Department of Energy held a meeting in Denver in November to solicit public input on the concept of cooperative funding for research in fossil fuels. About 140 people attended, indicating a reasonable level of interest in the concept (page 1-3).

GRI Forecast Features Adequate Gas Supplies at Lower Prices

The Gas Research Institute's 1986 forecast of U.S. and demand to 2010 predicts United States gas consumption to rise to almost 19 quads by the year 2000. A summary of the complete forecast is gi.'en on page 1-5.

Bankers Trust Forecasts New High in Oil Imports

Bankers Trust Company foresees United States imports rising from 4.3 mil- lion barrels per day in 1985 to 10 million barrels per day by 1995. This increased dependence on foreign sources of supply represents a clear threat to the nation's military and economic security (page 1-6).

Conoco Forecast Sees Continuing Fall in U.S. Domestic Oil Supply

Conoco's new "World Energy Outlook Through 2000" notes that the major effect of lower oil prices in the near term will be increased reliance on imports to satisfy United States energy demand. A digest of the complete forecast is presented on page 1-7.

Eastern Shale In Situ Project Completes Blast Test

Eastern Shale Research Corporation has blasted an underground horizontal

A-i in situ retort at a test site in Indiana. Evaluation of the blast results will determine whether to attempt ignition of this retort (page 2-1).

Cliffs Engineering, Allis-Chalmers Complete Indiana Cost Estimate

Cliffs Engineering and Allis-Chalmers have completed a cost estimate for a 600 barrel per oil shale demonstration plant in Southern Indiana. Total project cost, including 18 months of operation, would be $73,000,000. Details on page 2-1.

Unocal Restarts Parachute Creek Plant After Turnaround

In late November, Unocal restarted its Parachute Creek oil shale project after a two-month maintenance overhaul. The plant was again operating at about 50 percent capacity at last word. Other news concerning the project can be found on page 2-2.

White River Project Turned Over to fiLM

In late September, the White River Shale Project in Utah was formally turned over to the Bureau of Land Management. As explained on page 2- 3, the project sponsors are now relieved of all reclamation obligations concerning the lease.

New Oil Shale Association Formed

A new national Oil Shale Association has been formed to promote the development of an . The organization will maintain a Washington, D. C. representative to shepherd oil shale interests in the Capitol. See page 2-4 for information on joining.

Additives Increase Yield From Beneficiated Shale

The University of Alabama Mineral Resources Institute has studied a process involving the fine grinding of oil shale, beneficiation by froth flotation, and briquetting for retorting. As described on page 2-9, they have found that certain additives for improving briquette properties can also improve retorting yield. Effect of Nitrogen on FCC Catalysts Clarified

Research at Unocal Corporation has compared the performance of several commercial FCC catalysts using a blended /vacuum gas oil feedstock (page 2-13).

Petrosj.x Studies Fluid Bed Combustion of Retorted Shale

The oil shale project in Brazil has recently completed the design of a circulating fluidized bed combustor. As noted on page 2-17, the combustor could be used both to burn the on , and to burn shale fines which cannot be fed to the retort.

A-2 SPP/CPM Excavate Bulk Sample of Stuart Oil Shale for Testing

A sample of Creek oil shale from the Stuart deposit in Australia has been shipped to Calgary, Alberta, Canada for testing in the Taciuk retorting process (page 2-18).

BLM Issues Final EIS for Tract C-a Offsite Lease

The U.S. Bureau of Land Management has issued the Final Environmental Impact Statement on Rio Blanco Oil Shale Company's request to lease an offtract site for disposal of overburden and spent shale from Tract C-a. The Agency's Preferred Alternative for a disposal site is 84 Mesa. The rationale for this choice is explained on page 2-21.

Draft EIS Issued for Wolf Ridge Nahcolite Mine

The U.S. Bureau of Land Management has issued a Draft Environmental Impact Statement for Wolf Ridge Mineral Corporation's proposed nahcolite solution mine in northwest Colorado. A description of the proposed project is given on page 2-26, and terms of the sodium mineral leases in- volved may be found in the Appendix.

Court Supports Tribe in Utah Case

The U.S. Supreme Court has refused to review a U.S. Tenth Circuit Court of Appeals decision which gives the Ute Indian Tribe jurisdiction over much of the richest oil shale resources in the State of Utah. See page 2- 34.

Shale Land Transfers Finalized

The U.S. Bureau of Land Management agreed to issue patents on some 82,000 acres of oil shale claims in Colorado. These are pre-1920 claims which have been under litigation for decades. A summary Table of the lands involved is presented on page 2-35.

PanCanadian Frog Lake Project Detailed

PanCanadian Ltd is delaying its cyclic steam in situ bitumen recovery project in the Frog Lake area of Alberta's Cold Lake deposit. Details on the stalled project are given on page 3-1.

AOSTRA Gets Underground Drill Rig

The Alberta Oil Sands Technology and Research Authority has taken delivery of an underground horizontal well drilling rig to be used at its Underground Test Facility (page 3-2).

Shell Dedicates Peace River Expansion Project

Shell Canada Limited officially opened its Peace River Expansion Project,

A-3 which will produce 10,000 barrels of bitumen per day. The $200 million project finished ahead of schedule and under budget. See page 3-2.

Government Assistance Finalized for Biprovincial Upgrader

The government of Canada approved a remission of Petroleum Gas Revenue Taxes to help fund ongoing engineering studies of the Biprovincial Upgrader Project sponsored by Husky Oil Operations Ltd. A decision on whether to proceed with the project is expected in early 1987 (page 3-3).

DOE Small Business Program Solicits EOR and Tar Sands Projects

The U.S. Department of Energy has invited small business firms to submit proposals for its fifth annual solicitation in the Small Business Innovation Research program. A summary of the solicitation's tar sands related sec- tions is given on page 3-11. UNITAR Sees Favorable Outlook for Heavy Crude and Tar Sands

In a presentation to the Eastern Oil Shale Symposium, R. Omaha of UNITAR noted a number of factors favorable to future development of heavy crude and tar sands resources. An abstract of his remarks is given on page 3-13. Suncor Estimates Operating Costs at C$20/Barrel

In testimony before the Standing Senate Committee on Energy and Natural Resources in Canada, T. Thomson, president of Suncor Inc., discussed the question of the break-even cost of operating Suncor's oil sands and extraction plant. A summary of his testimony is presented on page 3-14.

Trapper Canyon Deposit Illustrates Travails of Tar Sand Development

A history of attempts to put together a project in the Trapper Canyon tar sand deposit in Big Horn County, illustrates the complex dif- ficulties in attempting to develop such a resource on federal lands outside a designated Special Tar Sands Area. See page 3-38.

Heat Pipe Process Could Produce Syncrude for Operating Cost of $13.32/Barrel

Work at the University of Utah has focused on a two-stage fluidized bed process utilizing heat pipes for retorting Utah tar sands. A summary of the estimated economics for this process is presented on page 3-16.

Lewin Estimates 2 Billion Barrels of U.S. Tar Sand Bitumen Recoverable At Mid $20/BBL

Lewin and Associates has estimated the amount of bitumen recoverable from U.S. tar sands deposits as a function of market price for the bitumen. Both and extraction, and in situ steam soak methods were considered. Results are tabulated on page 3-19. A-4 China Shows Increasing Interest in Heavy Oil and Oil Sands

Several cooperative undertakings between China and Canadian and United States groups have emerged in the last year. A discussion of these agreements plus an outline of China's heavy oil and oil sands deposits begins on page 3-34.

Solv-Ex Details Process Development Activities

Solv-Ex Corporation is involved in a major project study with Shell Canada Limited. Details of the project agreement, and other Solv-Ex activities are given on page 3-4.

OHS Corporation Reports Progress on Projects

ORS and its subsidiary, Uentech Corporation, are installing their downhole electromagnetic well stimulation devices in a number of locations around the world. A summary of these activities starts on page 3-5.

Suncor Sees Loss in Oil Sands, Shelves Burnt Lake

In the first nine months of 1986, the Oil Sands Group of Suncor Inc. reported a loss of $12 million. Abstracts from the nine-month quarterly report are given on page 3-6.

Oleophilic Sieve Seeks Interest in Public Offering

Oleophilic Sieve Development of Canada Ltd is seeking expressions of in- terest in financing the next stage of development of the Oleophilic Sieve Process for separation of bitumen from oil sands and water. The current status of the process is described on page 3-8.

In Situ Hydrogenation Process Developed by WorldEnergy Systems

WorldEnergy Systems has been working on a technique for in situ hydrogenation of tar sands bitumen to upgrade it in place and make it more easily producible. The concept is explained on page 3-22.

Horizontal Well Technology Advances

The technology of drilling long horizontal wells, either for gravity drainage alone, or for steam-assisted processes, has advanced considerably in recent years. A broad review of the current state-of-the-art begins on page 3- 25.

Heavy Liquid Beneficiation Developed for Alabama Tar Sands

The Mineral Resources Institute of the University of Alabama has developed a conceptual approach for the beneficiation and separation of bitumen from Alabama deposits using a heavy media sink-float separation. Experimental results are presented on page 3-30.

A-5 Ten Year Deadline on Federal Coal Leases Expires December 31, 1986

Section 3 of the Federal Coal Leasing Act Amendments of 1976 prohibits any company who has had a non-producing Federal coal lease for ten years from obtaining any leases for any other minerals including oil and gas. Thus, as of December 31, 1986, many companies will have to either give up their inactive coal leases or be prohibited from any other leasing ac- tivities. See page 4-45 for details.

MIP Process Tests Coal Gasification in Liquid Iron Bath

KHD Humboldt Wedag and Sumitomo Metal Industries are operating a coal gasification pilot plant using a liquid iron bath. The pilot, located in Sweden, was scheduled to be in operation in November, 1986 (page 4-37).

USSR Sees Advantages for Fluid Bed and Underground Coal Cashiers

Calculations by the U.S.S.R. Institute for Mineral Fuels show fluidized bed gasification to be cheaper than Lurgi fixed bed gasification. They also show the generation of power by underground coal gasification to be cheaper than by conventional coal combustion (page 4-38).

Nynaes Gasification Complex Hit with Setbacks

The Nynaes energy-chemicals complex in Sweden has lost one of its spon- sors, and is changing its configuration. As noted on page 4-39, the design for the complex is cutting back on the amount of chemicals to be produced and adding .

South Australia to Build High Temperature Winkler Gasifier

The government of South Australia has selected the Rheinbraun High Tem- perature Winkler process for the gasification stage of a combined cycle electric (page 4-40).

Israeli Co-Retorting of Coal and Oil Shale Would Break Even at $22/Barrel

Work under way at the Hebrew University of Jerusalem is testing the co- retorting of coal and oil shale in a fluidized bed. As stated on page 4-40, the break-even market price for oil from the process is estimated to be $22/barrel.

IGCC to be Favored Option for Utility Power Plants

Cost estimates prepared by the Research Institute (page 4- 17) show a slight cost advantage for phased construction of integrated gasification combined cycle systems over other utility power plant options. There is, however, a large advantage with respect to environmental emis- sions.

A-6 DOE Solicits Interest in Coal R&D Activities

The U.S. Department of Energy's Morgantown Energy Technology Center released a list of research ideas that it is considering funding. Public comment on the appropriateness of the list, reproduced on page 4-16, is being solicited.

SGI Montana Project Delayed, Others Planned

SGI International and Dravo Corporation have filed plans with the Federal Energy Regulatory Commission to develop a dozen or more 50 to 100 megawatt cogeneration projects involving partial liquefaction by coal . A list of the filing can be found on page 4-13.

Dow Syngas Project on Schedule for 1987 Stan Up

Dow Chemical Company's 2,400 per day Dow Syngas Project is progressing on schedule for a start up in April 1987. A project status report is given on page 4-3.

Shell Coal Gasification Process to Stan Up in 1987

Shell Oil Company's 250 ton per day coal gasification system, under con- struction at its Deer Park manufacturing complex near Houston, is due to start up some time after March, 1987. A project status report is given on page 4-5.

Rheinbraun High-Temperature Winkler Plant Starts Up

The High-Temperature Winkler demonstration plant constructed by Rheinische Braunkohlenwerke AG started up in the first half of 1986. A discussion of results and operating problems begins on page 4-8.

PRENFLO Gasification Starts Up in August

GICT's PRENFLO coal gasification pilot plant at Fuerstenhausen, West Germany, started up in August, 1986. A description of the process and project is given on page 4-9.

Army Studies Economies of Coat Gasification/Fuel Cell Cogeneration

The U.S. Department of the Army is interested in coal gasification/fuel cell cogeneration systems for supplying heat and power at military instal- lations. A study by Ebasco Services, summarized on page 4-22, analyzed sites in , Alaska, Texas, and Washington, D.C.

SGI's LFC Process Planned for Scaleups

SW has developed a process using low temperature pyrolysis for extracting liquids from coal (LFC) and producing an improved solid fuel. A descrip- tion of the LFC process and development program begins on page 4-27.

A-7 IGT Tests Internally Recirculated Gasification Catalyst The Institute of Gas Technology has tested an internally circulated gasification catalyst, which evaporates in the combustion section and con- denses in the feed section of a coal gasifier, eliminating the need for an external catalyst separation and recycle system. The concept is explained on page 4-30. Improved Sulfur Removal Processes Evaluated for IGCC An Electric Power Research Institute study finds that new, improved sulfur removal and recovery processes are now available which would have advan- tages over the technology used in the Cool Water Demonstration Plant. See page 4-32 for a complete discussion. EPA Questions Whether Clean Coal Awards Meet Acid Rain Criteria The U.S. Environmental Protection Agency has questioned whether the first round of awards under the Department of Energy's Clean Coal Technology program will provide any help in solving the acid rain problems. They have reported (page 4-41) that only one of the nine projects meets all of the criteria set forth in the United States/ Canada Special Envoy's report on acid rain. EPA Relaxes Waiver on Methanol/Gasoline Blends The U.S. Environmental Protection Agency has removed a restrictive evaporative index requirement which had been imposed on the "DuPont waiver". Now the methanol blend only has to meet the same requirements as regular unleaded gasoline (page 4-42). EPA Proposes Emission Standards for Methanol Vehicles The U.S. Environmental Protection Agency has issued proposed pollution control standards for methanol fueled vehicles. These standards, applying to engine exhaust and to evaporative losses, are summarized on page 4-44.

A-8 \ srn='fneJLs: general CORPORATIONS

IMPORT FEE GATHERS SUPPORT reflect the true cost of dependence on insecure sources of oil. A growing number of companies and organizations representing the oil and gas industry appear to be Basic research for the Harvard study was supported changing their historic opposition to government in- in part by a grant from Energy Security Policy, volvement in oil pricing. Inc. which supports a variable import fee.

In late October, the Interstate As- The Harvard authors said a large fixed fee on im- sociation of America (INGAA) wrote Deputy ports, to be matched by increases in the price of Secretary of Energy William F. Martin informing domestic oil, would reverse current trends in con- him that the INGAA Board of Directors supported sumption and production. The study cited $10- a fee. Then in early November, the Independent 11/bbl as the level required for an "optimal" level Petroleum Association of America (IPAA) endorsed of U.S. imports. the concept of using an import fee to maintain a viable domestic oil industry. IPAA's resolution was They said because the price of U.S. oil imports weak, only recommending that the President con- does not reflect total cost, consumers use more oil sider a fee rather than actually asking him to im- than is optimal and the amount of oil produced in pose one immediately. the U.S. is less than optimal.

Also in November, the American Petroleum In- Although the Reagan administration opposes a tariff stitute dropped its opposition, but stopped short of as being contrary to its free, market policies, the supporting a fee. Instead, API said that the study said there are market imperfections as- government and public should be made aware of sociated with U.S. oil imports that are not cap- the serious implications of U.S. military and tured by current prices. economic security posed by present industry condi- tions. However, George M. Keller, Chairman of The authors said a tariff would produce net and current Chairman of API, benefits for the nation as a whole, although advocated the establishment of a minimum floor redistributing resources throughout the economy. price for crude oil to be accomplished by an im- port fee, import quotas or some other means. The study considered various tariff instruments, in- cluding a variable fee designed to establish a floor The Society of Independent Petroleum Earth Scien- price, and concluded that a fixed fee is the best tists (SIPES) has also announced that it will work option. The authors rejected proposals to exempt for the imposition of import fees, and began a imports from particular countries from the fee. fund-raising campaign to pay for lobbying efforts. DOE Study Although its past president had already written President Reagan earlier this year asking for an The U.S. Department of Energy is working on a import fee, the Petroleum Equipment Suppliers As- study which examines the effect of increasing oil sociation (PESA) formally endorsed that same policy imports on national security. during their mid-year meeting in November. In a unanimous vote of the Board of Directors, PESA The report is expected to be the for said it "strongly supports an import fee/tariff on whatever action the administration takes or foreign crude oil and products." proposes that Congress should take in 1987. However, Energy Secretary John Herrington says The effect of all these policy statements will be to the study will now be delayed until February or show the Administration and Congress that there is March to give DOE more time to evaluate more now a strong consensus of opinion within industry, than 100 reports it has received from various which will take away the argument most commonly groups. given by the politicians for not doing anything--We don't know what to do because the industry itself In Herrington's views there is not a national is divided on the issue." security issue. He states that the Reagan ad- ministration always has opposed an oil import fee. Harvard Study William Martin, the deputy Energy secretary who is A recent study by Harvard University's Energy and managing the study, said it will examine in detail Environmental Policy Center also states that a worldwide supply and demand projections for 1990 fixed fee on U.S. oil imports is needed to reverse and 1995 under low and high price paths, then the trend toward rising volumes of foreign study the effect of those numbers on the U.S. petroleum on the domestic market. The study said economy and military preparedness. The study will a $10-11/bbl fee on imported crude oil and refined evaluate a complete list of policy options, including products is necessary because of the threat to the an oil import fee, based on the options' effect on country's energy and national security from increas- energy production, the economy, the budget, the ing oil imports. It noted that the current price environment, and national security. paid for imported oil by U.S. consumers does not

1-1 SYNTHETIC FUELS REPORT, DECEMBER 1986 API ACCEPTS CONCEPT OF IMPORT FEE Many API members still oppose the new position. Further opposition to an oil import fee came from The board of directors of the American Petroleum the director general of Petroleos Mexleanos, who Institute, at the API's Annual Meeting held in said trade restrictions on oil "would turn the free Houston in November approved the following policy trade policies of the United States into hollow statement: rhetoric confronted by protectionist realities."

The American Petroleum Institute believes that the Keller called on the industry to develop a consen- federal government and the public must be made sus on what government involvement it needs to aware of the serious implications for the economic survive, including the minimum survival price for well-being and national security of the nation of crude oil. what is happening to the . "I am proposing today that our industry vigorously The dramatic decline in exploration activities and pursue the following three Import steps: the dismantling of the industry's capability to ex- plore for oil and gas are resulting in rapidly rising "First, determine what minimum oil price is neces- dependence on foreign supplies. Therefore, the sary to assure the survival, not the economic com- potential is great for disruption and shortages, with fort, of a domestic petroleum industry; attendant sharp price rises--and sooner than many expect. "Second, develop a consensus within the industry on the most effective approach and what type of Until both the public and the government under- government involvement Is required to achieve that stand these facts, and develop a sense of urgency level of price stability; in addressing them, reasonable and timely solutions will not be forthcoming. Government actions this "Third, work with government, as a unified in- year which further hamper investment, including dustry, to put a program in place." those on tax reform and Superfund, are ample evidence that the seriousness of the situation is Asked what a minimum survival price might be, he even now not appreciated by Washington. said that $10/bbl is too low, and $20/bbl probably would be too high. The country cannot wait until a crisis is upon it. Something clearly needs to be done--and soon. Prices could fall further, especially next spring Both our industry and the federal government are when demand traditionally falls, if the Organization currently reviewing a wide range of energy policy of Petroleum Exporting Countries is unable to options. The API believes that no options that will restrain production, Keller said. He characterized increase investment in the industry and preserve its as important studies by the administration's energy ability to respond to future energy needs should be task force, the National Petroleum Council, and ruled out. API on what the industry need to survive. However, he said the industry cannot afford to With that statement, the API dropped a long- wait until the studies are complete before taking standing opposition to a government tariff on oil--a some decisive action. position developed during the Carter administration. Mack Wallace, commissioner of the Texas Railroad API Chairman George M. Keller, chairman of Chev- Commission, used industry's heavy tax burden to ron Corporation, urged industry and government to support his strong call for an oil import fee. He work toward a minimum price for oil. He did not noted that there is no free market for oil, pointing specify a price level or the mechanism, although he out that 70% of the oil produced in the world cited proposals by others for an oil import fee, an comes from government oil companies. He also import quota, or drilling incentives in the tax code. sounded a warning for those trying to agree on a minimum oil price. With respect to what the price API President Charles J. Diflona stated that level should be, he stated that $18/bbl was not problems resulting from current industry ills "will enough to survive on. manifest themselves in a shorter time than people expect." With oil at $15/bbl, he said, U.S. produc- tion will decline by 2.7 million bid within 5 years, leaving the U.S. dependent on imports for more than half its oil requirements.

DiBona acknowledged that it would be unwise to expect any helpful change in Washington attitudes and approaches in 1987. Government speakers at the API meeting reinforced this view. The Reagan administration's position is that its first priority is meeting the Gramm-Rudman deficit target of $108 billion in fiscal 1988 without proposing new taxes.

1-2 SYNTHETIC FUELS REPORT, DECEMBER 1986 GOVERNMENT

WESTERN GOVERNORS URGE IMPORT FEE The second was a request for $12.5 million to es- tablish a pool for cooperative funding ventures with Members of the Western Governors' Association, industry in the area of technology. The meeting in Scottsdale, Arizona on December 13, House appropriations committee said there was no agreed unanimously to urge Congress to impose an evidence to suggest that encouragement of such oil-import tariff, ventures would bring about increased industrial par- ticipation in fossil fuel research. The proposal and another asking Congress to ex- pedite proposed export-trade legislation are not resolutions, according to Governor Norman H. Ban- TABLE 1 gerter of Utah, the WGA chairman. However, he said lawmakers and President Reagan would be asked by mail to consider them. SELECTED DOE FOSSIL R&D PROGRAM FUNDING (Thousands of Dollars) "(The oil tariff) would be the difference between our production price and the import price and would phase out at a certain level--so we can start Budget FY87 producing and exploring for oil again," Bangerter Funding Category Actual FY86 Request Actual said. Control Technology & Coal Preparation $33,256 $18,147 $38,399

Advanced Research & Technology Development 35,233 27,224 32,114 DOE SYNFUELS BUDGET CUT 22% FOR 1987 32,912 9,147 23,957 The appropriations bill for the U.S. Department of 30,302 9,169 15,471 Energy for FT 87 was passed by Congress one day Combustion Systems before that body adjourned for the electoral season. 35,449 5,000 28,200 As in the past, Congress restored much of the deep Fuel Cells budget cum in fossil fuel research which had been 47,249 5,598 26,920 proposed by the Reagan administration. The ad- Coal Gasification ministration had requested a budget of less than 1,371 -- 1,650 one third of the 1986 level. Tar Sands 12,632 3,595 11,000 A comparison of the 1986 funding level, the 1987 Oil Shale level requested by the administration, and the 1987 Total $228,404 $77,880 $177,711 level provided by Congress for those areas bearing on synthetic fuels was made by the Council on Al- ternate Fuels (Table 1).

The funding legislation also allows DOE to sign contracts for the first round of clean coal technol- ogy programs. Without that special allowance, the nine tentatively accepted contracts would have been held up for approval by a Congress not ex- pected back until January. DEPARTMENT OF ENERGY PROMOTES COOPERATIVE VENTURES The Congressional appropriations committees wrote the budget bill with specific directions on how the In its 1987 budget request to Congress, the U.S. money is to be spent for most line items. For in- Department of Energy requested $12.5 million to be stance it was directed that $4,000,000 of the oil placed in a blind venture pool for cooperative re- shale budget be spent specifically on eastern oil search and development projects. DOE's idea was shale. Many of the line items carry instructions to offer this money for fossil energy research that a certain amount of the money must be spent projects for which other parties were willing to put at the University of North Dakota Energy Research up over half the money. center, or Western Research Center, for example. Congress refused to appropriate the money. The In only two significant areas did the administration House Appropriations Committee stated "The Com- request more money than Congress approved. One mittee has no objection to the Department provid- was a request for money to drill more natural gas ing funds to, or participating in cooperative R&D wells on the U.S. Naval Oil Shale Reserve No. 3 in ventures. The Department currently has the Colorado. authority to do so. But there is no evidence to

1-3 SYNTHETIC FUELS REPORT, DECEMBER 1986 - Recovery of gas from unconventional suggest that encouragement of, or participation in resources; such ventures will bring about increased industrial participation or cost-sharing in fossil energy re- - Development of oil shale resources; search, a better approach to resource problems, or a balanced response to the Nations perceived - Recovery of heavy oil and tar sands, and oil energy research needs. It would seem to the remaining after application of conventional Committee that the content of the research carried techniques; out Is of prime importance rather than the con- tracting method involved. The Committee wiT con- - In situ gasification of coal; and sider proposals for specific cooperative venture funding if presented in the context of future - Coal/petroleum co-processing. budget requests.' Additional concepts of potential interest include In response to the rebuff from Congress, DOE held other aspects of oil and gas resources and technol- a public meeting in Denver on December 3 in an ogy, as well as possible coal-related technologies, attempt to gather public support for the coopera- including examples such as: tive venture approach. In its announcement of the meeting, DOE stated that it is particularly inter- - Preparation of coal liquid, mixed, and solid ested in learning what operating and procedural fuels; characteristics interested parties would like to see In cooperative R&D ventures, including what - Technologies such as coal pyrolysis and coal relaxations in federal operating procedures affecting beneficiation for products, as well as precur- reporting oversight and management .would make sors to new clean and affordable fuels; these ventures more attractive to potential project participants. DOE is soliciting views preparatory - Liquefaction of coal and coal-derived gases to an actual program offering of cooperative R&D and by-products; ventures for fossil energy technologies and resources. - Advanced fuel conversion and energy utiliza- tion technologies, such as fuel cells and In a cooperative venture, the Energy Department MHD; would be a minority funding partner, involving It- self principally in matters of policy and investment - Environmental control technologies, such as, decisions rather than managing detailed technology for example, flue gas cleanup; and and business aspects. Other participants, which could include public or private organizations in the Coal and utilization. same business or industry, would determine the project's scope, technical activities and form of About 140 people attended the Denver meeting, and management. Cooperative ventures could include about 20 formal statements were presented by projects involving coal, oil, gas or oil shale. trade organizations, individual companies, states and universities. The Gas Research Institute, the "We envision the cooperative venture approach as Electric Power Research Institute, Columbia Gas augmenting the traditional core research and and Sun Oil formally expressed interest, as did the development program carried out by the depart- states of Indiana and Illinois. The universities of ment," said J. Allen Wampler, the department's Michigan, Texas, North Dakota, and Purdue Univer- newly sworn-in Assistant Secretary for Fossil Energy. "Such research ventures have proven sity, also presented statements. The turnout ap- highly productive in the microelectronics and semi- peared to have exceeded DOE's expectations. As a conductor fields, and we believe the opportunity result of the interest shown, DOE spokespersons in- may exist to extend this approach into the area of dicated definite plans to proceed with developing a fossil energy research." During his recent Congres- program and requesting funding in the FY88 sional confirmation hearing, Wampler cited the Federal budget. Provision of such funds in FY87 cooperative R&D venture approach as a high- could be done now only through a supplemental priority idea worth pursuing. budget request to Congress. Such a path would seem unlikely. DOE's background statement for the program noted that in the face of heightened international com- The State of Indiana Board has petition, U.S. firms are increasing the leveraging of already announced a public meeting for January 12 their resources in technology development to trans- to discuss cooperative research and development late basic concepts into potential market oppor- ventures and the opportunity for leveraged research tunities. in fossil energy. The State of Illinois has already concluded an agreement to cooperate with DOE in The planned initial emphasis is on advances in the area of fossil energy. It appears that the extraction-related technologies that embody cost- Department of Energy will get the support that it effective approaches to the use of extensive U.S. needs to return to Congress and try to sell the fossil energy resources. The areas of extraction- idea again. related technologies currently identified for con- sideration include:

1-4 SYNTHETIC FUELS REPORT, DECEMBER 1986 ENERGY POLICY & FORECASTS

CHEMICAL ENGINEERS PUSH FOR SYNTHETIC will become a major input to the CR1 planning FUELS FUNDING cycle leading to the development of the 1988 R&D program. The American Institute of Chemical Engineers has issued a policy statement urging the U.S. govern- Several important factors have contributed to ment to continue funding synthetic fuels efforts so changes in the new projection from last year's. that the United States will not be vulnerable to The most significant, of course, was the fall in cutoffs and price increases for imported oil. world oil prices early in 1986 and the resulting in- creased uncertainty about the near-term behavior The AIChE statement notes that such activities are of energy prices. As the basis for the 1986 expensive, but that the economic consequences of baseline projection, CR! has projected oil prices to not taking such actions are likely to be more firm gradually from current low levels. The severe. It notes that studies by the U.S. Synthetic average U.S. refiner's acquisition cost of crude oil Fuels Corporation estimated that having a domestic is projected to reach about $20 by 1990, $27 by synthetic fuels capacity that can moderate the 2000, and about $40 by 2010 (all in terms of 1985 price of imported oil by only 25 cents/bbl is a dollars). benefit with a present value of about $8 billion. This outlook is based upon several factors. Current The Institute urges the government to: oil prices discourage investment in new supply sources and encourage more extensive use of Continue funds for basic synfuels research. petroleum in discretionary applications. The very Private and public sector laboratories should low prices also create political tensions by increas- begin high risk, long range studies that could ing U.S. imports and restricting the oil revenues improve present technologies and create new received by the densely populated exporting nations. ones. For these reasons C RI feels that prices will tend to rise to the $20 range in the near term. Conduct synfuels process development work With government funding or cofunding with Until 1990, the global oil supply situation appears industry. Such work would test and optimize comfortable. The requirement for OPEC supplies specific technology combinations and develop will remain below historical peak levels, and U.S. information for design of commercial plants. production will hold up well. After 1990, levels of production from the U.S. and other non-OPEC Free Maintain a data base of research results so World sources are expected to fall rapidly. Opec's the most economical technologies can be production will reach 21 million barrels per day in identified. 1990, which will exceed the 20 million barrel level that is considered by many analysts to signal the Subsidize commercial demonstrations of syn- return of OPEC dominance of world pricing fuels technologies or combinations of tech- strategy. By 2000, the Middle Eastern OPEC nologies. countries alone will be producing 21 million barrels per day, the amount they produced at the peak of - Provide tax credits, accelerated depreciation, the energy crisis in 1978. depletion allowances, and other incentives to cut the risk of commercializing synfuels CR1 has assumed that these circumstances will projects. result in steady increases in the after 1990 and that the rate of price escalation will in- Fund boiler, combustion turbine, and engine crease in the later years of the projection. development based on synfuels, including combustion tests for coal, shale oil, and tar In the U.S., total consumption will sands. Such work would assure that equip- increase from 76.4 quadrillion BTU (quads) in 1985 ment would be available for synfuels use. to 105.1 quads by 2010. This rate, which is 45 percent of the GNP growth rate, reflects further - Develop processes and catalysts for conver- improvements in the efficiency of energy use, along sion of synthetic oils to traditional products with continued restructuring of the U.S. economy to assure that existing equipment can be into less energy-intensive applications. retained in a synfuels based economy. Industrial gas consumption will be constrained by strong price competition from residual fuel oil in the near term and technological competition with electricity in the later years, combined with slow growth in overall industrial energy demand. A GRI FORECAST FEATURES ADEQUATE GAS decline in electric utility natural gas demand in the SUPPLIES AT LOWER PRICES early years of the projection will also contribute to restraining gas demand through 1990 at the 1985 The Gas Research Institute's 1986 Baseline Projec- level of about 17.5 quads. tion of U.S. Energy Supply and Demand to 2010

1-5 SYNTHETIC FUELS REPORT, DECEMBER 1986 After 1990, gas consumption is projected to grow is being validated by current experience. In effect, rapidly, reaching almost 19 quads by 2000. This the supply system is becoming more cost-effective growth is heavily dependent upon increased use of under intense competition. However, gas prices gas to generate electricity. New, gas-fired gener- will have to firm significantly from today's low ating facilities are expected to be installed in the spot prices to attract adequate new investment into late-1990s to respond to the need for short-lead- gas exploration and development. CR1 expects that time generating capacity. a more efficient industry, working in the anticipa- tion of continuing intense competition, can achieve Residential gas consumption is projected to decline the required production at lower costs than earlier gradually as efficiency improvements offset the ex- historical experience would have implied. pected growth in the number of gas-heated homes. The rate of decline is less than in previous C RI baseline projections, however, as it reflects a reduced estimate of conservation improvement in response to lower energy prices. The commercial sector represents a potential HANKERS TRUST FORECASTS NEW HIGH IN OIL growth market for gas. Gas consumption is IMPORTS projected to grow from 2.5 quads in 1985 to 3.6 quads in 2010. This includes a strong market penetration of gas-fired commercial cogeneration, H. W. Krupp of Bankers Trust Company, speaking though somewhat less than in last years projection. at a December conference on Oil Imports and The availability of competitive gas cooling tech- Energy Preparedness sponsored by the Council on nologies and suitably sized cogeneration equipment Alternate Fuels stated that the recent collapse of will be critical to achieving the projected growth oil prices almost certainly will lead oil imports to in this sector. rise to unprecedented levels within the next decade. This increased dependence on foreign At prices competitive with alternative fuels, con- sources of supply represents a clear threat to the ventional natural gas production from domestic nation's military and economic security. resources is expected to hold up well in the near term, but diminish significantly in the 1990s. It Krupp attempted to measure the impact that lower will provide only about three-quarters of total oil prices could have on U.S. oil imports through supply in 2000 and less than half in 2010. The 1995. The results are based on a model of U.S. primary supplemental source of natural gas in the drilling activities that takes into account the inter- early years of the projection is imported gas from relationships of variables such as wellhead revenues, Canada's more accessible and developed resources. reserve additions and oil and gas production rates. In the later years, beginning in the 1990s, sup- The dramatic drop in oil and gas prices has slashed plemental supplies of gas which depend upon new wellhead revenues and therefore drilling expendi- initiatives will increasingly be required to meet the tures in recent months. For 1986 on the whole, projected levels of consumption. The most sig- revenues have fallen by $45 to $50 billion -- from nificant contribution in this timeframe will be en- $120 billion in 1985 to an estimated $70 to $75 bil- hanced production from lower-48 unconventional lion in 1986. Since roughly one-fifth of revenues resources, including low-permeability (tight) sands, are typically plowed back (reinvested) in drilling Devonian shales, coal-seam methane, and production activities, he estimates that exploration and from watered-out reservoirs. development expenditures have declined by some $9 to about $11 or $12 billion in 1986. This compares o RI is convinced that the extensive resources with spending of almost $40 billion in 1982. These available, much of which are already discovered expenditure estimates for 1986 are supported by and fairly well-known, can easily provide important API data showing that U.S. well completions in the levels of production at competitive prices beginning third quarter of 1986 were down by almost 50 per- about 1990. Obtaining the gas supplies required in cent from the year-earlier level. the 1990s and beyond, however, will depend upon a sustained and directed R&D program to improve The squeeze on wellhead revenues--and on explora- the technologies used in unconventional gas produc- tion and development expenditures--will continue to tion. depress domestic drilling activity through the entire forecast period, although an upward drilling trend is Additional quantities of Canadian imports will also expected to begin in 1988. be needed after the year 2000. These will depend upon major capital investments such as the Polar The levels of drilling activity will fall far short of Project to deliver gas from Canadian Arctic that necessary to replace reserves lost through resources or the infrastructure to develop and production. Both oil and gas reserves will be transport gas from new offshore regions. declining sharply in the next decade. Crude reserves will fall from about 26.5 billion barrels The projected acquisition prices for natural gas at the end of 1985 to about 18.5 billion barrels at supplies are significantly below previous C RI the end of 1996. This compares with over 33 bil- projections. C RI states that this analytical result lion barrels in 1977 (Figure 1).

1-6 SYNTHETIC FUELS REPORT, DECEMBER 1986 tant role in the next century. But we cannot depend on the private sector alone to foster development of alternatives that will become FIGURE I economic so far in the future. Therefore, the Government should provide a helping hand now to CRUDE provide for a foundation of alternative fuel tech- nologies. The existing complacency over future energy sup- I iuninumnnu plies that has developed in recent years is misplaced. The energy crisis will return, says !UuIIflhIIflhIIIII Krupp. • iiiiiiiiuiiii •HhIIIIIIuIn'flu.

•uuuiuiiiuiiinin CONOCO FORECAST SEES CONTINUING FALL IN •IuhIIIIIIIIuIuuIII U.S. DOMESTIC OIL SUPPLY Conoco's new "World Energy Outlook Through 2000" notes that the major effect of lower oil prices in the near term will be increased reliance on imports to satisfy United States energy demand. The study points out that the first signs of the impact of the Non-associated gas reserves will also be falling-- price collapse are already apparent. Some in- from 141 trillion cubic feet at the end of last year dustrial and electric utility plants in the United to 107 trillion cubic feet by the end of 1995. States, Western Europe, and Japan have switched Reserves were over 220 trillion cubic feet in the from coal or gas to oil. High-cost oil producers have shut down wells. Exploration and development late 1060's. expenditures have been slashed. Inflation and in- terest rates have fallen, and wealth has been trans- Imports to Soar ferred from oil producers to consumers. This pat- The slump in reserves will sharply reduce liquids tern represents the mirror image of the events fol- production (primarily crude oil and natural gas lowing the 1973-74 and 1979-80 oil price increases, liquids) in the United States--from 11.4 million bar- and may portend a period of healthy, sustained rels per day in 1985 to 8.2 million in 1995. economic growth for the United States and other Meanwhile, oil consumption will be on the rise, oil importers. However, just as high oil prices diminished oil's share of world energy markets, stimulated in part by the much lower oil prices. lower oil prices will lead to increasing reliance on Oil consumption would be expected to rise from imported oil. Rising import dependence means (1) 15.7 million barrels per day in 1985 (and 16.3 mil- a higher risk of an economically damaging shortfall, lion in 1986) to 18.2 million in 1995. The com- (2) reduced flexibility in formulating and im- bination of lower liquids production and higher oil plementing foreign policy, and (3) greater military consumption will raise net oil imports from 4.3 mil- obligations to safeguard vital supply links. At the lion barrels per day in 1985 to 10 million barrels same time, the ability to respond with an increase per day by 1995. As a result, net imports as a in domestic supply will be greatly diminished. share of domestic oil consumption would rise from a tolerable 27 percent in 1985 to an unacceptable Conoco's assessment of the world energy outlook 55 percent in 1995. Once again, the United States considers high-, low-, and mid-range cases (see would be vulnerable to supply disruptions and oil Figure 1), with the mid-range case explored in price hikes--no matter how large our strategic petroleum reserve is by 1995. detail. Krupp notes that it is widely expected that OPEC's Key Factors leverage over oil prices will be restored over the next decade, and in large part, the United States The supply and demand projections presented in the will be responsible for OPEC's growing market outlook are consistent with the mid-range price power. Over the next decade, U.S. oil imports scenario. (Prices are in current dollars and reflect alone will account for over 60 percent of the in- U.S. inflation averaging nearly 4 percent per year.) crease in worldwide requirements for OPEC oil. In this scenario, crude oil prices fluctuate between $15 and $20 per barrel through 1990. During the He concludes that legislators should give considera- 1990s, as the supply-demand balance tightens, tion to development of an alternative fuels policy. prices begin to move up rapidly, reaching $40-$50 Although not a fashionable topic at the moment, per barrel in 2000. Nevertheless, prices are ex- the fact remains that some alternative fuels will pected to remain below the range anticipated by become economic and play an increasingly impor- Conoco a year ago.

1-7 SYNTHETIC FUELS REPORT, DECEMBER 1986 World Energy Demand

FIGURE 1 Conoco predicts that World energy demand will grow slightly faster than 2 percent per year during the second hull of the 1980s and 1 1/2 percent per CRUDE OIL PRICE SCENARIOS year during the 1990s. Developing countries will account for nearly half of the total increase, al- though they currently represent less than n quarter (Omt* Who Pa jyd) of demand. 60 As Figure 2 shows, world energy demand will in- crease from 96 million barrels per day of oil 50 equivalent (MMBDOE) in 1985 to 107 MMBDOE in 1990 and 125 MMBDOE in 2000.

40

FIGURE 2 30 WORLD ENERGY DEMAND (MJWt, Oanrb Per Day Oil EquI.tefl) 20 ISO 10

- I I I o 1973 1979 1995 1990 2000 Low Rxigc - Mid Range Hi Range

Natural gas is expected to remain competitive with oil products in most markets through 2000. Some regions of the United States where gas transmission 2000 and distribution costs are high, however, may find 0 1973 1979 1985 1990 oil cheaper than gas. United Sates Japan [jJ Developing Nations Western Europe ( Other Dewloped Because of lower oil and gas prices, coal no longer C Nations has a clear-cut economic advantage in new boilers, even in relatively large units. In fact, with oil prices near the lower end of the mid range, a few Energy intensity (energy use per unit of economic plants now using coal may to oil. Although activity) will remain fairly stable in the developing substantial excess capacity exists in the coal in- countries. However, in the developed countries, dustry at present, few producers can reduce prices shifts in the composition of economic output, significantly and continue to operate. As a result, together with continuing efficiency gains and coal prices will fall only slightly before stabilizing. saturation of some uses, will force energy intensity lower. World energy intensity is expected to In the long run, prices will increase gradually, decline 1 112 percent per year. limited by productivity gains and expansion of low- cost capacity worldwide. World Energy Supply High plant construction costs and safety concerns Conoco calculates that coal and oil will provide the will limit the growth of . No new largest absolute increases in energy supply, while capacity beyond what already is under construction nuclear will experience the fastest growth. Oil will be added in the United States. In Western will continue to supply over 40 percent of total Europe, Japan, and some developing countries, world energy requirements in 2000; oil and gas nuclear programs will go forward, but at a slower together will supply over 60 percent. pace than in recent years. Nuclear power economics are questionable with oil prices below Although the price advantage of coal over oil and $20 per barrel. gas has eroded, coal will still make a significant contribution to incremental energy requirements. Energy fromrenewable sources such as , Several regions currently possess underutilized coal- wind, and will make only a limited fired electric generating capacity that will be put contribution to energy supplies. In most cases, the into service as electricity demand increases. Fur- renewable technology will not be competitive with thermore, relative to oil and gas, coal is seen as a combustion of conventional fossil fuels. No men- secure long-term choice for fueling new capacity. tion is made of synthetic fuels.

1-6 SYNTHETIC FUELS REPORT, DECEMBER 1986 Nuclear power will be the fastest-growing energy By 2000, fuel oil will win back from natural gas source, rising over 4 percent per year, with the much of the dual-fueled industrial and utility boiler most rapid growth during the next several years. market that it lost after the second oil price run- However, its absolute contribution will be less than up. 20 percent of incremental energy supply, far less than previously expected. Once plants currently Other products, including liquefied petroleum gases, under construction are completed, little additional petrochemical feedstocks, and , will grow capacity will he added. about 1 percent per year. In conjunction with steady demand growth for oil, U.S. Oil Supply the decline in non-OPEC supplies will lead to rapidly growing dependence on OPEC oil. OPEC's U.S. crude oil production is expected to fall by 2 share of supply is expected to reach 60 percent by 1/2 percent per year from 1985-2000, resulting in a 2000, comparable to the levels of dependence seen decline of 3 MMBD. Natural gas liquids output during the 1970's. will also fall. Net oil imports will rise from just over 4 MMBD in 1985 to nearly 11 MMBD in 2000. U.S. Energy Supply and Demand Few new EOR projects are likely to be economic, U.S. energy demand is estimated to grow 1 percent and the synthetic fuels program has ground to a per year. Oil will supply more than half of the halt. Over the long term, significant contributions resulting increase in energy requirements, while to domestic supply will require exploration of fron- coal and nuclear power together will supply the tier areas and the development of new production remainder. Natural gas use will decline slightly. technology. However, both activities will be sealed back as a result of the price collapse. U.S. energy intensity will decline 2 percent per year from 1985-2600. Despite lower oil prices, As oil demand rises, U.S. requirements will have to average energy efficiency will rise as (1) new capi- be met with higher imports. Crude oil and product tal equipment and structures require less energy imports will increase from 26 percent of demand in than the existing stock, (2) cogeneration increases, 1985 to 41 percent in 1990 and 56 percent in 2000. and (3) the economy continues to shift toward less energy-intensive services and light manufacturing. Policy Implications Demand for U.S. coal, including net exports, will Clearly, energy security will once again become a rise by 1 1/2 percent per year to over 1.1 billion front-burner issue during the 1990s. Because of by 2000. The electric utility sector will the long lead times typically required to bring new remain coal's principal market, accounting for over production onstream, steps aimed at preventing the three-fourths of coal output. next energy crisis must be taken now. Electricity demand growth of only 1 1/2 percent Although lower oil prices may be beneficial to the per year, the completion of nuclear construction U.S. economy, increased reliance on oil imports by programs, and growth in cogeneration and power the United States will reduce the nation's energy imports will limit growth in the use of coal in the security. Much of the actual vulnerability arises utility market. Relatively little new coal-fired not from imports per Se but because a large and capacity beyond what is already under construction growing portion of the world's oil supply is con- will be needed by 2000. Utilities will minimize centrated in a few countries where the risk of captial-intensive generating projects by purchasing supply disruption is significant. Conoco believes power, installing gas turbines or eombinetheycle that this cannot be entirely avoided, but certain units, or managing load more efficiently. Utility governmental actions can reduce U.S. energy vul- coal burn will rise by only 1/2 percent per year nerability. through 1990 as nuclear generation grows rapidly. Growth in coal use will accelerate to 2 percent per Conoco's recommendations include reducing taxes, year during the 1990s. eliminating environmental constraints, making Federal lands available, reducing minimum bid U.S. oil demand should grow by more than 1 per- prices, and adjusting lease terms in response to cent per year from 1985-2000, rising by over 3 price fluctuations. Mr,•IBD. Consumption of all products will increase, with residual fuel oil experiencing the largest gain. ## ## U.S. oil demand will increase from 15.7 MMBD in 1985 to 19.0 M MBD in 2600. Gasoline demand will rise as lower prices not only spur increased driving but also slow efficiency gains. Strong gains in the transportation sector, offsetting continued weakness in heating oil, will boost distillate fuel oil demand. Lower oil prices will have the largest impact on residual fuel oil demand, which will nearly double.

1-9 SYNTHETIC FUELS REPORT, DECEMBER 1986 TECHNOLOGY

METHANOL TO ETHANOL ROUTE MAY HAVE The acetic add and ethanol steps respectively ADVANTAGES require relatively pure carbon monoxide and whereas methanol synthesis can be Humphreys & Glasgow Ltd of London, a division of achieved by a comparatively wide range of Enserch Engineering and Construction, finds advan- hydrogen plus carbon oxides gas compositions. Syn- tages in a process for converting methanol to thesis gas production is followed by the separation ethanol. of carbon monoxide and hydrogen with the surpluses and recycle streams being fed to methanol syn- Production of methanol is considered the best op- thesis, using this unit as a reject gas "sink". tion for converting remotely located natural gas resources to transportable liquid fuels. However, Gas Generation its fundamental drawback is a saturated market which shows no prospect of being able to absorb The essence of the process is the conversion of a the quantities of methanol which would result from feedstock into synthesis gas and the mega scale production units. This will continue to subsequent splitting of that synthesis gas into three be the case unless a means can be found to meet sub-feedstocks: the rigid needs of the existing transportation fuel markets. 1. Mixed 11 21CO and CO 2 to produce methanol. Pure methanol added as a single component to the gasoline pool carries relatively little benefit and is 2. high purity CO to produce acetic acid. subject to much criticism. Its affinity for water, high vapor pressure, and the fear of corrosion and 3. High purity H 2 to produce ethanol. second phase formation have prevented its widespread acceptance. The basic requirement for the ENSOL gas separa- tion is to remove a pure stream of carbon Specific octane enhancers, on the other hand, can monoxide and then pure hydrogen from the syngas. bypass the necessity for expensive refinery up- grading techniques; but must be available at a Carbon monoxide can be separated by chemical guaranteed quantity, quality and price to attract washes such as aluminium trichioride dissolved in the attention of the blender. toluene, by cryogenic separation, or membrane dif- fusion technology such as the Monsanto "Prism". Methanol is one of the feedstocks for the more commonly accepted octane enhancers such as MTBE In reformer based ENSOL complexes, a carbon but all these synthetic additives require more in- dioxide removal plant used in conjunction with a gredients than just natural gas. C 31s and/or C4s cryogenic unit appears to be the best choice. For are needed in the isomerised and unsaturated form partial oxidation systems, Prisms alone are suffi- and unless available directly as a by-product from cient. a refinery or petrochemical process, require manufacture from natural gas liquids via a costly dehydrogenation step.

Humphreys & Glasgow feel that methanol to FIGURE 1 ethanol is a process route which retains the straight forwardness of methanol synthesis but ENSOL PROCESS FLOWSCHEME which produces a final product whose cost justifies the additional investment, whose selectivity and yield results in a single product from natural gas alone and, most important, whose marketability is universally accepted.

The ENSOL Route

ENSOL ethanol is produced through the initial syn- thesis of methanol, subsequent carbonylation to acetic acid, and finally hydrogenation to ethanol, as seen in Figure 1. The technology for each of these steps is supplied respectively by HaG, Mon- santo and BASF.

In the ENSOL flowscheme a source of syngas simultaneously services the methanol loop, the acetic acid plant and the final hydrogenation unit producing a pure ethanol product.

1-10 SYNTHETIC FUELS REPORT, DECEMBER 1986 The possibility of converting all the natural gas It must be emphasized that these figures relate to into methanol and then decomposing part of this to a totally self-sufficient complex neither importing provide pure carbon monoxide and hydrogen for the nor exporting utilities. A local need for power, two downstream syntheses is also being inves- such as a township or parallel industrial enterprise, tigated. could change the relative attractiveness of these options. Economics The lower efficiency of the ENSOL route reflects According to H&C, the economic success of a gas the number of process steps required; but this is conversion process depends on three factors. The balanced by the commercially acceptable tech- cost of feedstock, the on-cost of processing and nologies involved and a product which, as an octane the market price of the product. Market forces enhancer, can be sold for more than its thermal will control the selling price and unless the value as a straight fuel. producer has a monopoly supply situation lie is un- likely to have any significant effect on this.

As long as oil reserves remain in significant surplus over demand, synthetic fuels selling on a purely FIGURE 2 thermal basis in competition with natural fuels will not be viable except for strategic reasons. ENSOL INVESTMENT RETURN ENSOL is aimed at the natural gas resource owner OCr &UURH who does not have access to direct piped con- 215W QUill 19 (11 sumers and who is seeking an added value 30- transportable product which sells above its thermal 21 value. For the initial ENSOL evaluations, a nominal cost of $1/MMBTU was taken for the 20 natural gas. Since then, progressive development of the flowscheme has reduced capital costs to a 25 point where 2-2.5 dollar gas can be considered vi- -I. able (Figure 2).

The overall thermal efficiencies of the leading op- 20 tions for synfuel production from natural gas are as follows:

Thermal Efficiency II 70 71 00 05 00 00 (Related to unit ETHANOl PUCE US CSJCAIL. output of product)

Fischer-Tropsche 53 - 59% Methanol and Higher Alcohols 70% MTC 60 - 6196 ENSOL 52 - 55%

1-li SYNTHETIC FUELS REPORT, DECEMBER 1986 INTERNATIONAL

IFP AND IDEMITSU KOSAN REPORT PROCESS FOR HIGHER ALCOHOLS FROM SYNGAS

Japan's Idemitsu h{osan Co. Ltd and France's IF? (Institut Francois Du Petrole) have developed a process which produces a C 1-C 6 alcohols mixture, suitable for motor-fuels blending. It was reported to a Symposium on Production of Mixed Alcohols from Synthesis Gas, that a demonstration plant (capacity 7,000 bbl/y) was built under funding from Japan's RAPAD (Research Association for Petroleum Alternatives Development).

Catalysts

Researchers on the project found that copper-cobalt based catalysts induce a classical chain-growth mechanism. Heavier alcohols content ranging be- tween 20 and 70% by weight can be obtained, (actual target 35-45%), under moderate operating conditions. The process selectively produces linear alcohols ranging from C 1 to about C 7 . The reac- tion stoichiornetry (11 2 /CO) varies between 0.0 and 3, depending on the nature of the products and the number of carbon atoms involved. Most of these reactions are strongly exothermic. sponsorship. These tests will be performed with The catalysts are bused on homogeneous, spinel motor fuels blended with fractionated C 1-0 0 al- type, mixed oxides, modified by incorporating alkali cohols from the demonstration operation. metals. Among others, copper, colbalt, aluminum, zinc, and sodium mixed oxides have been described, Typical octane blending values (Figure 2) are high as well as copper cobalt chromium alkali metal when compared with data for individual alcohols. oxides. These figures (RON = 120.8, MON = 98) locate a typical octane blending value between that of Modifications of either the catalyst's formula or of ethanol and isopropanol. its "conditioning" in the reacting medium allows varying alcohol phase composition from 20 to about The Reid Vapor Pressure is low enough that, 70 wt% of C 2 -i- alcohols. One of the advantages of provided that most of the butane has been removed copper-cobalt catalysts is the very high purity of from the gasoline pool before blending, such an oc- the alcohol phase produced. tane booster could be used without trouble during summer time in many countries. Process Development Eca,omics Control of reaction temperature is achieved by using a multiquenched bed system, rather than the RAPAD's current interests concern alcohols produc- multitubu lar "isothermal" reactor favored for large tion from natural gas, via partial oxidation. The capacities. Two reactors in series are used, with cost of production of C 1-C 6 alcohols is highly sen- intermediate cooling (Figure 1) yielding high CO sitive to that of natural gas. Low-priced gas is conversions after CO 2 removal, then recycle of un- widely available, mostly in developing countries or converted syngas. remote areas. Two extreme situations are con- sidered in Table 1 where estimated production costs Depending on the efficiency of CO 2 removal, and are given for a typical 700,000 tons per year on the operating conditions of the reaction section, natural gas to alcohols integrated complex. the water content of raw alcohols is between 2.5 and 5 weight percent. Costs related to the investments vary for different countries. For remote areas, it is reasonable to During operation of the demonstration plant, the apply a location factor to the investments (here, content of C 1_6 alcohols in the product mixture 1.4). With a gas price of $0.50 per MMBTU, was very high, more than 99 wt%, even higher than production cost in remote areas will be mainly sen- predicted by bench-scale and pilot studies. The sitive to the capital costs. plant was slated to be restarted in late 1986.

An evaluation of the product is planned with a series of tests on a fleet of ears under RAPAD's

1-12 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 FIGURE 2 PRODUCTION COST OF C1-C6 ALCOHOLS FROM NATURAL GAS OCTANE NUMBER VS Plant Capacity: 2,100 tonsld VOLUME % ALCOHOLS ADDED Stream Factor: 8,000 lily - 1986 Data Industrial Remote Location Area Octane number RDN CAPTIAL COST (106$) is - Battery Limit Investments 320 450 - Storage, Off-sites Investments 160 220 - FIXED CAPITAL 480 670

OPERATING COST ($ /ton)) - Raw Materials Gasoline sample U - Natural Gas - $3.0/MMBTU 132 - Natural Gas - $0.5/MMBTU 22 IC - Catalyst and Chemicals 18 18

- Variable Costs - - Operating Labor 2 2 - Maintenance Labor 6.86 9.57 - Control Lab. Labor 0.40 0.40 MON - Maintenance Material 6.86 9.57 35 - Plant Overhead 7.40 9.58 - Taxes and Insurance 13.71 19.14 - DEPRECIATION 68.57 95.71

PRODUCTION COST - $/ton 256 186

SALE PRICE -$/tai 324.6 281.7 80 (at 10% ROD

C 1 _Csols, vol % I 0 5 10

JAPAN'S RAPAD REPORTS R&D PROGRESS IN SYNTHETIC FUELS

The Research Association for Petroleum Alterna- tives Development (RAPAD) was established in May, 1980, under the auspices of Japan's Ministry of International Trade and Industry. In its 1986 Annual Report, issued in September, the Association noted that "Although it has turned out that the world oil supply is enough for the immediate fu- ture, we believe we should continue our program, because the fundamental situation will not change substantially in the long term."

RAPAD is organized by 23 member companies from such industries as petroleum, fermentation, chemi- cal and engineering. It inaugurated its research activities in June, 1980, taking charge of a national project under a 7-year program (1980-1986). Re- search activities of RAPAD cover the following three fields:

1-13 SYNTHETIC FUELS REPORT, DECEMBER 1986

1. Manufacturing synfuels from syngas. New Process for Hydrocarbon Fuels from Syngas 2. Upgrading tar sands bitumen and shale oil. 3. Biomass conversion and utilization. Two different approaches are being studied, the methanol-to-gasoline (MTC) reaction, and the direct Major developments over the past year were syngas-to-gasoline (5Th) reaction. reported In a number of tasks for each of the above three fields. For the methanol to gasoline reaction, a chemically modified catalyst was tested which gave about 5- Improved Fischer-Tropsdi Process 10% more C 5 +gasoline than the unmodified catalyst. The chemically modified catalyst also has The most important objective of this research is a longer life under pressure. the development of new catalysts to maximize yields of liquid , such as gasoline frac- For the STG reaction, a slurry-bed reactor was tion and middle distillates. considered promising because in that system the heat removal is easier and catalyst regeneration The reaction of the F-T synthesis generates a great and recycle are possible. Slurry-bed reactor re- deal of heat. It is necessary to efficiently remove search has been continued since 1983. the heat of reaction and to develop a process in- hibiting the formation of carbon on the surface of An improved 2-stage 5Th reaction process is now the catalysts. For such a process, a slurry reactor under development. Syngas is converted to is being considered and chemical engineering data dimethyl ether (DM5) in the 1st-stage fixed-bed for scaling up will be collected by using a bench- reactor; and the D ME is converted to gasoline in scale reactor. the 2nd-stage fluid-bed reactor.

It has been found that when suitable amounts of A large bench-scale plant with a capacity of 1 bar- sulfur and alkali metals are added to Hu/manganese rel gasoline/day was constructed to facilitate the oxide catalyst, low class olefins are produced selec- design of the 2-stage STG reaction process and tively. evaluate the catalysts and products. Ru type catalysts were prepared with alumina and -Containing Fuels silica carriers having different pore diameters. As shown in Figure 1, yields of methane and light oils It is desirable that alcohol to be admixed with were great with catalyst A using alumina of small gasoline have high miscibility with gasoline and pore diameter, while the olefin content of the high calorific values. The miscibility and calorific product oil was low. In the case of catalysts using value are improved by coexistence of higher al- silica carrier, the yield of light oils tended to in- cohols, such as ethanol, propanol and butanol, with crease as pore diameters were decreased, as shown methanol in the gasoline. RAPAD is studying the in the same figure. production of such higher alcohols by catalytic reaction.

Mixed alcohols were produced from a pilot plant FIGURE 1 and admixed with gasoline and the blended product was analyzed for general properties and miscibility. It was found that no difference in performance ex- RATIO OF n-OLEFIN / n-PARAFFIN isted between mixed alcohols and methanol-TBA OF PRODUCED OILS blended alcohols. Miscibility with gasoline, as shown in Figure 2, compared with admixtures of 5% of mixed alcohols is better than that of l.0 methanol (threshold water content for phase separa- Catalyst Mean Pore Diameter (A) tion is high), and the results were nearly the same • :1% Ru Alumina A 70 as those of methanol-TBA blend. A : l%Ru Alumina B 100 o :1% Ru Silica A 30 A :1% Ru Silica B 60 Comparing the reaction performance of the pilot .9 a :1% Ru Silica C 140 plant with the values predicted on the basis of bench plant operation, it was found that the selec- tivity of C2+0I1 was rather high. A study concern- C A 0 ing the CO 2 concentration was conducted, and it 0.5 a was found that selectivity to C2+ OH is high when - .__s_._s------the CO 2 concentration is comparatively high. -----£ 0 £ a Improved Heat Treatment of Bitumen and Shale Oil Studies were conducted on the refining and reform- ing of products of thermal of bitumen. Treatment processes were com- pared and the characteristics of catalyst life versus hydrogen consumption and products versus condi- Carbon Number tions of thermal cracking were studied.

1-14 SYNTHETIC FUELS REPORT, DECEMBER 1986

FIGURE 2 FIGURE 3 MISCIBILITY OF TWO WAYS OF PROCESSING ADMIXED WITH ALCOHOL AND TBA THERMALLY CRACKED OILS

.-Gas & LPG A SO I till ______is I I 1lytic Gawline I1refinint1ReforminFf 10 A Tfl i -Kerosene I I 1reflnin4 E 0 -s lII TI -10 LA LJHydro. I yGas Oil I I Irenningi 0 0.1 0.2 0:3 0.4 H2O Content at Miscibility Limit (wt%) Ii/ /. Catalflic Hydra fm Oil refinin 1 Cracking -t Methanol 5% Added - Case-I ,L—s Methanol 10% Added Methanol 3% Added Gas & LPG TRA 2% Added Methanol 7% Added Catalytic Gasoline •( { TBA 3% Added Reforming 0-0 Product Liquid 5% Added 0-0 Product Liquid 10% Added Kerosene C111 Hydr Cracked Oilrefining • Gas Oil Two processes to refine and reform the product of thermal cracking were studied as shown in Figure 3. It was found that yields of fuel oils are higher, and generally better quality products are obtainable Hea Oil in Case 1. U Case-2 Conditions for hydrovisbreaking, demetallization reaction and hydrocracking were studied to arrive at optimum conditions for the operations. High yield of clean was obtained by Emissions of N Ox, CO and smoke were relatively combining these processes. higher in comparison with those from ordinary C fuel oil. These emissions, however, were at a level Solvent Deasplialting Process which can be reduced by improved combustion techniques and by conventional gas treatment. This work tested the refining of oil sands bitumen at high efficiency by a combined process consisting Thesyncrude produced by the composite process of visbreaking, solvent deasphalting and fixed-bed was evaluated for reactivity to fluid catalytic hydrotreating. cracking (FCC). While it was found to be possible to convert syncrude (H-DAO) under the same condi- Combustion tests on solvent deasphalted (SDA) fuel tions as for desulfurized vacuum gas oil (HDS-P) oil were conducted. The SDA was derived from which is ordinary FCC feed, conversion and Athabasca oil sands bitumen. The C fuel oil tested gasoline yield from H-DAO are lower than those was a blend of SDA 39%, atmospheric residue of from HDS-P. petroleum 47%, and light cycle oil from FCC 13%. Catalytic Proces A common steam atomizing burner for C fuel oil Studies were undertaken to develop highly active, was used and it was confirmed that the blended long-life catalysts for de metallizing, deasphalting mixture was perfectly combustible with this burner. and middle distillates producing processes.

1-15 SYNTHETIC FUELS REPORT, DECEMBER 1986 In 1984 catalyst DAM-244 was developed. This was based on finding a natural mineral catalyst which excelled in middle distillate producing reactivity FIGURE 4 and in metal removal activity. In addition it was low in the yield of coke and educed asphaltene. ACTIVITY OF To this, resistance to attrition had been improved. SAND BITUMEN DERIVED OIL Now further improvements in this catalyst were at- TAR tained and catalyst DAM-247 was developed. A secondary evaluation was made using the 0.1BPD 100 100 slurry-bed bench plant. The results are shown in - Athabea Table 1. Catalyst DAM-247, even in the bench so plant evaluation, was found to have higher middle 50 - distillate yield and lower yield of coke and educed asphaltene. 60

Athfln TABLE 1 40 40 a PERFORMANCE OF CATALYSTS DAM-247, 20 CerroNogro 20 DAM-022 .0 0 Catalyst Catalyst 390 410 430 390 410 430 DAM-247. DAM-022 Reaction Temperature (C) Reaction Temperature CC) 100 IN Metal Removal (wt%) 99.0 96.1 Athebaica 90.6 88.8 D easphaltene (wt%) 80 80 Dcsulfurization (IV t%) 70.7 65.2 Athabasca N Removal (wt %) 60.0 64.6 Hydrogen Consumption (Nm3kl) 160 200 Gas Yield (wt%) 11.6 11.7 40 Naphtha Yield (wt%) 11.8 12.6 Middle Distillate x Yield (wt%) 30.9 27.2 20 20 Vacuum Gas Oil (w t %) 29.6 30.8 Vacuum Bottom (wt%) 9.8 10.7 0 • 0 Coke and Educed 390 430 430 390 410 430 Asphaltene Yield (wt%) 6.3 7.4 Reaction Temperature CC) Reaction Temperature (t) Conversion (wt9o) 89.4 87.3 Catalyst: C3I2 Reaction Conditions hess. ISOlcg/cn'G I2ISV Q.7b' H,/HC ratio 1. NnW 525°C

Hydrogenation activities of feedstocks derived from Cerro Negro and Athabasca oil sands bitumens were H ydrodenitrogenation experiments were conducted evaluated using a typical catalyst and a circulating at various reaction conditions using Asian X shale type reactor. The results are shown in Figure 4. oil as the feedstock and the same catalyst as used in the life tests. The reason for this behavior is believed to be that the Cerro Negro feedstock as compared with the The properties of the hydrodenitrogenated product Athabasca feedstock is heavier and contains greater oils were inspected from the viewpoint of Japanese amounts of metals such as sodium which cover up Industrial Standards (JIS) of Petroleum Products. For the kerosene fraction, the smoke point and the acidic points on the catalysts. color would meet the JIS specification for NO. 1 Hydrorefining Shale Oil with Fixed-Bed Reactors kerosene (smoke point: + 23 mm, Saybolt color: t 25) only when treated under the severest reaction Life tests of newly developed conditions employed. In the case of the gas oil denitrogenation catalysts were carried out, after fraction, the cetane index meets the JIS specifica- which properties of the spent catalyst were inves- tion but the pour point needs to be improved. tigated. The decreasing rate of specific surface While the color of gas oil is not specified in the area and pore volume seem to be correlated with JIS specification, in order to attain the color of the content rather than with the carbon currently marketed gas oil (around ASTM Color content. Thus in catalyst , deactivation, the deposit 0.5), it has been found that a severe treatment is of arsenic plays an important role, excluding the required, the same as in the case of the kerosene initial stage of 200-300 hours where rapid deactiva- fraction. tion due to carbon deposition takes place.

1-16 SYNTHETIC FUELS REPORT, DECEMBER 1986 Hydroretlnhiig Shale Oil with Ebullated Bed Roan- TABLE 2 torn The overall organization of a refining system for PERMISSIBLE BLENDING RATIOS OF SYNCRUDE1 shale oil is shown in Figure 5. The 2nd-stage treating of the gas oil fraction from syncrude was conducted to investigate the relation of operating Permissible Blending Ratios conditions to quality and stability of the treated Operating for Gas OH Fraction from Permissible Blending oil. The gas oil fraction of syncrude (nitrogen con- Conditions Syncrud1e Ratios f Syncrude tent of 5,000 wt ppm) derived from an Asian shale vol 96 vol 96 oil and the gas oil fraction of Arabian Light crude were mixed to prepare feed oils of varying nitrogen contents for 2nd-stage hydrotreating. II 9 4 VIII 11 5 The permissible nitrogen content of the feed oil for X 20 9 each 2nd-stage treating condition was obtained. X 20 9 The permissible blending ratios of syncrude are 83 40 shown in Table 2. Increasing the severity of XII

operating conditions from II to X, the permissible *1) calculated with gas oil fraction as base nitrogen content for 2nd-stage treating feedstock *2) versus gas oil fraction from Arabian Light crude increased from 380 to 700 wt ppm, and the permis- *3) versus Arabian Light crude sible blending ratios of syncrude increased from 4 to 9 vol% (versus Arabian Light crude). The per- missible blending ratios of syncrude may be in- creased by reducing the LIISV. Cold flow model tests were conducted to obtain engineering data for construction and operation of a large-scale bench plant. After those tests, a large-scale bench plant with a capacity of 1.5 bar- rels per day was designed and constructed for the development of the ebullated 1st-stage hydrorefin- ing process.

FIGURE 5

REFINING SYSTEM FOR SHALE OILS

stage) (2nd gage) Ord heavy Naphtha Fraction G asoline tratia—.- Reformer Charge _—[ mm Blending Stock list gage) Kerosene Fraction Kerosene Raw Shale Oil ! (Finished Product) Gas Oil Fraction Gas Oil I I .;i;;i___•. (Finished Product) FCC Charge Gasoline Residual Oil Charge LECrIF-ackle Blending Stock FO Blending Stock

Heavy Naphtha Fraction

Fraction

PetroleumCrude Oil t:gGas Fraction

Gas Oil Fraction Vacuum Residual Oil

1-17 SYNTHETIC FUELS REPORT, DECEMBER 1986 ENVIRONMENT

CHEMICAL BASIS FOR PHOTO MUTAGENICITY IN Samples SYNTHETIC FUELS TRACED Samples included coal-derived materials from the The high incidence of skin cancers which was seen Solvent Refined Goal (SRC-1) and SRC-II processes. in early shale oil and coal conversion workers An SaG-Il blend of recycle process solvent and at- points to a problem which must be addressed by mospheric flash column bottoms was collected at the developing synthetic fuels industries. The Ken- the liarmarville, PA process development unit. An tucky Energy Cabinet has been funding studies to SRC-1 process solvent was collected from the Wil- aid in developing inexpensive and rapid tests that sonville, AL pilot plant operated by Catalytic, Inc. can predict tumor initiating, tumor promoting, co- and Southern Company Services. carcinogenic and anticarcinogenic activities in syn- thetic fuel materials. Some preliminary results A crude Paraho shale oil and a hydrotreated Paraho from this work were reported recently to the shale oil were obtained from the Oak Ridge Na- American Chemical Society. tional Laboratory Synfuels Research Materials Repository. The crude shale oil was produced by The S. typhimurium histidine revision bioassay (the the Paraho Development Corporation at Anvil Ames assay) has been only partially successful as a Points, CO and hydrotreated at Sohio's Toledo (Oil) short-term bioassay for detecting tumor initiators refinery. or complete carcinogens in synfuels as mutagens. Although positive correlations between the Bioassay microbial mutagenicity and the relative tumor in- itiating capacity of synfuels materials have been Photomutation assay procedures were performed as observed, "false negatives" have been reported. slight modifications of the method of Ames. For example, a hydrotreated Paraho shale oil has Suspensions of Salmonella were untreated or treated been reported to be carcinogenic but not with 1) fluorescent radiation, 2) test substance (in mutagenic. the dark), or 3) fluorescent radiation and test sub- stance, concurrently. Microbial mutagens and carcinogens have both been reported to be concentrated in the highest boiling The Salmonella/mammalian-mierosome test proce- fractions from synthetic fuels. dure of Ames et. al. was used with minor However, the microbial mutagenieity has been modifications. found to reside primarily in fractions enriched in amino-substituted polycycic aromatic compounds. Effect of Hydrotreatment Neutral polycyclic aromatic hydrocarbon-enriched synfuel fractions, which have shown relatevely high Crude and hydrotreated Paraho shale oil samples carcinogenic activity, have demonstrated little or were tested for mutagenicity 1) in the no microbial mutagenicity. Based upon these Salmonella/mammalian-microsome test and 2) in the results, it has been suggested that with synfuels, photomutation assay. When the parent crude and the "apparent correlation between Ames hydrotreated oils were tested in the mutagenicity and mammalian skin tumorigenicity Salmonella/mammalian-microsome test in the ab- may be due to the coincidental occurrence of two sence of microsomal enzymes and in the dissimilar classes of molecules." photomutation assay in the absence of light, no direct-acting mutagens were detected in either oil. Goal- and shale-derived liquids have been known to When the oils were tested using a microsomal en- possess potent phototoxie properties for many years zyme preparation, the results shown in Figure 1 (i.e., they enhance the lethality of non-ionizing were obtained. These results are in agreement radiation). In addition, a positive correlation has with other studies in showing that the crude Paraho been reported to exist between the phototoxic and shale oil is mutagenic and the hydrotreated shale carcinogenic activities of polycydic aromatic com- oil is not deteetably mutagenic in the Ames assay. pounds. More recently, a number of synfuel materials have been shown to possess The photomutagenic responses of Salmonella suspen- photomutagenic activity, i.e., the ability to enhance sions to fluorescent light plus either the crude the mutagenicity of non-ionizing radiation. shale oil or the hydrotreated product oil are shown However, the significance of this photomutagenic in Figure 2. The shale oils were tested at several activity towards potential occupational hazards and concentrations and the mutation frequency the role of photomutagens in effects seen in mam- responses are plotted in Figure 2 as a function of mals are not yet clear. In an effort to determine the product of shale oil concentration times dura- the chemical nature of photomutagens in synthetic tion of irradiation. The apparent dependency of fuels and to determine the relationship between the photomutagenic responses on the product of oil photomutagenic and carcinogenic activities, the concentration times light exposure demonstrates a Kentucky work began testing synfuel fractions form of "reciprocity' of oil and light doses on the (isolated based upon boiling point and chemical photomutagenie response, a phenomenon observed class) that have been chemically characterized and previously with an Eastern U.S. shale oil sample. tested for skin tumor initiating capacity.

1-18 SYNTHETIC FUELS REPORT, DECEMBER 1986

FIGURE 2 FIGURE 1 PHOTOMUTAGENICITY OF CRUDE

MUTAGENICITY OF CRUDE AND AND HYDROTREATED SHALE OILS HYDROTREATED SHALE OILS 5000 500 III

U) 400 - cc 4000- > Crude 5 Cr D Crude + Light 300- U) z ZZ 3000 Cr U) tie I— 4 W 200- z

Cr 0 'Li o 2000 4 100 S Cr Cr I C o t Li 0 I- Hydrotreated C.) Li o o-g 'Hydrotreated '—a— _• _ M 1000-. / O 100 300 500 ipoo spoo 10poo o life i-Light C) I ..ç'{ iii SHALE OIL/PLATE

100 200 300

Photomutagenicity of Ilydrotreated Shale Oil Fine- ni SHALE OIL / mix HOURS IRRADIATED Lions Column chromatography of the hydrotreated Paraho shale oil yielded fractions termed Al, A2 1 AS and A4 which were enriched in aliphatic hydrocarbons, Photomutagenicity of Fractions neutral polycydic aromatic hydrocarbons (PAll), 0 nitrogen-containing polycyclic aromatic compounds The SRC-II 800_850 distillation cut was also (N PAC), and hydroxy-substituted PAC (IIPA C) separated into chemical class fractions by column respectively. The A2-A4 fractions were tested for chromatography. The slope values representing the photomutagcnicity and the mutation frequency mutation frequency response to fractions A1-A4 as responses are shown in Figure 3. The A2 fraction a function of minutes irradiated are given in Table was the most photomutagenic fraction, although all 1. The A2 fraction was clearly the most three fractions were active. photomutagenic fraction; the A3 fraction was also photomutagenic, but the Al fraction was inactive and the A4 fraction was only slightly active or in- Photomutagetheity of Coal Oils active. The SRC-II Al-A4 fractions were not SRC-11 distillation cuts having different boiling delectably mutagenic when tested in the dark. point ranges were tested for photomutagenic ac- tivity. Slope values for mutation frequency Conclusions responses as a function of minutes irradiated are given in Table 1. The data show a trend towards Although a relatively limited number of samples higher photomutagenic activity with increasing boil- were tested, the data suggest that high boiling big point of the material tested. In the absence of point components in the PAll-enriched fraction are fluorescent light irradiation, the same SRC-II cuts the determinant chemical photomutagen in synthetic were not delectably mutagenic. fuels. Substantial photo mutagenicity was also measured in coal oil and shale oil NPAC fractions and the IIPAC shale oil fraction. The HPAC and

1-19 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1 CARCINOGENICITY AND MIJTAOEN1CITT or FIGURE 3 SIC-11 DISTILLATES AND CHEMICAL CLASSES

PHOTOMUTAGENICITY Relative Relative Carcinogenicity Mutaeniclty OF HYDROTREATED MateriaL W° Ames Photomutation1' SHALE OIL FRACTIONS DsulIatsas Heavy disillate 100 100 100 ND 300700°F 0 0 70 2.0 + 2.3 700_750e F 18 87 05 12 9.3 C,) 750-800°F 14 120 138 15 t 3.7 6000 HOT Paraho 42 800-850°F 49 157 148 27 2.2 > Shale Oil Chemical Clacsi Fractions $00..8$0e fraction Al 10° 0 1.3 + 3.8 A2 157 0 200 +01 U, A3 79 700 32 -, 9.2 0 6.6+ 7.7 0)0 43 A4 -

Values are relative to heavy jsUllato, given a value of 100. IF initiation- U) - promotion test. Revertanta/lO survivors/minute irradiated, 50 ug/mI tested. ZI.— . I ND - not determIned. ° not a significant respozae C I 3000- A / amounts of environmental radiation (such as Iii / / fluorescent room light), and the positive correlation shown in Table 1 may reflect a mediation of coal o oil-induced tu morigenesis by photochemical 'IA / processes. It is also possible that photo mu tagenesis F— 44) o I and carcinogenesis by PAC synfuel components W I proceed by the same mechanism. cr -I cr

00 I 2 HOURS IRRADIATED BLM PROPOSES NEW PROCEDURES FOR AREAS OF CRITICAL ENVIRONMENTAL CONCERN In October the U.S. Bureau of Land Management released for comment the proposed revisions to its aliphatic hydrocarbon fractions isolated from the guidelines for areas of critical environmental con- SRC materials were relatively inactive. cern (ACEC's). An ACEC is a public land area where special management is needed to protect im- It is not yet known which compounds present in the portant historic, cultural, scenic and natural values, PAR fractions were responsible for photomutagenic or to protect human life and safety from natural activity. hazards. In summary, of 11 samples that were tested for Robert Burford, Director of the BLM, said that ex- carcinogenicity, photo mutagenicity and enzyme- perience over the past few years had shown the mediated mutagenicity, in 7 cases there was need for improving the existing guidance to BLM agreement between all three assays and in 4 cases field offices on this subject, a position which was the photomutagenicity data was in better qualita- reinforced recently by a policy resolution of the tive agreement with carcinogenicity than were the National Public Lands Advisory Council. mutagenicity data obtained using enzyme activation. The draft guidelines are being made available for The strong agreement between photo mutagenicity review and public comment. When comments have and carcinogenicity among the synfuel materials been analyzed and the guidelines revised, they will could be coincidental. However, the agreement is be issued as a formal directive to all ELM field sufficiently extensive to consider possible fun- offices. Designation of an ACEC indicates to the damental underlying relationships. It is possible public that the ELM recognizes those special fea- that animals exposed to synfuels in the car- tures and has established special management cinogenicity studies were also exposed to significant measures to protect them.

1-20 SYNTHETIC FUELS REPORT, DECEMBER 1986 Areas of critical environmental concern are desig- c. Management Desire to Highlight. There is nated through the resource management planning a need to highlight unique or special process. ACEC's may be designated in a resource resources or hazardous conditions. A management plan (R M P), plan amendment, or, in resource or area may be found relevant cases where there is no existing plan and even if there are no known or potential require special a II MP is not now scheduled, in a planning analysis. threats or risks which The provisions of the Federal Land Policy and management action. Management Act (FLPMA) require that the BLM give priority to the designation and protection of 2. Importance. An environmental resource or ACEC's during the development and revision of land natural hazard may be identified as "important" for use plans. one of the following reasons: The proposed guidelines govern the identification, a. Significant Resource Qualities. Importance evaluation, and designation of ACEC's. Highlights may be based on qualities or circumstances of the guidelines follow, that make the resource fragile, sensitive, rare, irreplaceable, endangered, threatened, Characteristics or vulnerable to adverse change.

1. Compatible with Multiple Use Management. b. Significant Threat to Life and Safety. A A variety of multiple use activities may take place natural hazard poses a significant threat, within an ACEC. These activities, however, must either existing or potential, to human life be compatible with the primary management objec- and safety. tive of the ACEC.

2. Require Special Management Attention. No Nomination and Management of Nominated Areas two ACEC's are alike and management prescriptions are tailored to each ACEC. The management 1. Nominations. An area may be "nominated" practices and the allowable uses of an ACEC as a potential ACEC by Bureau personnel, inter- necessary to protect resource values or to protect ested publics, or others. human life and safety are specified in the plan. 2. Preliminary Evaluation. The information The ACEC designation itslef does not automatically available on a nominated area is evaluated on a impose any restriction or limitation on entry to or timely basis to determine if the identification use of the public lands (e.g., it is not, by definition criteria are met. This evaluation is made by the a withdrawal). District Manager in writing.

3. Have Established Boundaries. The at- 3. Temporary Management. The District tributes of the resources, values, or natural hazards Manager must decide whether an area nominated and management considerations require that the for ACEC consideration is threatened and warrants boundaries of an ACEC be specified. There is no temporary management. size limitation, but an ACEC should be held to the minimum area necessary to protect life and safety ACEC's in the RMP Planning Proce or the resources on which the designation is based. The ACEC designation is not used as a substitute Early in the planning process, the available inven- for a suitability recommendation for a wilderness tory data and information are reviewed by the Dis- study area. trict and Area Managers and the interdisciplinary team. This review determines whether there are Identification in Resource Management Planning places in the resource area with ACEC attributes that should be considered in the planning process. All areas which meet the identification criteria must be considered as potential ACEC's in the The boundary of a prospective ACEC is closely planning process. A potential ACEC must meet reviewed. This review examines surrounding or ad- the relevance and importance criteria to become jacent public lands and considers likely management eligible for further consideration. requirements and their feasibility. The BLM Dis- trict Manager determines from the analysis of the 1. Relevance. A resource or natural hazard management situation whether or not an area under may be identified as "relevant" for one or more of study meets the ACEC identification criteria. the following reasons: All potential ACEC's must be included in the a. Known Threat or Risk. There is an im- preferred alternative unless there is a clear and mediate need for special management ac- documented reason not to do so. tion and attention. When the proposed plan and final environmental Potential Threat or Risk. There is a long b. impact statement (EIS) include an ACEC, the term need for special management to avoid management practices and uses, including any irreparable damage or risk to life and mitigation measures and use limitations identified safety. to protect the ACEC, are set forth. State Diree-

1-21 SYNTHETIC FUELS REPORT, DECEMBER 1986 tor approval of the plan constitutes formal designa- Previous Designations. tion of any ACEC involved. The ACEC's are usually designated for the life of the plan unless A variety of areas have been established for spe- otherwise specified in the II Ml'. cial management by DLM under the expired Class- ification and Multiple Use Act of 1964 and related The requirements for the protection and manage- provisions of 43 CR1 2070 (Designation of Areas ment of ACEC's are stated to be generally not and Sites) and the 43 CPR 8352 (Established compatible with public land disposal. In the event Areas). These designations include outstanding an ACEC designation is proposed on a tract also natural areas, primitive areas, and resource conser- identified as meeting public land disposal criteria, vation areas. the public notice describing the proposed ACEC must specify that fact. To avoid confusion, BLM suggests that use of the terms "special area" or "special management area" Notification should be avoided in the future. To avoid am- biguities the ACEC procedures set forth must be When an area is identified during preplanning as a used as a basis for future designations of outstand- prospective ACEC, it is described in the notice of ing natural areas (ONA's), research natural areas intent (NOD. All existing ACEC and related desig- (RNA's), natural hazard areas (NHA's) and other nations (research natural areas, outstanding natural areas requiring special management attention in the areas, etc.) are also identified in the NOl so that sense used in the ACEC provisions. The 43 CFR the public has the opportunity to participate in 2070 (Designation of Areas and Sites) and the 43 their re-evaluation. A special notice is required to CFR 8352 (Established Areas) will he removed from be published in the Federal Register. A minimum the Federal regulations when revisions to the ACEC 60-day public comment period for review of a guidance are completed. These regulations are proposed ACEC is initiated by the special notice. outdated and have been a source of confusion in Since a draft RMF and EIS are open to comment relation to the ACEC requirements during the plan- for 90 days, the notice of the filing of a draft EIS ning process of areas requiring special management can also be used to fill the requirements of the attention. special ACEC notice.

1-22 SYNTHETIC FUELS REPORT, DECEMBER 1986 RESOURCE

IGT CALCULATES WORLD RESERVES OF FOSSIL Although the U.S. share of oil reserves is not FURLS nearly as large and is declining rapidly (Figure 1), its coal reserves are very large, and it also has The Institute of Gas Technology has published the significant resources of and oil shale. IGT World Reserves Survey, giving their latest tabulation of world reserves of fossil fuels and The United States has been and continues to be a . The report contains 120 Tables and 41 leading producer of natural gas, natural gas liquids, Figures. Estimates are provided for proved coal, oil and uranium, although it does not produce reserves, resources, current production, and life in- as much coal as might be expected in view of the dexes of the non-renewable energy sources of the abundance of this resource (Figure 2). United States and of the world as a whole. World regional data are also provided in many cases. Tables 2 and 3 indicate the estimated lifetime of world and U.S. fossil fuel resources for different The excellent position of the United States with assumptions on the rate of growth in demand respect to total fossil energy is clearly evident in (consumption). As seen, a 4 percent per year in- these tables. As seen in Table 1, the United crease in demand for fossil fuels would exhaust States has approximately one fifth of the total U.S. proved fossil reserves by the year 2020 (assuming that all demand was satisfied by domes- world reserves of fossil fuels. tic production, i.e. no net imports). Note that the

TABLE 1 NONRENEWABLE CONVENTIONAL U.S. AND

Proved and Estimated Current Total Remaining Recoverable Recoverable Crude Oil, billion bbl - U.S. 31.2 187 World 720 1480 Natural Gas, trillion CF U.S. 203 987 World 3620 7830 Natural Gas Liquids, billion bbl U.S. 7.64 29.6 World 109 220 Syncrude from Shale and Tar Sands billion bbl U.S. 76.5 1041 World 770 4310 Coal, billion short tons U.S. 323 1030 World 1063 5580 Total Fossil Fuel Energy, 10' s BTU U.S. 8000 44,100 World 34,100 156,000 Uranium Oxide at <$30/lb, thousand short tons U.S. 180 1360 Free World 2090 4040

1-23 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 1 U.S. PROVED RESERVES OF CRUDE OIL AND NATURAL GAS

350 A.G.A.. API DATA I DOE- 500- 250 ADDED NATURALIL GAS 200 . TII006Iu/CF

RO 2 150 ^ - T 5.8 x I0 Btu /bbl

100 I.e 4 GAS TO OIL It RATIO t-c._____ 50 PROVEDIN . 1.42 RESERVES C, C I •1 1945 1950 1955 1960 1965 1970 1975 1960 1985 YEAR

TABLE 3

POTENTIAL LIFE OF U.S. FOSSIL FUEL RESOURCES AT VARIOUS DEMAND GROWTH RATES Date When Remaining Annual Reserve/Consumption Ratio GrowthRate,% Dropsto10years

TABLE 2 4 2020 2056 3 2026 2072 POTENTIAL LIFE OF WORLD FOSSIL FUEL 2 2036 2101 RESOURCES AT VARIOUS DEMAND 1 2053 2165 GROWTH RATES A: Proved fossil fuel reserve B; Total remaining recoveralbe resources Date When Remaining Annual Reserve/Consumption Ratio GrowthRate,% Dropsto10Years resources considered in Tables 2 and 3 include oil from tar sands and oil shale. This would require a very different fuel mix than now in use. 4 2022 2057 3 2029 2075 2 2040 2105 Table 4 is IGT's summary of the major heavy crude 1 2059 2171 and bitumen deposits in the world. A: Proved fossil fuel reserves Table 5 provides an overall summary of estimates B: Total remaining recoverable fossil fuel resources of oil recoverable from tar sands and oil shale. It can only be viewed as a preliminary "guesstimate', because the basic data are incomplete and of low quality. Most areas have not been well explored, largely because conventional crude oil is available in good supply and at a price which is low enough

1-24 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 4 TABLE 5

LARGE HIT ESTIMATES OF SYNCRUDE RECOVERABLE AND BITUMEN DEPOSITS FROM TAR SANDS AND OIL SHALES (Billions of Barrels) Heavy Crude Oil Million bbl

Orinoco Oil Belt () 1,000,000 Remaining Cold Lake (Canada) 187,000 Proved Reserves Recoverable Maracaibo Basin 80,000 Six Fields (U.S.A.) 53,638 Africa Lloydminster Area (Canada) 40,000 Tar Sands 9.2 10 Maturin Basin (Venezuela) 40,000 Oil Shale 195 200 Eight Texas Fields (U.S.A.) 30,568 204.5 210 "F" Structure (Iran) 20,000 Apure-Barinas Basins (Venezuela) 10,000 N. America Quaiyarah (Iraq) 10,000 Tar Sands 29.0 265 Subtotal 1,471,206 Oil Shale 75 2100 Rest of the World 55,000 104.0 2365

Total 1,526,206 S. America Tar Sands 50 150 Bitumen Million bbl Oil Shale 100 800 150 950 Triangle (Canada) 1,350,000 Athabasca Deep (Canada) 722,200 Europe* Chieldag (U.S.S.R.) 280,000 Tar Sands 0.4 1 Athabasca (Canada) 140,000 Oil Shale 204 210 Melekess (U.S.S.R.) 123,000 204.4 211 Melville Island (Canada) 100,000 Lena-Angararsk (U.S.S.R.) 70,000 Asia* Peace River (Canada) 72,000 Tar Sands 6.6 115 Bemolanga (Madagascar) 21,000 Oil Shale 32 175 Tugunska (U.S.S.R.) 17,500 38.6 290 Tar Sand Triangle (U.S.A.) 16,000 Ragusa (Italy) 14,000 U.S.S.R. Silinger (U.S.S.R.) 13,000 Tar Sands 15 100 Subtotal 2,938,700 Oil Shale 50 175 Rest of the World 126,700

Total 3,065,400 Oceania Tar Sands 1 5 Oil Shale 1 5 I 170 to provide little incentive for the research and development needed for the exploitation of tar World Totals sands and oil shales. Probably only the Alberta tar Tar Sands 112 646 3665 sands and Western U.S. oil shale are reasonably Oil Shale 657 well known. However, it would appear that there 769 4311 oil recoverable from these is as much or more * sources as there is from remaining recoverable Excluding U.S.S.R. conventional crude oil sources. ## It U

1-25 SYNTHETIC FUELS REPORT, DECEMBER 1986 RECENT GENERAL PUBLICATIONS /PATENTS

The following papers were presented at the 1986 Annual Meeting of the American In- stitute Of Chemical Engineers in Miami Beach, Florida, November 2-7, 1986:

Paspek, S.C., "Upgrading of Heavy Hydrocarbons with Supercritical Water Solutions."

Crynes, B.L., et al, "The Use of Composite Catalyst Beds for Hydrotreatment of Heavy Fuels."

Dooley, K.M,, et al, "Oxidation Catalysis in a Supercritical Fluid Medium."

The following papers were presented at the 36th Canadian Chemical Engineering Con- ference in Sarnia, Ontario, Canada, October 5-8, 1986:

Labrecque, B., et al, "Thermal Decomposition of Scrap Tires Into Oils and Charcoal."

Berruti, F., et al, "Measuring and Modeling Residence Time Distribution and Pyrolysis Reactions of Low Density Solids in a Fluidized Bed Reactor of Sand Particles."

Utioh, A., et al, "Catalyzed Pyrolysis of Grain Screenings."

Graham, R.F., et al, "Fast Pyrolysis (Ultrapyrolysis) of Poplar.

American Petroleum Institute, "Two Energy Futures," 1986 Edition.

Kalt, J.P., et al, "A Review of the Adequacy of Electric Power Generating Capacity in the United States, 1985-93 and 1993-Beyond," Energy and Environmental Policy Center, John F. Kennedy School of Government, Harvard University, E-86-09, June 1986.

1-26 SYNTHETIC FUELS REPORT, DECEMBER 1986 COMING EVENTS

1987

FEBRUARY 1-6, NEW ORLEANS, -- Society Winter Meeting.

FEBRUARY 2-6, ORLANDO, FLORIDA--Annual Meeting and Exhibition of the Society of Min- ing Engineers.

FEBRUARY 2-6, HONG KONG, CHINA--2nd International Pacific Rim Coal Conference.

FEBRUARY 2-6, PRETORIA, SOUTH AFRICA--Ash: A New Resource Symposium.

FEBRUARY 15-19, DALLAS, TEXAS--Technical Economics, Synfueis and Coal Energy Sym- posium, Energy Sources Technology Conference.

FEBRUARY 24-27, DENVER, COLORADO- -Annual Meeting and Exhibition of the Society of Mining Engineers.

MARCH 23-25, WASHINGTON, D.C.--14th Annual Energy Technology Conference and Exhibi- tion.

MARCH 29-APRIL 2, HOUSTON, TEXAS--AIChE Spring National Meeting and 1987 Petrochemi- cal and Refining Exposition, Astrohall.

MARCH 30-APRIL 3, NEW ORLEANS, LOUISIANA--12th International Conference on Slurry Technology.

APRIL 5-10, DENVER, COLORADO--193rd National Meeting of the American Chemical Society. APRIL 7-9, READING, UNITED KINGDOM--5th International Conference on Energy Options: The Role of Alternatives in the World Energy Scene.

APRIL 8-11 9 SAN FRANCISCO, CALIFORNIA--Alternate Energy '87, Council on Alternate Fuels.

APRIL S-il, KUALA LUMPUR, MALAYSIA--Asian Energy/Power Conference and Exposition.

APRIL 16-19, MINNEAPOLIS, MINNESOTAAIChE Summer National Meeting.

APRIL 26-MAY 1, HOUSTON, TEXAS--12th World Petroleum Congress.

APRIL 27-29, LEXINGTON, KENTUCKY--International Coal Preparation Conference and Ex- hibition,

MAY 3-6 2 CINCINNATI, OHIO--Coal Convention, American Mining Congress.

MAY 7-12, BEIJING, CHINA--2nd International Coal Technology Conference and Exhibi- tion.

MAY 19-21, DALLAS, TEXAS--14th Biennial Lignite Symposium on the Technology and Utilization of Low-Rank .

JUNE 1-3, TAMPA, FLORIDA--37th Vehicular Technology Conference.

JUNE 6-8, CALGARY, CANADA--9th Annual Meeting of the International Association of Energy Economists.

JUNE 7-10, , CALIFORNIA--American Association of Petroleum Geologists An- nual Meeting.

JUNE 9-11, LONDON, UNITED KINGDOM--6th International Conference and Exhibition on Coal Utilization.

JUNE 23-25, HARROGATE, UNITED KINGDOM1st European Conference on Dry Fine Coal.

1-27 SYNTHETIC FUELS REPORT, DECEMBER 1986 JULY 6-9, LISBON, PORTUGAL--Solid Fuel Utilization International Specialists Meeting.

AUGUST 9-14, PHILADELPHIA, PENNSYLVANIA--22nd Intersoeiety Energy Conversion En- gineering Conference.

AUGUST 24-27, PRETORIA, SOUTH AFRICA-- International Coal and Gas Conversion Con- ference.

AUGUST 30-SEPTEMBER 4, NEW ORLEANS, LOUISIANA--American Chemical Society National Meeting.

1-28 SYNTHETIC FUELS REPORT, DECEMBER 1986 n olil sflalite

PROJECT ACTIVITIES

EASTERN SHALE IN SITU PROJECT COMPLETES Allis-Chalmers Corporation. The engineering study BLAST TEST would be the first step of a multi-phase approach to develop a shale oil industry in the State of In- Eastern Shale Research Corporation is studying an diana. in situ process to recover oil from eastern shnle. The technique will be a near-surface nibbling and The demonstration retorting complex consists of the horizontal retorting approach similar to that retort, an open pit mine, shale preparation and developed by Geokineties in Utah. product storage facilities, pollution abatement equipment, utilities, buildings, roads, etc. Design The project was funded in September of 1985, and activities assumed a plant location on private is jointly funded by the United States Department property some four miles north and cast of Uen- of Energy, the Indiana Corporation for Science and ryville in northern Clark County, Indiana. The 73 Technology, the Indiana Division of Energy Policy acre site is within the outcrop and Eastern Shale Research Corporation. It in- belt and is representative of a location that could cludes the selectIon of a site, and construction and be chosen for an oil shale operation. Here, oil operation of a small horizontal retort. shale suitable as retort feedstock is close to the surface, sources of water and electric power are According to Victor Carr of Eastern Shale Re- nearby and only minimal road construction is search, a site was initially selected south of Scot- required for access to the property. tsburg, Indiana. However, drilling at the site lo- cated an unsuspected irregularity in the formation P reee directly above the shale. In addition, the above the shale was heavily influenced by the rainy The Allis-Chalmers roller grate retorting technology weather, and caused difficulty in maintaining open was utilized in the design and costing of the holes. A decision was made to move to a site demonstration retort. Shale is pyrolyzed as it is about three miles north. moved through preheat and retorting zones by a crossflow of hot recycled noncondensable hydrocar- The second site has proved to be more desirable. bon gases and water vapor. Energy to heat the The overburden was dry enough to allow holes to process gases is provided by burning residual carbon be completed with less trouble, although it was contained in retorted shale as it is conveyed still advisable to case through the clay. The clay through the combustion zone. Products from a overburden at this site is twelve feet thick. commercial oil shale facility using this technology will include shale oil, high BTU gas and thermal A retort blast design was developed and tested. energy. In addition, depending upon t' A' type of The design used charges placed at multiple levels flue gas scrubbing system used, sulfuric acid or with stemming between charges. Charges were other forms of sulfur may be recovered as a by- held to below five feet from the top of the shale product. Due to the limited life of the demonstra- to allow the shale directly under the clay to tion plant, however, high BTU gas and thermal remain as intact as possible to lift the clay. energy would not be recovered as salable products.

The above ground results of the blast were said to The roller grate spans a width of 8 feet between be very close to design expectations. It was inner walls of the processing unit and is about 150 reported to the 1086 Eastern Oil Shale Symposium feet long. Rolls are slotted to permit passage of in November that re-entry drilling was in progress, process gases. An advantage of the roller grate is to define the underground results. Good com- the gentle agitation imparted to the shale bed, munication of air was demonstrated between the resulting in greater heat transfer, lower pressure holes. Final results of the retort evaluation will drop, greater oil yield, and higher carbon burnout determine whether this retort will be burned. than would occur in a static bed process. The rol- ler grate is designed to carry a 30-inch-thick bed through the 500-BPD processing unit at a velocity of 1.8 feet per minute.

CLIFFS ENGINEERING, ALLIS-CHALMERS Demonstration plant production, based on processing COMPLETE INDIANA COST ESTIMATE 1,680 tons of oil shale having a Fischer • Assay of 12.5 gallons per ton and assuming a t00% of Fis- Cliffs Engineering and Allis-Chalmers recently com- cher Assay recovery would be 500 barrels per day. pleted an engineering study entitled "The Indiana However, recent tests performed by A-C have indi- Oil Shale Project". The study provides preliminary cated that oil recoveries of up to 150% of Fischer design data and cost estimates for the construction Assay might be expected. and two-year operation of an Allis-Chalmers 500- barrel-per-day, demonstration-scale retort. Funds Included as part of the demonstration retorting were provided by the Indiana Corporation for complex is a wet sulfuric acid plant designed as a Science and Technology, the United States Depart- segment of the pollution control system. When ment of Energy, Cliffs Engineering, Inc., and the

2-1 SYNTHETIC FUELS REPORT, DECEMBER 1986 operating at capacity, this plant will produce some weeks later the plant was again operating at about 100 tons per day of sulfuric acid during the 50% of its 10,000 barrel/day design capacity. This demonstration program. Is the maximum rate which has been achieved for long periods of time, although Unocal said that it Demonstration Program did operate at full capacity for a brief period last summer. Some 160,000 barrels of shale oil were The proposed demonstration program schedule shows produced during the summer in 40 days of opera- 18 months of project lead time to prepare s firm tion. cost proposal, complete preproject monitoring and permitting activities and perform sufficient detailed Fifty new employees were hired at the plant site engineering to meet procurement and construction in anticipation of beginning continuous operations, start-up requirements. An 18 month period is this brings the plant site employment up to 450. scheduled for construction of the retort and as- sociated support facilities. A two-year operating Fluid Bed Combustor period for the demonstration retort is planned. Unocal has been continuing to explore the pos- According to H. Raymond of Cliffs Engineering, the sibility of adding a fluidized bed combustor to the two-year demonstration program, would consume retorting system. The Company agreement with 882,000 tons of oil shale assaying 12.5 gallons per the U.S. Synthetic Fuels Corporation could provide ton. Estimated shale oil production, assuming only an additional $500 million in loan and price 110% Fischer Assay recovery will be about 290,000 guarantees if the FBC technology is installed. barrels. In addition, some 50,000 tons of sulfuric Samples of retorted shale have been sent to Lurgi acid will be produced as a by-product from flue in West Germany for testing in a circulating FBC gas desuifurization. These products would be sold unit. A decision on whether to proceed with build- to help offset costs of the demonstration program. ing the FBC is expected to be made by July, 1987.

Cost Estimate Reclamation

Capital and operating cost estimates were The Colorado Mined Land Reclamation Board has developed with an accuracy of + 30% A summary allowed Unocal to make changes at Parachute of the demonstration program costs is given in Creek to better accommodate the handling of spent Table 1. shale. The changes allow Unocal to replace a con- veyor belt system with a radial stacker system for moving and piling spent shale in a disposal area. TABLE 1 The radial stacker disperses shale in a broader area than is possible with a conveyor system. INDIANA OIL SHALE COST SUMMARY Unocal will also be allowed to build an inter- Capital Costs: mediate bench on the mountain below the retort to give trucks and loaders better access to the spent Process Plant $45,450,000 shale. The changes were needed because the spent Infrastructure & Support 5,670,000 shale pile angles were getting too steep and Unocal Construction Management Fee 256,000 had problems with water running off too quickly, Subtotal $51,376,000 forcing them to use more water than desired.

Operating Costs: The Mined Land Reclamation Board was concerned about where the drainage from the shale pile would Process Plant $14,579,000 go, and wanted to make sure none would spill into Infrastructure & Support 10,150,000 the East Fork of Parachute Creek. All runoff is Product Revenue -4,822,000 to be caught in Unocal's interceptor ditch, where it Subtotal $19,907,000 will evaporate.

Project Abandonment Costs: $1,999,000 Operating Problems

Total Project Costs $73,282,000 R. Stegemeier, President of Unocal Corporation discussed some of the plant's operating problems at a press conference in which he pointed out the wisdom of continuing with oil shale development during a period of low oil prices and rising imports.

UNOCAL RESTARTS PARACHUTE CREEK PLANT AFTER TURNAROUND He reviewed the plant startup history, in which the original scraper system did not work as planned. In late November, Unocal Corporation restarted its The scraper has to push the hot, retorted shale Parachute Creek shale oil project after a two from the top of the retort into the disposal chutes month turnaround, or overhaul operation. The tur- for cooling. The scraper system was redesigned naround was completed on November 10 and by 2 and worked well during resumed startup operations in 1984.

2-2 SYNTHETIC FUELS REPORT, DECEMBER 1986 Late in 1984, enough shale oil had been accumu- WHITE RIVER PROJECT TURNED OVER TO ELM lated to conduct a short operation of the upgrading plant. The plant worked effectively at full design In late September, the White River Shale Project in rate of 10,000 barrels per day and produced southeastern Uintah County was turned over to the syncrude that met or exceeded design specifica- Bureau of Land Management. This marked the end tions. of nine months of cooperative negotiations on terms of the pullout. This is the first time the However, difficulties with the retorted shale cool- BLM has owned an oil shale project. ing system prevented continuous operation of the retorting plant. The retorted solids exit the top of The White River Shale Project surface facilities, the upflow retort at about 900 degrees F and then about $40 million in buildings, water and sewer must be depressurized and cooled before disposal. treatment facilities, air and mine portals will be maintained by the BLM until the economy is right The retorted shale is cooled by spraying water onto to again lease the facility. the hot solids in a vertical shaft cooler, generating steam. The amount of fines generated during White River, composed of Sun, Phillips and Sohio, retorting turned out to be substantially greater conveyed to the BLM ownership of all constructed than expected and created an impermeable barrier facilities, roads, power lines, earthworks and mine that the water or steam could not penetrate. As a construction. result, steam Was often trapped temporarily within the semi-cooled solids, creating high-pressure bursts White River also gave $1 million to the BLM to be when it broke free. used to defray the cost of maintenance and security of the facility. Extensive modifications to the shaft cooler were completed in July 1986. Stegemeier acknowledged Previous agreements were to use the interest off that the shaft cooler, although operational, still the $1 million to pay for the maintenance of the needs improvement. Some problems remain with facility, but the U.S. Treasury Department ruled the joint operation of the retort and cooler. The that the interest could not be used. FBC retrofit would be attractive because it would replace the cooler. In exchange for the monetary contribution, the BLM released White River from any liability and Upgrading obligation that may be attached to the two lease tracts. White River was released from the bond Once continuous operation is achieved, the upgrad- posted to ensure compliance with the original lease ing plant will be brought online. However, with stipulations that requires the project to be returned the Gary refinery still in bankruptcy, a new outlet to its condition before the lease, if the lease is must be found for the shale oil syncrude. Current relinquished. plans are to truck the synerude to Lisbon, Utah, where it will be placed in Unocal's Pure pipeline. In 1973 Sun Oil Company and Phillips Petroleum The syncrude will then be pumped through the con- bid $75.6 million for a 5,120 acre tract identified necting Texas-New Mexico pipeline to Midland, as U-a; White River Shale Oil Corporation bid Texas. From there it will be pumped through $45.1 million for the adjacent 5,120 acre U-b tract. Cushing, and then to the Unocal refinery Leases were issued June 1, 1974. The two tracts in Lemont, Illinois. were to be developed as a joint venture operated as the White River Shale Project. White River relinquished its leases to the two tracts December 31, 1985.

Strong support for maintaining the property came from local residents and leaders and Utah's Con- gressional delegation. The agreement gives the BLM the flexibility to maintain the properties until such time as interest in oil shale development oc- curs again. The properties may also be available to universities and similar organizations for re- search.

2-3 SYNTHETIC FUELS REPORT, DECEMBER 1986 CORPORATIONS

NEW OIL SHALE DEVELOPMENT CORPORATION NEW OIL SHALE ASSOCIATION FORMED FORMED A new national Oil Shale Association has been Two small Southern California firms have joined to formed to promote the development of on oil shale promote a new oil shale retorting process. industry.

Shale Development Corporation, a subsidiary of Im- Executive Director of the new association is Paul pox Corporation of Redlands, California and Petzrick, of Compass Corporation, who will direct PI]TIASC, Inc. of San Bernardino, California have the association's efforts in Washington, D.C. formed United Stratum Corporation to develop what they believe will be the first economically feasible The head of the steering committee is Gary Aho of shale oil project in the United States. Cliffs Engineering. Other initial members of the steering committee include Victor Carr, Robert Ad- Using new technology developed by Energy '80 dington and Joseph Fox. Scientific, Inc., the new firm is planning a semi commercial shale oil production facility on Utah Companies interested in the objectives and opera- property controlled by Shale Development Corpora- tion of the Oil Shale Association are urged to con- tion. Phtiasc Inc., whose major business is develop- tact Paul Petzrick or Gary Aho. ing and marketing high technology, will be con- tributing other oil shale holdings to the venture.

United Stratum Corporation states that they will be using an above-ground, indirect retorting system.

2-4 SYNTHETIC FUELS REPORT, DECEMBER 1986 GOVERNMENT

DOE OIL SHALE PROGRAM FOCUSES ON YEAR task is designed to gain a fundamental understand- 2000 FEASIBILITY ing of the phenomena influencing oil production and properties of products. Rapid pyrolysis is studied The U.S. Department of Energy oil shale program to understand the mechanisms and kinetics of the has stated that its goal is to foster development by decomposition reactions. the private sector of an economically competitive and environmentally acceptable oil shale Industry National Engineering Laboratory(IN EL) whose products can compete with petroleum in the marketplace by the year 2000. In FY 1986 the Congress directed the DOE to in- clude INEL in the oil shale program. Funding was As recently summarized by T. Bartke of the Mor- provided to INEL for mining research. The INEL gantown Energy Technology Center, the current project consists of three tasks: assessment of oil DOE oil shale program consists of a combination of shale mining state of the art, advanced mining fundamental and applied research being conducted concepts research, and demonstration of a con- in-house in national laboratories and research in- tinuous mining technique. In the state-of-the-art stitutes and at various industries and universities. assessment, INEL is conducting a literature survey In FY 1986, DOE awarded three cooperative to determine what progress has been made since agreements under a PRDA solicitation and com- the oil shale program terminated its mining re- pleted a Congressionally directed report on the search in FY 1981. Since mining costs account for feasibility of a national oil shale research facility. 25 percent of the cost of the product oil, it is necessary to determine if cost improvements are Primary research areas in the program and major possible. activities within each area are as follows: Through a competitive procurement in association with the Colorado Mining Association, IN EL will Fundamental Process Research seek to demonstrate a water-jet assisted continuous mining technique in an active oil shale mine. - Characterization of Reference Shales Lon Alamos National Laboratory (LANL) - Characterization of Process Phenomena and Products The LANK, project consists of two tasks: correlation of resources, processes, products and effluents, and - Optimization of Processes siting methodology. The correlation task is designed to determine the nature of major and - Characterization of Effluents trace element releases as functions of the raw shale chemistry and mineralogy, retorting condi- Applied Process Research tions, and spent shale mineral character. - Solid Waste Management Lawrence Livermore National Laboratory (LLNL) - Siting Methodology The LLNL project consists of fundamental process research including characterization of process Data Base phenomena and products and optimization of processes. The optimization effort includes retort Major Plants, Test Data, Resource, Math systems operations and retort component studies. Models The emphasis at LLNL is on surface processes, especially those employing hot solids as the heat Morgantown Energy Technology Center (METC) transfer medium. The M ETC in-house project consists of four tasks: Laboratory studies include pyrolysis, char combus- systems analysis, mathematical modeling, fundamen- tion, sulfur evolution and capture, nitric oxide, tal laboratory studies, and data bases. Both east- formation, oil loss mechanisms including ern and western shales are considered in all tasks. oil coking and cracking reactions, and solids flow. The systems approach is to identify least-cost op- tions and to use results to direct research in the LLNL has operated its 1-2 TPD continuous loop most promising directions. This approach evaluates solids-recycle retort, using both a two-stage all efforts from mining to production of finished fluidized bed pyrolyzer and a cascading mixer and oil; it includes yields, product characteristics, gravity bed pyrolyzer, processing both lean and rich process conditions, environmental impacts, and western shale and eastern shale. costs. Sandia National Laboratory(SNL) Fundamental research studies focus on pyrolysis un- der rapid heat-up conditions and on characterization The SNL project consists of development of a pre- of shales and their decomposition products. This dictive capability for in situ oil shale processing. This involves developing models to predict fragment

2-5 SYNTHETIC FUELS REPORT, DECEMBER 1986 size distributions and void distributions in oil shale vertical modified in situ retorts to avoid subsidence as a function of an explosive blast design. These and possible interconnection of aquifers. Radio results are then used to predict the flow through frequency (volumetric) heating of oil shale in the the retort and the'subsequcnt retort performance. low void reactor vessel has confirmed the feasibility of the technique and the survivability of The characterization effort includes modeling and antennae in situ. experiments in motion. A 100-kg retort is utilized to investigate the influence of bed struc- Characterization of effluents, the primary focus of ture on the retort process and provide data for the the environmental research at Will, has resulted in models. SNL has demonstrated that yield losses organic and inorganic profiles for aqueous effluents. due to permeability contrasts within a retort can Separation schemes have been developed for various be minimized through control of particle sizes. fractions and further fractionation of these frac- Uniform retorting can be accomplished by using tions. particle size differences to counteract void dif- ferences that accompany a large-scale blast. Cliffs Engineering, Inc. (Cliffs) Kentucky Center for Energy Research Laboratory Cliffs developed preliminary engineering designs and (KCERL) cost estimates for a 500-BPD oil shale demonstra- tion plant to be located in southern Indiana. The KCERL has two projects within the DOE oil shale plant will utilize the Allis-Chalmers roller-grate program. In one project, KCERL is conducting retorting technoloby. field and laboratory studies on retorted Kentucky oil shale. In the second project, awarded under the Energy and Environmental Engineering, Inc. (REEl) FY 1986 Program Research and Development An- nouncement, KCERL is using a combined gas/solid EREI was selected for an award under the F? 1986 heated dense phase fluidized bed oil shale retort PRDA for advanced oil shale concepts. The (KENTORT II) with eastern oil shale to enhance oil, project will begin in FY 1987. EEEI will inves- gas, and sulfur recovery. tigate the utilization of heat pipes to transfer heat from a combustion zone to a pyrolysis zone in an Mineral Resources Institute (MRI) oil shale conversion system. The REEl system in- cludes a fluidized-bed combustor with heat pipes The Mill project is a joint effort with Hycrude and connecting it to the pyrolyzer, and staged fluidized consists of fundamental process research on the beds in a further heat recovery section. combination of beneficiation and hydroretorting of oil shales. This project includes assessment of Eastern Shale Research Corporation (ESEC) various oil shales for beneficiation-hydroretort processing, optimization of beneficiation and The ESRC project consists of a field experimental hydroretorting process variables and environmental program to determine the suitability of an in situ impacts of the two processes, and development of process to recover hydrocarbons from eastern shale. process designs and economic evaluation of the in- Up to three small retorts will be designed, drilled, tegrated system. blasted, and evaluated. One retort will be burned. A site in southern Indiana has been selected. To Western Research Institute develop data on powder loading and shot spacing and timing, ESRC conducted blast tests in a The W RI project consists of six tasks: characteriza- quarry. Upon completion and evaluation of the tion of reference shales, characterization of process quarry tests, the first retort was drilled and phenomena and products, optimization of processes, blasted. characterization of effluents, solid waste manage- ment, and development of data bases. The tasks RYCRUDE Corporation are included in three projects: The DOE-WRI Cooperative Agreement, a contract for study of The Hycrude project is designed to optimize the acid drainage in eastern oil shale, and a contract HYTORT hydroretorting system and to expand the for development of data bases for the pre-1983 data base for hydroretorting of eastern oil shale. DOE data. The project consists of four tasks: development of a hydroretorting data base for six eastern oil Characterization of process phenomena primarily re- shales, investigation of concepts to improve the lates to in situ processes but provides a basic un- hydroretorting process efficiency, investigation of derstanding of the reaction chemistry and transport methods to increase resource recovery by fines processes in oil shale retorting systems in general. utilization, and an environmental analysis of a con- ceptual hydroretorting facility. Optimization of in situ processes includes large- scale laboratory experiments, utilizing 10- and 150- Terra Tek, Inc. ton capacity retorts. Comparison of horizontal retorting of western and eastern shames at low void DOE has established a system of reference shales. volume has been made utilizing a large, single- Terra Tek was selected through a competitive block reactor vessel. Compaction studies are solicitation to establish and maintain a reference providing guidelines for improving the design of shale repository. The repository will supply the oil

2-6 SYNTHETIC FUELS REPORT, DECEMBER 1986 shale program with well characterized, homogeneous The radio frequency project is designed to charac- reference oil shale samples for use in laboratory terize the process phenomena involved in radio experiments. Ten reference shales will be obtained frequency heating of oil shale. The characteriza- from five eastern and five western sites during a tion is being conducted through modeling and five-year period. Ten-ton quantities of well mixed laboratory experiments. A reactor has been reference samples will be produced from 25-ton designed, constructed, and operated with one-foot bulk samples. The bulk samples will be crushed to cubes of western oil shale. Theoretical modeling a maximum size of 3/4-inch, homogenized, stared, of the electromagnetic fields due to a single mo- and maintained under an inert gas blanket. nopole has been completed. Modeling for heat transfer in porous media has been completed. The lJmvemity of Wyoming (Wyoming) feasibility of the radio frequency heating of oil shale has been confirmed. Oil yields and oil Wyoming has two active oil shale projects: oil shale quality are being determined. process water evaporation studies and radio frequency heating of oil shale. The evaporation Wyoming Water Research Center (WWRC) study relates to characterization of effluents and consists of four tasks: collection and evaluation of W W R C was awarded a cooperative agreement under climatological data; collection and evaluation of the FY 1986 PRDA for advanced oil shale con- chemical composition data, model development, and cepts. This project is designed to model hydrologic laboratory and field studies on evaporative emis- conditions and solute movement in processed oil sions. shale solid waste embankments under simulated climatic conditions. Physical modeling will be con- ducted in a 4,800-cubic-foot laboratory lysimeter where temperature, precipitation, and other climatic variables can be simulated.

2-7 SYNTHETIC FUELS REPORT, DECEMBER 1986 TECHNOLOGY

PHILLIPS PATENTS SULFUR RECYCLE tide bed Is formed from a composition comprising RETORTING SYSTEM zinc and titanium, most preferably In the form of zinc titanate. Where the zinc titanate contains at United States Patent 4,599,161, "Retorting Process least one promoter selected from , With Contaminant Removal" was issued to J. Seinta chromium, manganese, iron, cobalt, , molyb- and A. Moffat of Phillips Petroleum Company on denum, rhenium and compounds thereof, hydrogen July 8, 1986. It concerns a method for recycling sulfide present in the effluent stream will be ab- sulfur to the spent shale for disposal. sorbed and organic sulfur compounds which may be present in the stream can be converted to hydrogen Oil shales with high sulfur content produce large sulfide which is subsequently absorbed. quantities of hydrogen sulfide upon pyrolysis and large quantities of sulfur dioxide upon combustion Where unsaturated compounds such as olefins are of residual carbon. Converting these gaseous sulfur present in the effluent from the retort in addition compounds to solids which can be disposed of in an to excess hydrogen, zinc titanate-containing com- environmentally sound manner would be desirable. positions act as a hydrogenation catalyst to hydrogenate the olefin components to paraffins. Also, a portion of the carbon contained in the of the shale is generally not converted to The desorber is identical to the absorber, and the upgraded liquid or gaseous products during the two units are alternately switched back and forth pyrolysis step. This residual carbon is typically from absorption to desorption. combusted with oxygen to provide process heat. A process to provide for increased carbon recovery The desorption zone is connected to a source of in the form of combustible liquid or gaseous oxygen-containing gas, for example, air or products would be desirable. preheated air at elevated pressure. Sulfur deposits are burned from the support material in the Overview of the Invention desorption zone forming 502, which is introduced into a lower portion of the retort. In this manner, In one aspect of the invention, retort offgas con- the absorbent material can be regenerated. The taining hydrogen sulfide is circulated into contact absorber and desorber are brought on line alter- with an absorbing solution which removes the 825. nately in absorption and desorption cycles by the The absorbing solution is periodically regenerated manipulation of the valve shown. Besides the em- by contact with oxygen to liberate sulfur dioxide. bodiment of the invention in the drawing the ab- The sulfur dioxide is then circulated back into the reactor to form a solid reaction product which can be properly disposed of. The retort effluent gas will contain hydrogen in addition to hydrocarbons FIGURE 1 and H 2 S. By selecting a zinc titanate as the ab- sorbing solution, unsaturated compounds in the gas SULFUR RECYCLE will become hydrogenated, thus raising the hydrogen/carbon ratio in the offgas at the same OIL SHAL RETORTING SYSTEM time as reducing the concentration of hydrogen sul- fide.

Another aspect of the invention involves absorbing hydrogen sulfide on a particulate support material. OXYGEN Oxygen is used to liberate 50 21 as before, which is recycled to the retort and reacts with the spent shale. RETORT

DerIption of the Invention A SOR ER HYDROG N DE ORB R As seen in Figure 1, the apparatus comprises a 2 retort, an absorber, and a desorber. For hydrogen- enriched retorting, which is preferred, it is preferred that the retort be of the vertical downflow type. SULFUR- FREE The absorber provides a means for absorbing the PRODUCT hydrogen sulfide from the retort effluent gas. The OXYGEN GAS absorber will generally contain a bed of absorbent, RECYCLE LINE usually a fixed particle bed, although the invention may also be practiced with fluidized beds, moving SPENT SHALE beds, and entrained beds, for example. The par-

2-8 SYNTHETIC FUELS REPORT, DECEMBER 1986 sorption and desorption zones can be portions of a the research involves beneficiating the shales by continuous process using a loop flow of absorbent flotation to concentrate the kerogen into enriched between adsorption and desorption zones, such as products. This work was recently summarized by transfer tine or moving bed units. J. Hanna at the November 1986 Eastern Oil Shale Symposium in Lexington, Kentucky. Conveying the SO 2 from the desorber to the retort provides certain process advantages. The 502 The Mill process involves wet grinding the raw reacts with materials in the spent shale and results shale to minus 20 microns or finer (ultra fine in the production of a solid product easily disposed grinding) followed by froth flotation to recover an of. Additional carbon recovery is also realized. upgraded kerogen product containing 2-3 times According to one reaction mechanism, the 302 more kerogen and organic carbon than the raw reacts with the residual carbon to form a mixture shale. In typical tests, concentrates yielding 30-37 of carbon monoxide, and sulfur. gallons of Fischer Assay Oil per ton were produced The sulfur reacts with iron salts to form iron sul- from raw shale containing only 10-14 gallons of oil fides. Where calcium and magnesium oxides are per ton. present in the spent shale the sulfur dioxide may react with them to form solid calcium and mag- Agglomeration of Beneficiated Shale nesium sulfates or similar salts. The finely ground oil shale concentrates produced Eastern oil shale is generally rich in , which by flotation may be amenable to fluid bed or is converted in the pyrolysis zone to a form which entrained solids flash retort processing to recover reacts with SO 2. Western oil shale is generally the oil by thermal pyrolysis and possibly rich in , which is converted during the hydroretorting techniques. However, because of the combustion of the residual carbon on the spent size consist, the ground concentrates are not ac- shale to a form which reacts with 302 ceptable for retorting techniques like the or the IIYTORT process. The fine-sized A stream of oxygen containing gas is introduced at beneficiated shale must be agglomerated into larger the lower end of the retort for the combustion of sizes for these processes. residual carbon. Gas flow through the retort is upwards, countercurrent to the downward flow of Little information is available concerning ag- oil shale. As the shale descends, it is contacted glomeration of oil shale fines. in Brazil by the hot upwardly rising gas and liberates vapors has briquetted oil shale fines for the PETROSIX which are withdrawn from the retort. retorting process. The briquettes, however, were said to be not satisfactory. A high pressure tech- Where hydrogen is introduced into the side of the nique for compacting oil shale fines into sheets was retort, hydrogen partial pressure in the retort will developed by Allis Chalmers Company. generally be maintained in the range from 200 to 2,000 psi. The hydrogen-containing gases also flow The research at Mill involves briquetting tests on upward to the outlet. The sulfurous gases intro- concentrates recovered from an Alabama oil shale. duced into the bottom of the retort flow upward The ultimate analysis, size distribution and Fischer until the sulfur dioxide contacts a material with assay of the beneficiated sample are given in Table which it can react. Sometimes liquid sulfur will be 1. Limited tests involved briquetting of formed. beneficiated shale samples from Indiana and Brazil. The tests were made wit). and without additives to A preferred absorbent composition comprises zinc determine their effects on briquette strength, oil titanate which has been promoted with cobalt oxide and gas yields and sulfur fixation or removal during and molybdenum oxide. retorting. The absorption zone can be maintained at a tem- perature in the range of about 204 0C to 3990C Briquetting Without Additives where zinc titanate is used as the absorbent. The regeneration cycle where zinc titanate is used as In a series of tests, the dry concentrate was the absorbent will generally be in the range from briquetted at different pressures and ambient tem- 3700C to 815 0C. A temperature of about 540 0C is perature without addition of any reagents. Figure preferred to affect the regeneration within a 1 shows the competency of the briquettes produced reasonable time. at various pressures. These results indicate that the briquettes made at pressures of 5,000 psig and above were competent according to ASTM stand- ards.

ADDITIVES INCREASE YIELD FROM Durability of the briquettes was improved by BENEFICIATED SHALE retorting and their volume decreased by about 8%. This increase in the durability and the volume The University of Alabama Mineral Resources In- reduction of the briquettes after retorting, may be stitute ( M R[) is involved in a research program for due to improvement in the binding properties of recovering the energy values from Devonian black the associated clays, or formation of new cement- shales of the Eastern United States. One phase of ing material derived from kerogen decomposition

2-9 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1 FIGURE 1 CHARACTERISTICS OF ALABAMA BENEFICIATED SHALE EFFECT OF PRESSURE ON COMPETENCY OF THE A: ULTIMATE ANALYSIS BRIOUETTED SHALE

Constituents Weight Percent

Organic Carbon 24.00 0 Hydrogen 2.63 Sulfur 12.15 Nitrogen 0.40 Carbon Dioxide 0.61 Ash (Total Inorganic Matter) 68.20 IIIATEDJIS B: SIZE ANALYSIS

Size Fraction Weight Percent

Plus 20 micron 21.2

20 x 20 micron 54.5 S 45 5• '55 II' 55 4s Minus 10 micron 24.3 WIJONT 5' PLUS *0. MESH SEHERCIATED SI4AL! AFTER flVE DROPS. %

Composite 100.0

C: FISCHER ASSAY

Oil Assay, gal/ton 21.3 Carbon Conversion to oil, weight percent 35.0

during retorting. Oil yield from the briquetted Pan of the study focused on two groups of inor- material was as good as the yield from the uncon- ganic additives which are also potential candidates solidated concentrate. for controlling either the oil shale retorting process or the sulfur distribution in the products of retort- Results of tests conducted on a higher grade ing. The first additive group was comprised of the sample of Alabama beneficiated shale as well as alkali metal hydroxides LiOH, NaOH and 1(011 and beneficiated products of the Indiana and Brazilian Li 2 CO3, Na 2 CO 3 , K 2 CO 3 . The second shales are shown in Table 2. In all cases, the group was made up of alkaline earth hydroxides powdered materials were successfully briquetted Ca(OH)2 , Sr(011)2 and Ba(Oh1) 2 and carbonates without a binder at 10,000 psig. The briquettes CaCO 3 , SrCO 3 , and BaCO3. were found to withstand both Fischer Assay and Hydroretorting conditions.

TABLE 2

RETORTING RESULTS OF BRIQUETTED AND POWDERED BENEFICIATED SHALE

Oil Yield, gal/ton Retorting Oil Shale Product Method Alabama Indiana Brazil

Powdered Raw Shale Fischer Assay 11.6 12.5 18.6 Powdered Flotation Conc. Fischer Assay 35.0 28.2 32.4 Briquetted Flotation Cone. Fischer Assay 34.3 27.6 33.5 Briquetted Flotation Cone. Hydroretorting 65.0 54.4 53.3

2-10 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 3

EFFECT OF ADDITIVES ON PERMEABILITY AND DURABILITY OF NON RETORTED AND RETORTED BRIQUETTES

Gil Green Briquettes Retorted Briquettes Additive, Yield, Permeability, Durability, Permeability, Durability, % Weight gal/ton md No. of drops md No. of drops

None 21.3* 3.2 23 9.8 58 1% Li011 23.0 3.4 24 9.6 60 10% LiOB 19.6 N.D. 23 N.D. 60 1% NaOH 23.1 3.5 24 9.4 59 10% NaO H 18.9 2.4 31 7.2 71 1% CaCO3 22.3 N.D 22 N.D 56 10% CaCO 3 25.4 5.0 17 10.2 48

Average of five Fischer Assay Determinations Standard deviation = 0.5 gallon/ton

N.D. - Not determined

Screening tests indicated that LiOH, NaOIl and be involved in complex pyrolysis reactions taking place during kerogea conversion to liquid and CaCO 3 produced significant changes in the physical or the retorting properties of the briquetted shale. gaseous hydrocarbons. These may include catalytic Examples of the results are given in Table 3. effects of Li, Na, and Ca compounds on kerogen NaOH was the only reagent which showed promising conversion and interactions with the sulfur-bearing binding activity toward the beneficiated shale par- constituents of the shale. ticles. The durability of the briquettes increased with Na011 addition. However, as much as 10% by The material balance data given in Table 4 shows weight of NaOH was required to produce substan- that addition of 1% LiOH or 1% NaOII increased tial improvement in the briquette durability. Table oil yield at the expense of gas and water yields. 3 shows that NaOH and CaCO 3 also had significant With 10% NaOH addition, the carbon conversion to effects on briquette permeability.

Despite the limited effect of Li011, NaOH and FIGURE 2 CaCO 3 as binders during the briquetting of the beneficiated shale, some of these reagents showed beneficial effects on retorting or on sulfur distribu- EFFECT OF CaCO 3 ADDITION tion in the oil, gas and water products. ON RETORT PRODUCTS The addition of 1% Li011 or NaOH during briquet- Ling improved the Fischer Assay oil yield of the original flotation concentrate, in gallons per ton, from 21.3 to 23.1 and 23.5 respectively. However, higher doses of either of these additives produced a BENEF1CIATED ALABAMA OIL SHALE BRIOUTTES

decline in oil yield. n I. On the other hand, Figure 2 shows that addition of C increasing amounts of CaCO 3 to the beneficiated Ct shale improved the oil yield to as high as 25.5 a:cZ1TTTZiTER. gal/ton when up to 10 0,6 by weight of this reagent -a was used. At still higher CaCO 3 additions (up to -D... D 2096 by weight of the briquettes) a slight decrease L.._..GAS in the oil yield was observed. g ADDITIVE CCO3 As the oil yields increased to reach maximum values at optimum reagent additions, the gas and . I water yields declined to a minimum. a • a, Ia 20 WEIGHT OF ADDITIVE. % According to the M RI presentation, the effects of the three additives on oil and gas yields of the beneficiated shale indicate that the reagents may

2-11 SYNThETIC FUELS REPORT, DECEMBER 1986

oil decreased to about 25% but as much as 11% of 2. Briquetting at 5,000-20,000 psig showed no the carbon reported to the gaseous phase. This represents a total carbon conversion to oil and gas detrimental effects on the oil yield or other retort- of about 36% with additives, as compared to the ing characteristics of the shale. 33% conversion without additives. Over 76% of the sulfur in the feed was retained In the spent 3. With the exception of NaOH, which showed shale. binding activity at high additions, all the additives tested were not suitable as binders. In contrast, addition of 10% CaCO 3 to the system produced a marked increase in total carbon conver- 4. Some of the reagents used, such as LiOH, sion to oil and gas. The carbon distribution in NaOH and CaCO 3 had pronounced effects on the these products was in excess of 39% compared to retorting properties of the shale. the 3396 conversion found for the original con- centrate. S. Addition of 1% LiOH, 1% NaOH or 10% CaCO3 produced significant increases in oil production. These additives also enhanced carbon conversion to Conclusions oil and gas products during pyrolysis.

Bases on the above results and discussions the fol- 6. Addition of 10% NaOH lowered the oil yield lowing conclusions were reached: but increased the production of hydrocarbon gases. Also, it reduced the sulfur content of the oil, gas 1. Compaction of the powdered beneficiated shale and water products by locking the sulfur within the at 5,000 psig and above produced briquettes with spent shale. good green strength and resistance to breakage before, during and after retorting. This was achieved without any binder.

TABLE 4

COMPOSITION OF RETORT PRODUCTS OF BRIQUETTES WITH SELECTED ADDITIVES

Analysis, Percent Additives Products Wt% C A

N one Oil 8.4 82.04 5.56 9.90 11.22 Gas & Water 9.0 11.66 50.44 19.44 8.65 0.95 Spent Shale 82.6 Feed 100.0 24.00 12.15 2.63

1% Li011 Oil 9.6 80.90 6.08 9.53 7.1 5.63 59.84 11.43 Gas Ii Water Spent Shale 83.3 19.34 8.87 0.88 Feed 100.0 24.17 12.24 2.54

Oil 9.8 80.67 6.14 9.58 1% NaOH Gas & Water 6.9 4.68 61.86 13.00 8.75 0.95 Spent Shale 83.3 19.11 Feed 100.0 24.21 12.13 2.54

7.2 83.51 4.24 9.82 10% NaOH Oil Gas & Water 9.3 24.73 23.15 9.67 10.64 Spent Shale 83.5 18.36 0.96 Feed 100.0 24.00 11.67 2.55

10% CaCO3 Oil 10.6 83.40 4.31 9.81 Gas & Water 8.4 7.98 35.31 7.64 Spent Shale 81.0 18.31 7.95 0.92 Feed 100.0 24.42 11.10 2.68

2-12 SYNTHETIC FUELS REPORT, DECEMBER 1986 EFFECT OF NITROGEN ON FCC CATALYSTS CLARIFIED Use of immiscible solvent to extract nitrogen compounds. This method has been recom- High levels of nitrogen in shale oil are a primary mended for shale oil. hindrance to processing the shale oil in conven- tional refinery streams. Work by Unocal Corpora- - Neutralization of basic-nitrogen compounds tion is shedding some additional light on how with acid additives. The products of neutralization can be separated or left in the nitrogen compounds affect FCC catalysts, and on feedstock. the tradeoffs which can be made in refining shale oil blends. Work by J. Sherzer and EL McArthur has been reported at the Kntalistiks FCC Sym- - Use of nitrogen-resistant FCC catalysts. posium in Venice earlier this year, and more This method eliminates or greatly reduceds recently in the Oil and Gas Journal. the cost of pretreatment. Six commercial fluid catalytic cracking (FCC) Although the poisoning effects of different nitrogen catalysts were evaluated for resistance to the ef- compounds on cracking catalysts have been fects of nitrogen compounds. In addition to shale described in the literature, there is little informa- oil applications, the results of the evaluations are tion available with regard to the nitrogen resis- important because of the shift in FCC feedstocks tance of different types of cracking catalysts. to heavier types containing higher levels of sulfur, metals, and nitrogen. Feedstocks The deleterious effects of nitrogen compounds on The Unocal researchers used feedstocks with dif- the performance of cracking catalysts has been ferent levels and types of nitrogen compounds. known for many decades. Approaches which can be The properties of the feedstocks are shown in used to minimize the deleterious effects of Table 1. nitrogen compounds include: Feedstock F-i is a vacuum gas oil (200 to 540 0 C similar - Ilydrotreating. This requires high pressures cut) to feedstocks used by California and temperatures. refineries. It contains about 0.3 wt% N. Two other feedstocks, F-2 (0.5 wt% N) and F-3 (0.75 - Use of solid adsorbents to remove nitrogen wt% N), were obtained by blending F-i with shale compounds. The solid adsorbent is usually oil, F-4. acidic and captures the basic nitrogen com- pounds.

TABLE 1 FEEDSTOCK PROPERTIES Feed No. F-i F-2 F-3 F-4 Gravity, °A P1 22.0 22.8 24.4 28.1 Sulfur, wt % 1.19 1.06 0.93 0.47 Nitrogen, wt % 0.30 0.48 0.74 1.56 Basic nitrogen, wt 96 0.094 0.16 0.37 1.23 Conradson carbon, wt 96 0.12 0.1 0.07 0.01 Aniline pt., °C 19 18 17 Ii Bromine No. 12.3 16.6 18.1 28.7 Refraction index at 070 C 1.4950 1.4911 1.4840 1.4700 Metals, ppm Fe 4 3 2 2 Ni 0.6 <0.5 <0.5 <0.5 V <0.2 <0.5 <0.5 <0.5 Cu <0.1 - - - Simulated Distillation

iO%, °C 259 253 248 238 50%, °C 393 381 367 328 95%, °C 513 508 496 440 Maximum °C 538 538 538 450 U OP 'k" Factor 11.5 11.5 11.5 11.0

2-13 SYNTHETIC FUELS REPORT, DECEMBER 1986 FCC Catalysts TABLE 2

The commercial catalysts used are shown in Table COMPOSITION AND PHYSICAL CHARACTERISTICS 2. Catalysts K and L have high silica content, OF COMMERCIAL FCC CATALYSTS while catalysts N, 0, and P have high alumina con- tent. Catalysts L and P have higher contents of Catalyst K L M N 2 ! rare earth Y-zeolite (RE?). Catalysts K, N, and 0 have lower zeolite contents and lower cracking ac- Chemical Analyses tivity. Al 20 3 , wt % 29.9 28.3 41.7 45.9 48.1 48.9 Catalyst M is an octane-enhancing catalyst and Na2 O, wt % 0.81 0.43 0.37 0.28 0.66 0.34 contains ultrastable Y-zeolite (US?). These Re2 0 31 wt % 3.20 6.2 <0.51 3.1 2.7 4.3 catalysts have significant differences in surface area, pore volume, and bulk density. Physical Properties

Results SA, sq m/g 170 215 240 120 270 345 ADD, g/cc 0.90 0.80 0.74 0.77 0.72 0.86 The experimental results show a general decline in N 2-PV, cc/g 0.18 0.19 0.22 0.24 0.38 0.37 conversion and gasoline yield with increasing feed Hg-PV, cc/g 0.62 0.52 0.67 0.71 0.96 0.72 nitrogen content. Such a decline is due to in- Pk. It., cps 312 401 345 275 261 363 creased poisoning of the catalysts by the nitrogen compounds in the feedstock. * SA = Surface area; ADD = Average bulk density; N 2-PV = Nitrogen pore volume; Hg-PV = pred volume; Pk. II. = The most active of the catalysts tested are Peak height in x-ray diffraction pattern, at 20 = 23.50. catalysts P and L. These two catalysts showed a smaller decline in conversion and gasoline yields compared to the other catalysts. - At constant feed-nitrogen content, the nitrogen content of the liquid products Analysis showed that most of the nitrogen com- decreases with increasing conversion. pounds are in the DO (decanted oil) and LCO (light cycle oil) fractions. - The percent nitrogen recovered in the liquid products decreases with increasing conver- Nitrogen analysis of spent catalysts showed that sion, regardless of feed nitrogen content. the amount of nitrogen on the catalyst is con- siderably smaller than in the corresponding liquid - Catalysts P and L have the highest activity product. For example, catalyst K tested with feed among the catalysts tested, regardless of F-i gave, at 74 vol % conversion, a liquid product steaming temperature of feed-nitrogen con- containing 1,100 ppm nitrogen, while the cor- tent. responding catalyst contained only 190 ppm nitrogen. At constant feed-nitrogen content, an in- - Catalysts P and L gave the highest gasoline crease in conversion results in an increase in and coke yields, as well as the lowest LCO nitrogen content of the catalyst. and DO yields.

A general decline was observed in percent nitrogen - At constant coke make (5.6 wt%), catalyst P recovered with increasing conversion, regardless of gave the highest conversion and gasoline catalyst tested. All catalysts line up on the same yield. curve, regardless of feed-nitrogen content. The lower concentration of nitrogen in the liquid - High zeollte content and matrix type play a product obtained with the more active catalysts, role in enhancing the nitrogen resistance of and the corresponding higher concentration of FCC catalysts. nitrogen on the spent catalysts, indicates stronger conversion of feedstock-nitrogen compounds into coke components.

Overall conclusions derived from the study were: PATENT ISSUED FOR RETORTING PROCESS - At constant steam-deactivation temperature, USING COAL an increase in feed-nitrogen content results in a decrease of conversion and gasoline A United States Patent, number 4,589,973, was yields and an increase in LCO and DO issued May 20, 1986 to C Minden and assigned to yields. Dreckinridge pinerals of Murray, Utah for a retort- - At constant conversion, an increase in feed- ing process involving the addition of pulverized nitrogen content results in a decrease in coal. The process is referred to as an integrated hydropyrolysis/thermal pyrolysis technique. gasoline and DO yields and an increase In LCO, coke, and hydrogen yields. Referring to Figure 1, raw oil shale is crushed and ground in a conventional system then placed in the

2-14 SYNTHETIC FUELS REPORT, DECEMBER 1986 shale feed hopper. The hopper feeds to the bottom The two different treatment zones in the thermal of a drier/heater which is supplied from a retort are selected such that the upper zone tem- fluid bed combustor. perature is sufficient to vaporize the remaining slurry oil, and the lower zone temperature is suffi- From the gas lift drier/heater, the crushed heated cient to thermally retort residual organic carbon shale is taken through a cyclone (28). Cyclone and hydrogen remaining after hydropyrolysis and to vapors are taken to a furnace for disposal. Shale thermally crack excess heavy gas oil and pyrolyze recovered from the cyclone at a temperature in the coal charged as coal slurry. The hydrogen con- the range of 300 0C is taken to a slurry mixer tent of the shale leaving the thermal retort is tow, where it is mixed with heavy recycle oil. The in the range of 0.5 hydrogen/carbon atomic ratio or mixed slurry is then pumped to the bottom of the less. hydropyrolysis reactor where it is combined with hydrogen under pressure. The process is claimed to be particularly outstand- ing for use in the treatment of leaner oil shales A portion of the mixture in the hydropyrolysis having a low hydrogen to carbon ratio, such as the reactor is recycled to the bottom of the reactor by Devonian shales found in Kentucky, Mississippi and recycle pump (34). Recycled cracked product from Tennessee. the quench tower is injected into the reactor through line (52). Gas is removed at the top and An advantage of the new process is found in the the product from the reactor is taken to the unusually low yield of light hydrocarbon gases, and product stripper. Steam from line (40) strips the in the high yields of desired liquid hydrocarbons in liquid hydrocarbon products from the mixture and the boiling range typical of gasoline, diesel oils and the resulting stripped products are taken through a the like, that may be obtained by thermal cracking cyclone (37) and then to the product bubble tower. of heavy oil product within the thermal retort. In many cases, the yield of liquid hydrocarbons from A portion of the heavy gas oil from the bottom of Devonian shales is from 150% to 25096 of Fischer the product bubble tower is taken to the coal Assay. Such high yields are obtained with mini- slurry mixer (22) where it is mixed with pulverized mum hydrogen loss in the spent shale. coal to form a pumpable slurry. The slurry is then taken to the thermal retort were the slurry oil is Further special advantage is claimed in the surpris- subjected to thermal cracking and the coal is ingly improved quality of the liquid products ob- pyrolyzed. The re maining spent shale and slurry oil tained from the process. For example, prior known from the product stripper enters the thermal retort products possess considerable amounts of un- through line 30. The mixture is subjected to two desirable unsaturated hydrocarbons, such as olefinic different temperature levels by adding through lines compounds, and little if any, of the desired 41 and 42 spent shale and coal char that has been aromatic or cyclic compounds found in conventional burned in an air lift combustor. crude oils. The liquid products from the new process are said to be substantially free of un- The hot solids create a temperature gradient to saturated compounds and possess increased amounts vaporize slurry oil and thermally retort the of the desired cyclic or aromatic compounds. hydropyrolysis spent shale. The combined gas and liquid products from the thermal retort pass in the In addition, the liquid products have significantly vapor phase to cyclone (46) and thence to the reduced amounts of the complex organic nitrogen, recycle quench tower. oxygen and sulfur compounds and thus exhibit im- proved color and stability. The new products also The spent shale and coal char from the bottom of exhibit a significant increase in API gravity. thermal retort is taken through line (43) to the bottom of the air combustor. The spent shale and Also of significance is the fact that the addition of coal char is forced up the column by air under coal provides supplemental fuel in the form of gas combustion conditions. From the top of the air for hydrogen manufacture and coal char as fuel for lift combustor the burned shale and coal char goes - a fluid bed combustor so that the plant can through cyclone (48a) and thence to take off lines operate in energy balance and the hydrogen plant (41) and (42) or else to the fluid bed combustor, or can operate in fuel-plus-feed balance. else recycled to the air lift combustor. Ash removed from the fluid bed combustor passes A further unexpected advantage of the invention is through a cooler for disposal. the fact that efficient operation can be obtained without the use of hydrogen donor hydrocarbons or The combined gas and liquid product from the the use of catalysts. thermal retort is taken through cyclone (46) to the recycle quench tower. From the quench tower, the gas is removed at line (51), while the cracked gasoline and light gas oil is removed through lines (52) and (53) and recycled to the hydropyrolysis reactor. The slurry gas oil is taken through the slurry oil heater and then recycled to the shale slurry mixer.

2-15 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 1 INTEGRATED HYDROPYROLYSIS / THERMAL PYROLYSIS RETORT

to W37E HEAT to

ASH

2-16 SYNTHETIC FUELS REPORT, DECEMBER 1986 INTERNATIONAL

PETROSIX STUDIES FLUID BED COMBUSTION OF Industrial Plant RETORTED SHALE With respect to the commercial module under con- The Petrosix oil shale project in Brazil completed struction, it is now scheduled for operation in mid in September 1906 the design of a circulating 1988. The current construction schedule is given in fluidized bed combustor to be used in a pilot fur- Table 1. nace to produce one ton of steam per hour. Erec- tion of that facility is in progress. TABLE 1 An update of the Petrosix project was provided to the 1986 Eastern Oil Shale Symposium by E. Piper of Stone & Webster Engineering Corporation. PETROSIX INDUSTRIAL PLANT SCHEDULE

Petrobras is interested in fluidized bed combustion for two general reasons. One is to make use of Item Percent Complete the fines in power generation and the other is to recover the carbon values from retorted shales that Total Project 48 may warrant this treatment. One such shale might Engineering 81 be Moroccan shale with high carbon content and Equipment Acquisition 52 some residue. Irati and Western United Civil Works 59 States oil shales leave the Petrosix process at too Plant Erection 19 low carbon values to justify recovery of the energy.

Petrobras is also considering a new fines retorting Operating Costs system. They have already studied the PLASOL process, which is an entrained bed, indirect heated Piper also restated a summary of operating costs system to process oil shale fines. At present there which Was developed. Exclusive of capital cost is a PLASOL pilot plant which has been in opera- recovery, Brazil expects to produce shale oil from tion since January, 1982. Some main features of Irati shale for approximately $24-28 per barrel. An the process are: eastern United States oil shale project for the same size plant could produce crude shale oil for Shale mass velocity Up to 6,000 approximately $28-32/barrel (operating costs). lbs/hr/sq.ft For the same size unit, shale oil produced from the Retorting temperature Up to 6000C Moroccan Timandit deposit would also cost ap- proximately $2832 per barrel (operating costs). An Solids residence time 10 to 80 evaluation of a duplicate unit for western U.S. oil seconds shale resulted in a production cost for crude shale oil of $13-17 per barrel (operating costs) from 35 Oil plus gas yield + 90% FA gallon per ton shale. Table 2 presents costs, in- vestment and production for several projects, all Gas used Steam, inert based on the 36 foot diameter industrial retort unit gas, recycle under construction in Brazil. gas

Particle size minus 1.5mm TABLE 2

The plant is capable of running various shales up to PLANT COSTS 10 tons per day. PETROBRAS also has a cold flow test apparatus to conduct physical modeling East West studies and visual observation of flow phenomena. USA USA Brazil Morocco PLASOL The project is presently in the second Capital phase of development with the installation of a Investment recycle gas compressor. $xlO ' ' 120 150 70 100 Petrobras decided in October, 1986 to build a new BPI) 2,300 5,700 2,600 2,600 pilot plant for a spouted bed process for fines Operating which has been developed by its research group. Cost,$/BBL 28-32 13-17 24-28 28-32 Operation is scheduled for March, 1987.

2-17 SYNTHETIC FUELS REPORT, DECEMBER 1986 SPP/CPM EXCAVATE BULK SAMPLE OF STUART An earlier 500 ton shipment of shale is said to OIL SHALE FOR TESTING have yielded promising results. A team of Jor- danians will accompany the new batch to observe Southern Pacific Petroleum N.L. and Central the tests. Pacific Minerals N.L. of Australia noted in their Quarterly Report September 30 that the company continued to evaluate retorting technologies suitable for the processing of Stuart oil shale. A sample of 400 Kg of Kerosene Creek oil shale was shipped to ISRAEL ELECTRIC JOINS OIL SHALE POWER UMATAC in Calgary, Alberta for bench testing of PLANT PROJECT the TACIIJK process. The Israel Electric Corporation has purchased a The TACIUK process, based on rotary kiln technol- 25% share in PAMA (Energy Resources Develop- ogy, has been developed for the thermal processing ment, Ltd). PAMA is planning to build a 7 1/2 of oil sands and is sponsored by the Alberta Oil megawatt shale-fired demonstration plant at Mishor Sands Technology and Research Authority. The Rotem in Israel. process can also be applied to oil shales. The demonstration cogeneration plant is being The objective of the bench scale testing program is designed to produce 42 tons/hour of steam for use to evaluate the process and to determine whether in nearby phosphate plants, and also produce pilot plant tests should be undertaken in the exist- electricity. PA MA is also operating a one ton/day ing 5 ton per hour plant located in Calgary. experimental retort. Preliminary results of the bench scale work have been encouraging. Construction of the demonstration plant is expected to begin in early 1987 and be completed within 2 In preparation for the 5 ton per hour pilot plant years. It will be based on fluidized bed technol- program a bulk sample is being extracted from a ogy. Successful operation of the demo plant could box cut in the Kerosene Creek seam. The box cut then lead to a 50 to 100 megawatt or larger com- involves the removal of some 50,000 tons of over- mercial plant. burden and the extraction of 3,800 tons of oil shale. The completed excavation will be crushed, dried and placed in 1 ton bags. Weight losses due to drying and handling should result in about 2100 tons being bagged for shipment. NEW BRUNSWICK OIL SHALE PYROLYZED IN SPOUTED BED Rundle Oil Shale Project

During the same period, , as Operator, com- Work carried out at the University of British pleted a series of trials of Rundle Kerosene Creek Columbia has recently characterized the behavior shale in the Shale Retort pilot plant at of oil shale from New Brunswick, Baytown, Texas. The tests were completed in Sep- Canada in a spouted bed reactor. The shale was tember. pyrolysed in a nitrogen-carbon dioxide mixture in beds of either inert silica sand or spent shale. At the Rundle site, data collection concerned with waste management studies is in progress. The A summary of results obtained in the 12.8 cm lysimeters installed to provide information on water diameter spouted bed reactor was given at the 30th movement through waste materials are fully opera- Canadian Society of Chemical Engineering Con- tional. Geological field assessment of Authority to ference in Sarnia, Ontario. At optimum tempera- Prospect 4094M was completed in the period. ture, particle size and feed rate, oil yields of up to 9496 of the Fischer Assay value were obtained. The oil shale was reduced in size using a jaw crusher and then screened to 3 different sizes: 2-4 mm, 1-2 mm and 0.5-1mm. Samples were analyzed as shown in Table 1. The organic carbon content JORDAN SHIPS OIL SHALE TO CHINA TABLE 1 Jordan and China have signed an agreement to develop oil shale processing technology that could MODIFIED FISCHER ASSAY OF OIL SHALE lead to a 200 ton/day oil shale plant in Jordan. China will process 1,200 tons of Jordanian oil shale at its Fu Shun refinery. If tests are successful, Size Fraction (mm) 0.5 - LO 1.0 - 2.0 2.0 - 4.0 China could build the demonstration plant in Jordan's Lajjun region, where the oil shale resource Oil Yield (wt%) 5.50 7.95 7.85 is estimated at 1.3 billion tons. China plans to Water Yield (wt%) 2.00 2.25 2.00 send a team to Jordan to conduct a plant design Gas Lost (wt %) 5.50 2.30 2.65 study. A Lajjun oil shale complex could produce as Char Yield (dill.) 87.0 87.5 87.5 much as 50,000 b/d of shale oil. Oil Density (g/ml at 0.867 0.867 0.866 15.50C

2-18 SYNTHETIC FUELS REPORT, DECEMBER 1986

was about 10.2 - 12.4%, with mineral carbon about 2.3%. The ash is primarily silica, with significant - FIGURE 1 levels of calcium and magnesium oxides. The Fis- cher Assay values show substantially lower oil yield EFFECT OF BED TEMPERATURES from the smaller size fraction. ON OIL YIELD

I I I I I Effect of Temperature

A study of the temperature effect was done on two feed sizes: 1-2 mm and 2-4 mm, at a constant feed rate of 1.4 and 1.28 kg/h respectively. All of 0 these experiments were done in a bed of silica I:: sand, with pyrolyzing gas of 15% CO 2 and 85% N2. Figure 1 shows a plot of oil yield as a percent of the Fischer Assay value versus the bed temperature for the two different sizes of particles. A maxi- ! : mum value of the oil yield exists for each size at Ii' a critical temperature. For particles of 1-2 mm, I I I 1 1 I the optimum temperature is around 470-4900C 420440450410 500 620 540 4(0 1(0 where the oil yield is 89.3% of the modified Fis- BED TEMPERATURE. C cher Assay value. For the 2-4 mm particle size, the optimum temperature is somewhere between 490 and 5100 C. At 505°C the oil yield was 94.3% of the modified Fischer Assay yield. The curve for the 2-4 mm particles appears shifted slightly to the FIGURE 2 right, perhaps because the larger 2-4 mm particles will have larger internal temperature gradients, and EFFECT OF MEAN PARTICLE SIZE will require a longer heating period to heat up the ON OIL YIELD entire particle for complete pyrolysis. I Effect of Oil Shale Particle Size

A study of the particle size effect on oil yield and composition was carried out for 2-4, 1-2, and 0.5-1 mm sizes. Figure 2 shows the oil yield versus mean particle size. Oil yield increases with in- c creasing particle size at fixed feed rate and tem- perature. This is exactly opposite to observations made for coal pyrolysis in the same apparatus. No + n,c.cI fla satisfactory explanation for the behavior in Figure 0 0 ROUTU UI 2 was found. However, if the experimental tem- perature is higher than the optimum temperature I I for a given particle size, the chance is greater 0 I 2 3 4 5 that the oil will be decomposed to secondary MEAN PARTICLE SIZE. (ron) volatilcs and coke. It was hypothesized, based on Figure 1, that the optimum reaction temperatures for the smaller particles are farther from the ex- (5050) perimental temperature used in Figure 2 and Effect of Spent Shale therefore result in lower yield. To study the effect of bed material on oil yield, Effect of Oil Shale Feed Rate the initial volume of the bed was kept the same at 3.7 L but the amount of spent shale in the initial A feed rate study was carried out for 2 sizes: 2-4 bed ranged from 0 to 5 kg. The remainder of the mm and 1-2 mm. Data for oil yield versus shale bed was silica sand. The results showed a marked feed rate showed a marked decrease of oil yield decrease in oil yield with increasing spent shale with increasing feed rate. For 1-2 mm shale, the mass in the bed. These experiments show essen- oil yield dropped from 6.3% to 2.9% as the feed tially the same effect as the feed rate experi- rate was increased from 1.33 to 3.32 kg/h. Similar ments. results were observed for the 2-4 mm sized shale where feed rate increases from 1.53 to 2.71 kg/h The researchers concluded that the hot spent shale resulted in an oil yield drop from 7.4 to 2.096. which accumulates in the reactor acts either as a The decrease may be due to the hot spent shale sorbent for oil or as a surface for secondary oil- accumulated in the reactor acting as a surface on consuming reactions. which the secondary oil-consuming reactions occur, or perhaps as a catalyst for oil decomposition. ## ##

2-19 SYNTHETIC FUELS REPORT, DECEMBER 1986 carbon concentrations (DCC 43 samples). The ac- COMBUSTION OF AUSTRALIAN SPENT SHALES tivation energy determined from the Arrhenius plot COMPARED was higher for samples with the lowest carbon con- centration. The combustion kinetics of spent oil shales from seven major Australian deposits have been examined A comparison between the shales over a range of by B. Charlton of CSIItO using a fluidized bed particle sizes at 7000C is shown in Figure 1, where batch technique. Results were reported at the the spent shales are graded with the lowest carbon 14th Australasian Chemical Engineering Conference concentration on the left. Stuart and Rundle spent in Adelaide iii August. Chemical rate constants shales require a relatively short residence time for were shown to vary between the shales and to be 90% combustion, whereas Nagoarin South requires less than extrapolations of data from American considerably longer. At 7000 C, chemical kinetics spent oil shales. The effective diffusivity also have very little influence on the overall reaction varies widely among the shales. time for particles above 0.5 mm diameter. The seven oil shales were from the Condor, Duaringa, Low mead, Nagoorin, Nagoorin South, Rundle and Stuart deposits in Queensland.

The batch analysis technique used a fluidized bed reactor in an electrically heated, 150 mm diameter stainless steel vessel. The fluidized bed was shale ash, generally of the same type as the kinetic sample, sieved to between 0.425 to 0.6 mm and approximately 150 mm deep.

The chemical kinetics are given in Table t. At 600-7000 C, all the Australian spent shales are less reactive than extrapolated values for Colorado and Antrim spent shales. Rundle and Stuart spent shales have the same activation energy as Colorado spent shales, but Rundle is less reactive than Stuart. Lowmead has a lower activation energy but, within the range 600-7000C, it is the most reactive Australian spent shale. Condor and Nagoorin South are equally reactive, being ap- proximately the same as Rundle, but having a lower activation energy. Duaringa has the lowest activation energy and is the least reactive of any of the spent shales. Calculated activation energies and pre-exponential factors are shown in Table 1.

Condor spent shales with lower carbon concentra- tions were less reactive than those with higher

TABLE 1

KINETIC PARAMETERS FOR SPENT OIL SHALES

Carbon Time for 90% Activation Frequency in Spent Combustion, sec Energy Factor Deposit Shale, % @ 600 0 C @700°C (kJ/) (Pa 1

Condor 7090 6.0 60 23 67.7 1.12x10-2 Condor CDD 43 3.5 75 23 99.4 7.92x10 2 36.32 an - Condor CDD 43 7.0 60 23 67.7 1.12x10 2 68.25 m Lowniead 14.9 40 14 78.0 6.37x10-2 Nagoorin South 7.0 60 23 67.7 1.12x102 Stuart 9.3 54 14 99.4 7.81x10 1 Duaringa 5.2 75 35 56.4 2.04x103 Rundle 5.6 75 23 99.4 4.92x10 2

Note: Condor 7090 Box cut sample Condor CDD43 = Different levels of same drill core

2-20 SYNTHETIC FUELS REPORT, DECEMBER 1986 ENVIRONMENT

BLM ISSUES FINAL EIS FOR TRACT C-a this is an existing Prototype Oil Shale Tract that OFFSITE LEASE was leased on the basis of a previous EIS. The previous EIS and other environmental studies were In October, 1986, the United States Bureau of Land incorporated by reference into the D EIS and were Management, White River Resource Area, issued updated where necessary. The main focus of the the Final Environmental Impact Statement concern- EIS effnrt was to assess potential consequences ing Rio Blanco Oil shale Company's request to from the proposed disposal of waste materials on lease an offtract site for disposal of overburden the public lands and to compare the alternatives in and spent shale from Tract C-a. order to select the preferred alternative.

BL M noted that comments on the draft environ- Alternatives to the Proposed Action on 84 Mesa in- mental impact statement (D EIS) did not require clude disposal sites located in Philadelphia Creek significant changes in data, analysis, or conclusions. and the West Fork of Spring Creek plus a No Ac- Therefore, the D EIS was not reprinted. In most tion Alternative. The alternative sites are located cases, comments required only minor corrections or off the oil shale resource in an area roughly west clarifications to the text. of Cathedral Bluffs. See Pace Synthetic Fuels Report, December, 1985, page 2-36. Locations for Numerous changes and major revisions were the alternative sites are shown in Figure 1. Waste recommended by various groups but were not made disposal to these sites would be reached by an by BLM. overland conveyor system ranging in length from 5.5 to 7.7 miles (84 Mesa conveyor length is 2.7 to Several comments addressed a need for long-range 6.2 miles). mine planning for the whole oil shale resource. Many people who responded Significant environmental impacts would occur, believed that various other alternatives should be regardless of the alternative selected, including the analyzed in addition to those described in the D ElS. No Action Alternative (in which case only Tract C- These included total disposal needs of Tract C-a, a and RBOSC's private land holdings would be phased development of Tract C-a, and additional impacted). The main focus of the EIS was to "on the resource" alternatives. No new alternatives assess the potential consequences of the proposed were analyzed by BLM. A No Action Alternative disposal of several billion cubic yards of waste and three alternative offtract disposal sites were materials on federal lands. analyzed. Preferred Alternative Federal Prototype Oil Shale Tract C-a is currently under a temporary lease suspension that was issued BLM determined that the Proposed Action (84 by the U.S. Department of the Interior (USD1). Mesa) is also the Preferred Alternative. This The suspension was issued to allow for considera- determination was made on the basis of environ- tion of Rio Blanco Oil Shale Company's (RBOSC) mental factors, resource management considera- request for an offtraet lease for disposal of waste tions, and by considering the goals of the Prototype materials from a proposed open pit mining opera- Oil Shale Leasing Program. tion. The suspension commenced on August 1, 1982, and will continue until the USD1 issues to the Many respondents identified their choice for the lessee an offtract lease for disposal of spent shale; preferred alternative as the No Action Alternative. or July 31, 1987, which ever occurs first. The Although the No Action Alternative would result in terms of the Mineral Leasing Act of 1920 the least amount of degradation because it would prohibited additional leasing of lands to an existing limit impacts to the smallest area, BLM stated oil shale lease holder. The act was amended in that the No Action Alternative would not best 1982 to allow the Secretary of the Interior to con- serve the public interest, because the development sider a 6,400-acre offtract lease to the holder of of alternative energy technologies might not be the Tract C-a lease for disposal of waste material furthered. and the location of facilities. RBOSC subsequently submitted a proposal to lease 6,400 acres of an The Resource Issue area adjacent to Tract C-a known as 84 Mesa. A major issue which pitted Rio Blanco Oil Shale Complete mining of Tract C-a from boundary to Company against many other members of the oil boundary would produce more waste disposal shale community was the covering up of oil shale material than could be accommodated on a 6,400- resources on 84 Mesa. The oil shale resource un- acre offtract lease. The EIS does not address the der 64 Mesa may contain as much oil in place as complete disposal needs of a totally open pit mined Tract C-a itself. Some of the significant points tract, but only addresses the legally mandated concerning this issue were covered in comments by limitations of a single 6,4000-acre offtract lease. J. R. Dyni of the U.S. Geological Survey in Den- The exact mining approach has not yet been ver. defined by RBOSC. The EIS does not further analyze the direct impacts to Tract C-a itself, as

2-21 SYNTHETIC FUELS REPORT, DECEMBER 1986 He notes that the 84 Mesa site contains enormous - To stimulate development of alternative quantities of oil shale, as well as large amounts of sources of energy, specifically oil shale dawsonite and nahcolite. Furthermore, 85 Mesa has technology, by private industry. excellent potential for recovery of those minerals by open-pit and underground methods of mining. To develop techniques for environmental safeguards and reclamation that could be "Despite the shortcomings in mineral resource es- incorporated into a mature oil shale in- timates for the 84 Mesa site in the Draft EIS, it is dustry. clear that many billions of tons of resources of oil shale, naheolite, and dawsonite will be seriously - To permit an equitable return to all impaired by selection of 84 Mesa as the preferred parties. site. In contrast, the selection of one of the other sites would result in a relatively small loss of - To gain expertise in the leasing and super- mineral resources that are present in greater abun- vision of oil shale development as the basis dances in other parts of the region. Not only for future administrative actions. would the minerals on 84 Mesa be seriously degraded, or completely lost because it may not be These goals do not include the means for develop- economic to mine them, but bonus bids amounting ing a fully commercialized industry, but simply to to hundreds of millions of dollars would be lost gain experience in an area with many unknowns and both to the Federal and local governments. From yet-to-be-proven technologies. the standpoint of conservation of valuable mineral resources on the public lands, it is difficult to see The 84 Mesa Alternative allows the recovery of how 84 Mesa was chosen as the preferred site." more oil shale resource than the No Action Alter- native with the least resource foregone (only 2 In response to such comments, the BLM stated that percent). Both other offtract disposal sites do al- the mineral resources underneath 84 Mesa are low more oil shale recovery from Tract C-a. known to be substantial. The analysis set forth in However, maximizing resource recovery of Tract C- the DEIS reveals that a percentage of the resource a is a function of total tract development and was would be lost because of the proposed action. not the critical factor in selecting a preferred al- However, the waste disposal alternatives are not, ternative. nor have they been proposed as leasable sites for mining by BLM. The premise in the DEIS that 84 Mesa resources would not be lost is because: 1) the disposal pile The disposal of wastes west of the bluffs would can be moved to facilitate an open pit mine travel- have a greater impairment to the resource (oil ing into 84 Mesa; and 2) if an underground mine shale) development of Tract C-a than the waste were used to mine those resources beneath 84 pile on 84 Mesa would have to the potential Mesa, with a disposal pile in place, the necessarily resource (oil shale) development of 84 Mesa. Each larger mine pillars to support the increased weight alternative results in some quantity of mineral of the overburden would result in only a 2 percent resources foregone, be it coal, oil shale, dawsonite, loss of recoverable resources. Via underground naheolite, or natural gas. Based on environmental mining, 100 million barrels of oil shale, 5.5 million factors, resource management considerations, and tons of nahcolite, and 4.6 million tons of dawsonite the goals of the Federal Oil Shale Leasing would be "lost" with a disposal pile in-place on 84 Program, 84 Mesa was chosen as the Preferred Al- Mesa. This underground mine (84 Mesa with pile) ternative. would recover 2.4 billion barrels of oil shale, 150 million tons of nahcolite, and 120 million tons of The BLM further noted that a single 6,400-acre dawsonite. Therefore, requiring underground mining lease is not large enough to handle the 10.5 to 12 instead of allowing surface mining of 84 Mesa billion cubic yards of waste materials that would comparatively losses as much as underground mining be generated if Tract C-a were open pit mined of Tract C-a, plus the additional approximately 2 from boundary to boundary. The disposal sites in- percent loss due to the potential disposal pile vestigated in the U US have disposal capacities placement. For either site, too percent recovery ranging from 3.6 to 4.4 billion cubic yards, thus of the entire resource in situ is not possible, theoretically requiring about three tracts, each of regardless of the technique used. 6,400 acres, in order to fully mine Tract C-a. Congress was aware of this limitation when a 6,400-acre offtrnct lease size was written into an Other Actions amendment to the Minerals Leasing Act of 1920. Since the oil shale industry is a fledgling industry, In order to initiate a lease, procedures would have it would have been premature for Congress to to be followed in accordance with Section 302 of commit more than 6,400 acres for disposal use the Federal Land Policy and Management Act prior to the availability of data upon which to (FLPMA) concerning lease processing. Steps that make future decisions. BLM's position is that the would have to be taken include making a market goals of the Federal Prototype Oil Shale Leasing value rental determination (including an evaluation Program can be met with a single 6,400-acre off- of mineral values forgone); issuing a Notice of tract disposal lease. These goals are briefly stated Realty Action to inform the Governor of Colorado as follows: and other parties of the lease decision; and issuing

2-22 SYNTHETIC FUELS REPORT, DECEMBER 1986 after a 45-day comment period, a Notice of The offtract surface lease may not serve more Determination to Proceed or Vacate the decision, than one federal oil shale lease (Trace C-a) and A lease document would be developed according to may not be transferred except in conjunction with terms and conditions set forth in the Code of the transfer of the federal oil shale tract that it Federal Regulations (C FR) (Sec. 2920.7), and serves. The environmental resource protection stipulations resulting from the environmental impact stipulations included in the prototype lease would statement would be incorporated into the lease, not apply to the surface lease for waste disposal. A summary of environmental consequences is tabu- In response to comment letters, several perfor- lated in Figures 2 through 5. mance standards have been developed for the Preferred Alternative.

FIGURE 1

ALTERNATIVE OFFTRACT DISPOSAL SITES

R 9 P99W R1OIW IA 1W w 7 I

C,

*E ,Mx,,

/ TIS / -84 ,, '

- a,

/ 1 /' o'• /

',I / •+ /,/,

T25 '

I I

o i 2 3 tI1L5

2-23 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 2 SUMMARY OF ENVIRONMENTAL CONSEQUENCES

______site rn a S Iv. 5 Mesourte Element Proposed act's., 54 sal if nhlsd.ipi,lsi.,evezf West Fern of Sp.-iisi tv-er, 2! - oct10.,]! Air Oval it.y Disposal soesId recall in 85 Ell Want U U Mesa. Eases mel., t to 64 Mesa. tasI-range i.pactt .11 be Af total TIP last.. 1. iwo-thirds of 645... bet the project, with a greater likelihood that class ii mncre.tots All slidU. ted federal stood- staid be esceeded n_ar Tract ards be eet, escept C-.. 24-hour TIP Class II Snore- .At would be esteeded near Tv-act C-..

loograplvy iceography - Id be algol F. rspsgs-aphy woval 4 be sigsil F- iopaqraphy ails1 d be 5, gal f - rnest I acts to topography. icaetly altered. candy altered. AddS ti onal I castly altered. adds ti seal iteucts due to cueeeysr iceacts doe to c040eysr -seat.. 'at.. Soil. Assert's dual a recover 545 of 051 Mularacover in or eli .,A recueer .045 ii 55, Ire Open pit opt los s '- shale resources free Tract shale resources from Tract shalt resources crc. Tract asa I los I ---of oil C-a. Disposal as 84 S.c C-.. No ol I shale resources c-c. Op oil shale reins rces shale resources free Tract cool d rhaul t In a 21 loss of eovcsssbered. Possible loan of Ancestor". Possi bit lass of c-a. Uudergrossd opti ass oil 'hale resources Most, 64 181 of coal We to disposal. 391 of coal due to disposal. soda clips 341 or 3" recta- Mess. silposal Wan I.- Coal has 1. deaelspein.t Coal has 1.denelor.eet cry, best the rewaining oil or ho_ta bids from future pr I sri . priority, shale reeources would be leasing end reduced royal - far,.. tics for 84 Mesa.

Fluid uiiseral 5 dl span' soul 4 lact up 5. 0, 'petal soal p l.ct sia UI sposal seoul d 1.ceas 5 Me Mis, ng lupac S as stated nor 40 billIe, cithic feet of set esisting well, and gas re- coasting sell and re- 8455.. resources, but partial re- serbesup to 0.5 billion lanes 5 to 58.3 bUIlDs co very by directional drill' cubic feet with so possible cubic feet eith to possible leg possible, recovery by directional recovery by directional drillieg. drilling. Mining of Tract C-a seovald iteact up to 145 billinei Mining (act as stated fur Mining iact as stated to, cubic feet of tan reserves. 84 Mesa. 84 Mesa. bat partial recovery by di rectienul drill leg possible. eydrol opy. disposal pIle I eachate pro. eachat e dl scnarie could be eats. te disc barge cool d be 2_tac ts rrse 'act L.a elsie. All e.a al Vail ny Si on cool d reach 220 np . 231 griater than a' A. 321 arbiter than 04 Mesa. siei I ar to e4 Me.. eocnpt F Flood, bust efl tate years so get to .1" IM deep sceptIc and eith less deep saepage and urea could be ..IT .. At wor. plains 55th a state. teacisate. oure sarfece sater effects, .euesarfacesu ter effects. g'osn..s ter adversely could degrade sar face and Mere sater central auares "'..d. groandsaterresic rces for a Less Potential Moors* of- would be necessary. very loop period. facts to greansater than at

FIGURE 3 SUMMARY OF ENVIRONMENTAL CONSEQUENCES (continued)

Alterestloes nesource Element froposee ScsI as 1, Mess) if ml gel pall a creth 21 disc Porn it Irl nq creek if NO Acts on it 84 Mess. tess poteet al adverse of- 0,4,01 . Open pit easing Tract C-s facts to ireunater thea at all reiarlallny soesld iact andirlyles other iects fit. Tract C-a 84 Mesa. Floors, FloodS aquifers and intarcoanecs .1.1, As described ceder U plains (Cast. ) the U.. Mesa. 35 scres of a Iou-year flood- plate .14 be iopacted. l.sll areas of allasial valley floors sad flood- Or lactsf—Tract C-a plains as Tract Wcould be elsiegas described under 04 affected. Mesa. 55' elI Ce,-T/r— u1. tenti a i di spi acnt of ,otaet g al alspiacneat Sn lispi atut Of 3)1 Ic lisp1 aceveist Or .850 eJ it species ni esle deer. eeciaataos 445 eusle deer. sacbaatlov deer. secle_atice, potential deer. seclaiti as potential "Well.) of wildlife babi. potential of sildllfe Not- sf wildlafe habitat esala be of nildlife habitat would tat .1 d be good. tat would be adequate. adequate, be paor. Me ."Militant i neacts to iepacts to TIE specie as lopacts U TI°E specie, as Impacts to WE speci eq as terrestrial TIE species doscribed under 04 Mesa. described ceder 84 Mesa. described under Si Mesa. anticipated.

Ivestock potential loss of fOp atuelu fotevti al loss on I .50, wails potential loss on I Sit 5 voteetla I loss at 444 Al te-aoieg and 601 reductOse of cattle spread out Over 3 separat, spread out over 3 separate fri. lot allot_tnt.. As" fri. one grail eg allot- as lotsts. tows overall is- all stants, me overall I.. nest, pact eay got bets great as pact eay not be as erest for 84 Mesa. for 54 Mesa.

Si it MOfltt osaotiel loss 05 bus of I,' Potent Ian loss Of I .portae t isss area eutsi de the wild foteetial loss of I eportant portant ointerssg habitat on sIstering habitat. water re- horse word erea. water supply PoorTract C-.. e4 uesa. Potential loss of sources, sod restricted ieeortant eater supply soar eowata. I,pacts not as Potential loss Of ieport.nt Tract C-.. Migration and severe as 14 Mesa. water supply or Tract c-u. genetic Interchange eay be restricted. Forage coel tion site livestock.

Forestry nay iigact 3,504 acres cn_- May lepact 5,042 acres cue- say iepact J,Lbsl acres ci.- say specs 1.010 acres cue- eercial pin,00-jsniper cued eercial pieyoa.Jaoiper wood- rcial pisyon-Joniper eood. ,erciil pinyia-jswiper wood' laod. land. Greatest potential a.- laid. lot a sense 5 iact I aId. ly significant of all alternatives '""t'. to ants U WW Forest Maiage.est iactIt U SW forest Manage' foteeti sl loss of woodland Forest Manage.e nt Prru..og Prograt, eacept poteetu sS Pont P"'.. on Tract C-tasignificant losses Mrac Input to the 5044 Forest ioanuge.ent Proera..

2-24 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 4 SUMMARY OF ENVIRONMENTAL CONSEQUENCES (continued)

Cite rteut vet ______Renounce (Ieee's frogesee Action 54 Mesa) If rhiladespenia troth It west hoe-h of Spring creek 7/ Me Action 3/ Leads aid Ii prior to I sti isg rights II prior cii sting rights Is prior eon stAn1 rights 7 prior eli sting rights -gold ".its would b. impacted. would be iioutttd, including would be ieicted. be lu-nc ted. - futilities of. natural gas field. cii tonal I 35 efowon ca tO na I resources It known cuitaral resources 90 kIowa cul to ral resources au known to I tura I resources Resources would be libation. Weld be I u-acted. would be I ogatted. wool d be lu-acted. Paleontolooj Ig oMnosin u-wont of piston- Stellar to 54 Mesa. Slalla, to 04 Mesa. sietlae to 54but u-si, feewr tologicil resources would be iu-ac IS. facetted.

SOC ins Cegit gyp social I acts Ira slat Ian to 04 rosa. Siell ar to 04 Mesa. si.l Oar to 04 Mesa. oust less population fluctuations impact Am to finer workers. could "cur fr developeent of Tract C-a. Orrtrec t dis- posulcotta have little additional iguac I. LCOeoelc •wel iat on I ract L . a S eei I ir to 14 eesa. to 04sl.lIar Mesa. steel.. to 54 ions.. but less coil d have significant CC' i epact doe to (ewe rworkers once It tolsevueeCes • bat if rtract disposal would have little adds clonal au-act. Recreation Il.ihs acres or hantengrec- F.I acres on SuItIng ret . h.wolacres of belting rec . s,IuZ acres at MlotingreCrw. reatiwo area noald be is- reatiol area would be Ic- reitlon could be iepacted. atlol g-old be lepacted. patted, patted. llsaai Vol Class OP tress ewoold rejl class II iaed Clash II 0dM Class 50 aS Cuss II Sl.iiar 5004 Mesa. hit less, Aesoirces allaw evident changes to arias u-old allo, less areas would be leesucted. 5.- impacts. coO sd ni 1 osdsc.p.s, chasne china Class IV area. pacts would be wore seoere ler.fls to sessi t iwo wisua I thaw 04 Mesa and less sweere resoerces ..To occur, thee Phlladelphi. treeS.

lraosportatloa usrsadseet woos deoceed Stellar to we Mess. Siel I or to 34 Mesa. tensor to 54 ret.. eucept 205 of Cepacit. fewer labacls due to a settl- er wurt forte.

eons. Major noise scold reso It stellar to 04 Mesa Stellar eoel Mesa. .ess pr.duction sound result free retorting. Maui.. in less noise produced. level of 55 dO at 1 eile, with no iep.ct to residents.

FIGURE 5 SUMMARY OF ENVIRONMENTAL CONSEQUENCES (continued)

Al l—.11111 Action Res-me Element p roposed Pctipn I. u-sal If Pliludelsenli treet Af Melt hort of Spring creek LI h, 4/

wet Coergp Enero reseurces would be Sbnl w disposul soul a çequui re Sane us PhI I udel phii troth. To produce 1.106 Its. it coenerted tow ce unit ii. Additional O.OZolO° sewld etlllo. 0.160100 Ito. or asureeenit lotus). Shale Ito. not including eu-rD reqsir.d disposal would reogire an far shale disposal. additiownal 0.01o10° at.. tegwtation. vs p lant cowlties on 0.400 flint canitks on 11,544 Plant coolttes An 02.951 p ..' Cmnsttes we 5.1°c Species acres would be lu-acted. •cres would he iact.d. acresg -ild be iguicted. acres -geld b lu-acted. Less ret torti on poteisi ul Less restnrti en pet.nti 'I would be i.pacts to than O4Mesa. thin Be Mess, would se no iepacts to WE species, species. Zone candidate nod sensl tine tone candidate and sensitive species would be lu-acted, species would be lu-acted.

Solos Scala be highest reclatios dould be least soil atoll- would no deeper soils but would IT least nnhunL of Ii). potential and best tpportisn- .51. for reclamation. Cent. sohigher Contest of Cl eys and tursance to soils. It, to control . amaspect of disposal pile Is. then reosting recta- To rose It in drier soils. nation potential would be grew ter eros log control prohndes.

19011 PIle he CIsc terrain of 54 Mesa dIsposal would no 0 valley £I.liir to rinlladelpbna Siesldr tO *4 Mesa. Met 00 a beings end .a7 cnntrihwtw to pile stab- fill with possible cress on Creeb - hut wore eotensi ye seal I Cr Icat e, Construction init and erosion control - control problt during con- diversionwoter .osld be strsttien. necessary.

Swrea.e sun Inc lent growth cell a TedIwl qses howl I no 5 IwlIar teaparible no ni woe i ph Ia soeparas 1w to 04 Mesa. cut ow seclaatisn would be evuilahl. to ullu- toll Mesa. Out with less creek. a scalIer scale. standard r.veietetion tech- available growth .1.and ni pies. Owed poteanti 51 for less diners Icy in pt set Ca. estahl i snt 5 (waivers. ..IV estahl I se plant cani ty.

I! Inci We'the Cae Areae ad Tract C-a. Inclwdes the Common Am-ne. Tract C.a. and tint-of-tin Corridor. No ofrtract activities. 7 Threatened aad endangered.

2-25 SYNTHETIC FUELS REPORT, DECEMBER 1986 DRAFT EIS ISSUED FOR WOLF RIDGE NAIICOLITE MINE FIGURE 1 The U.S. Bureau of Lund Management (BLM) has issued a draft Environmental Impact Statement for a nahcotite solution mine in the Picennee Basin of LOCATION OF PROPOSED Colorado. NAHCOLITE MINE Wolf Ridge Corporation (WRC) proposes a solution mine that will produce a maximum of 125,000 tons per year (tpy) of sodium bicarbonate over a 30-year period. The proposal is for a site-specific mining operation initially producing 50,000 tpy, with es- calation in the second or third year to 125,000 illy. W RC's four sodium leases total approximately 8,222 acres and are located in Rio Blanco County (Figure 1).

Sodium bicarbonate, would be produced by mining nahcolite (naturally occurring sodium bicarbonate). Currently, all sodium bicarbonate produced in the world is synthetically manufactured. WRC officials believe that they can produce the lowest cost sodium bicarbonate through solution mining. The existing U.S. market, is approximately 380,000 tons per year.

The proposed project includes a well field for in situ solution mining of nahcolite; a handling and processing plant; evaporation ponds; and associated transportation, access, and support facilities, includ- ing natural gas and water pipelines, access roads, and a storage/rail-loading facility at Lacy Station railhead in Rifle, Colorado.

According to WRC's schedule, site construction would begin in 1987, with the first production oc- curring in the second quarter of 1988.

Background on Sodium Leases

On July 1, 1971, four sodium preference right leases were issued as follows,

Lease No. Owner

C-0118326 Wolf Joint Venture C0118327 Wolf Ridge Minerals Corporation C-0119986 Ridge Minerals Venture C-0119985 Rock School Joint Venture

In March 1972, lease No. C-0119985 was partitioned Mineral Corporation (MMC) acquired lease No. C- by the members of Rock School Joint Venture and 0118326 from WRC. MMC conducted exploration as a result, Advance Minerals Corporation (AMC) on the lease, drilling numerous holes (11) and con- acquired approximately 1,200 acres of land covered ducting other work. However, effective June 29, by that lease. In September 1972, the owners of 1982, M MC assigned all interest in the lease back the original lease Nos. C-0118326, C-0118327, C- to WRC. 0119986, and AMC, as the owner of 1,200 acres of original lease No. C-0119985, assigned the leases to In an April 15, 1983 decision, consolidated sodium Utah Shale Land Corporation. The assigned leases lease C-0118326 was reformed to comply with the were then consolidated into one lease, number C- Mineral Lands Leasing Act of 1920 by reestablish- 0118326. The Utah Shale Land Corporation later ing the three original leases and a new lease (1,200 changed its name to Industrial Resources, Inc. (IRI). acres out of C-0119985). These leases are shown in Figure 2. On March 1, 1980, lease Mo. C-0118326 was as- signed from IRI to Wolf Ridge Corporation, a The terms of the sodium leases are reproduced in wholly owned subsidiary. On June 9, 1980, Multi- Appendix 1.

2-26 SYNTHETIC FUELS REPORT, DECEMBER 1986 Proposed Action and Alternatives FIGURE 2 Four alternatives were identified and analyzed: W R C SODIUM LEASE MAP 1. No Action Alternative 2. The Proposed Action 3. 50,000 Ton Per Year (TrY) Alternative 4. 500,000 TPY Alternative The BLM'S preferred alternative is the Proposed mii Action. The No Action Alternative assumes con- U I struction and operation of a pilot-scale sodium NJ mine by WRC. The pilot-scale mine plan was pre- viously analyzed in an environmental assessment and subsequently approved on May 2, 1986, by BLM. As such, this action is independent of WItC's commercial-scale mine plan and can occur regard- less of the outcome of the EIS. The solution mining technique proposed by WRC, I which is common to all four alternatives, involves drilling two wells, establishing communication be- tween the wells by drilling two intersecting horizontal holes, and circulating hot water between ..rnririu wells to dissolve the nahcolite. Once the saturated solution is brought to the surface, the sodium bicarbonate will be recrystallized, dewatered, dried, and shipped to market. Figure 3 shows the general solution mining technique.

IwoNS FIGURE 3 GENERAL SOLUTION MINING DIAGRAM

CARBONATE hCRYST^X^ATION PLANT INJECTtONLL PRODUCtION .ELL WELL Development Schedule The first phase of development was a 3-ton per day bulk sampling operation. This testing phase, which ran from November 1983 to February 1984, '1 produced 165 tons of high purity sodium bicar- bonate. WRC believes that thi program was successful in demonstrating the effectiveness and feasibility of their solution mining technique. AT-Sfl NHCO, !0 IOLLO CAVITY The second phase of development involves construc- tion and operation of a 6-ton per hour pilot-scale mine. Although the original pilot mine plan was approved by BLM in February of 1984, no develop- ment occurred. In the summer of 1985, WRC sub- The sodium minerals that would be solution mined mitted revisions to the approved pilot plant mine are located in the Sales Bed, a 40-foot thick plan. An environmental assessment by BLM was sequence of nahcolite, oil shale, and nahcolitic- approved on May 2, 1986. WRC projected a halite that assays between 80 and 85 percent production start-up date in 1986. sodium bicarbonate and lies at a depth of about 1,900 feet. Approximately 26 feet of this zone The third phase of development is the Proposed would be solution mined to produce various grades Action (125,000 TP I Commercial-Scale Nahcolite of sodium bicarbonate. Sodium bicarbonate has ap- Solution Mine), which is the focus of the environ- plications in solution buffering, textiles, plastics mental impact statement. and rubber, soaps and detergents, fire extinguishers,

2-27 SYNTHETIC FUELS REPORT, DECEMBER 1986 leather manufacturing, medication, food stuffs, feed An existing dirt road, approximately 3.3 miles in supplements, control, and sewer and length, would be utilized to access the sodium mine water treatment. The recovery of in-place nab- facility. This road, as shown in Figure 2; would be colite within the Boies Bed would probably be upgraded to accommodate access from existing about 40 percent. Approximately 12,000 tons of paved Ryan Gulch Road (Rio Blanco County Road naheolite would be produced from each cavity, as- 24) to the plant site. suming 300-foot well spacing. Affected Resources Each well would initially be drilled with an auger or bucket type drill rig to a depth of 50 feet, with In Figure 4, part of the R-7 zone, the B-Groove, a hole diameter of 15 3/4 inches. A 13 3/8-Inch k-fl, and part of the L5 oil shale zone constitutes surface casing would be cemented In place. A the "leached zone". Within this sequence, the rotary drill rig would then drill a 12 1/4-inch hole Mahogany Zone is the most economically important to a depth of approximately 1,900 feet and circu- interval, averaging 175 feet in thickness and having lated clean. an average grade of 29 gallons per ton (gpt) of shale oil. The leached zone ranges from 590 to Following completion of each well, horizontal drill- 672 feet in thickness within the lease earn. ing would be initiated from the bottom of each hole for a length approximately half the production well spacing; the goal would be to intersect about midway between wells. FIGURE 4 Solution Mining Process GENERAL STRATIGRAPHIC The solution mining process involves utilizing a hot barren liquor (essentially hot water) to dissolve COLUMN nahcolite within the Bolas Bed. The hot barren liquor would be pumped from the process plant to the well field through an aboveground 8-inch diameter piping system. At the well field, the barren liquor would be diverted to a series of I IT N 0 LOG Y production well pairs. Each well pair would consist tv..:. 00 of one injection well and one extraction well, each JINTA vt equipped with a nominal 5 1/2-inch diameter pipe string. FORMATION :.. ISO T0,s,CI Or Each well pair would be quippped with an injection pump, a plate and frame-type heat exchanger and 500 1A.0.1 0, 6-inch insulated piping between the 8-inch header t Oil and the well head. The injection pump and heat '000 exchangers would be skid mounted to facilitate 111111111 .' Sn,.. IN Ud0O N"'. handling during relocation to a new pair of produc- SE tion wells. IZl0 -- AN lost Saturated solution (pregnant liquor) containing dis- A I,000flt17 solved sodium bicarbonate would enter the process us.OG*;, Lost plant from the well field. Impurities, such as inor- ganic solids, would be removed from the pregnant r '0* a • InoVflL..L - A. liquor through filtering. The filtered solution would •5 ZONE Ltsc,lE0 ZONE then flow to a crystalizcr and then to a centrifuge. 100 lOIS! 3 OISIOLUI ION IIflF4C( Next, the crystals would undergo drying; the L• t*titlNt0L IIflENISLT product would then be sized and sent to the ''00 product begging facility. ES - ,., ZONE

LONER SALT Evaporation ponds would be utilized to evaporate £100 - waste water from plant wash down, boiler blow L.4 ZONE down, water treatment system blow down, discharge w- 0400 60 from the filtering system, and well field pipeline N., LONE drainage. L- I lONE• 0400 Water would be required for solution mining, *% ZONE processing, boiler feed, potable, and fire protection LI ISE 1500 uses. Water would be supplied from a water well in Section 24, Township 1 South, Range 98 West. N., LONE so It would be pumped through a buried 4-inch j -0*5,00 SANNEN diameter, 10,000-foot long water pipeline from the well to a water storage tank near the plant site.

2-28 SYNTHETIC FUELS REPORT, DECEMBER 1986 The lowest section of the Parachute Creek Mem- Facilities approved under the pilot project include ber, the Saline Zone, averages approximately 1,000 a 5-acre plant site, a 4-acre well field for in situ feet in thckness. It is bounded at the top by the solution mining of naheotite, an evaporation pond dissolution surface and includes all or part of the encompassing 4 acres, a new water well and ancil- L-5, the ft-S and ft-2 zones, and all of the L-4, R- lary pipeline, and upgrading (including graveling) of 4,L-3,11-3, and L-2 zones (Figure 4). the existing access road into the plant site. The target zone of the proposed plan is the Boles The EIS finds that no significant adverse impacts Bed, which constitutes the lower section of the L-5 will result from the No Action (Pilot Project) Al- Zone (designated the L-5A or Boles Bed). In the ternative. Minor short-term impacts will occur to lease area, the top of the Boles Bed Is generally air quality, soils, vegetation, livestock grazing, 100 feet or less below the dissolution surface. , wildlife, and recreational/visual resources. Cultural and paleontological resources The Boles Bed is composed of three different will also be potentially impacted. Existing and fu- fades in the lease area. The proposed project Is ture mineral lease rights could be complicated be- located in the naheolite fades where the Boles Bed cause of diminished surface occupancy possibilities averages 30 feet in thickness and 80-65 percent within the project development area. granular nahcolite by weight. This portion of the Boles Bed Is of limited extent in the lease area. Groundwater consumed by the pilot project will To the south and west of the project area, contribute cumulatively to adverse alterations of groundwater movement has totally removed the downstream endangered fish habitat, although the bed. To the north and east of the project area, project, by itself, will probably not jeopardize the the Boles Bed enters the transition facies where it continued existence of any listed fish. Mitigation is composed of nahcolite and nahcolitic halite. (conservation measures) will compensate for this impact. The remainder of the Saline Zone below the Boles Bed consists of the ft-S through R2 zones. This The Proposed Action would involve: expansion of interval contains the R-4 Zone, which in this part the approved pilot project well field and plant site, of the basin Is the richest oil shale zone in the paving of the access road into the plant site Parachute Creek Member. In the lease area, this (affecting up to 215 additional acres), construction zone averages 158 feet in thickness, 33 gpt shale of additional evaporation ponds (affecting up to 22 oil, 23 weight percent nahcolite, and 9 weight per- additional acres), construction of a natural gas cent dawsonite. pipeline into the plant site (involving 17 acres), and additional of a warehouse/rail loading facility at The federal government has leased 100 percent of Lacy Station in Rifle, Colorado. the oil and gas mineral estate underlying WRC's sodium tease tracts. Although no producing oil or The only potentially significant adverse impacts as- gas wells exist on the project area, it is underlain sociated with this alternative would be to local by potential oil and gas producing formations. groundwater quantity and quality. There would be a S percent reduction in average daily flow from No minerals of economic significance are known to Yellow Creek. This could be mitigated through a occur within the Uinta Formation. The Mahogany state required water augmentation plan. The area Zone contains an estimated 350,000 barrels per of the base of the lower aquifer in contact with acre of shale oil in the project area over its entire salts would increase by approximately 20 percent thickness. Although the leached zone below the within the lease tracts. Mahogany Zone contains significant quantities of oil shale, the dissolution of the sodium minerals and Potential surface subsidence of less than 1 foot resultant poor rock quality renders the recovery of would also occur; however, none of these impacts minerals from this zone infeasible. Within the would be considered significant after application of project area, the Boles Bed is estimated to contain mitigation. 66,000 tons/acre of naheolite, and the L-5E Bed to contain approximately 51,000 tons/acre of naheolite. The 50,000 TPY Alternative would involve construc- Estimated in place resources within the remainder tion and operation of a 30-year solution mine of the Saline Zone beneath the Boles Bed (ft-S producing 50,000 toy of sodium bicarbonate. It through ft-S zones) are 1,500,000 barrels per acre would essentially be an expansion of the 2-year of shale oil, 724,000 tons per acre of nahcolite, pilot project to a 30-year commercial facility. It and 159,000 tons per acre of dawsonite. would involve similar, but less expansion than under the Proposed Action. Impacts The EIS concludes that no potentially significant Under the No Action Alternative, the approved adverse impacts would occur under this alternative. pilot project will take place; however, expansion of Resource impacts would be similar, although the approved pilot project to a commercial-scale greater than those addressed under the No Action project will not occur. Alternative, because of the 30-year project life. Potential surface subsidence of less than 1 foot would also occur under this alternative.

2-29 SYNTHETIC FUELS REPORT, DECEMBER 1986 The 500,000 TPY Alternative would involve: sub- All private land and any actions on private land stantial expansion of the approved pilot project not subject to a required permit, action or decision well field and plant site (affecting up to 818 addi- are exempt from the policy. tional acres), a commercial transmission line into the plant site, bulk product loading and handling Impact assessments and mitigation recommendations facilities on-site and at Lacy Station, and a coal- are to be based upon a systematic evaluation of fired generator and associated facilities. fish and wildlife resources and habitats. The policy states that the Division will distinguish between The EIS concludes that impacts to all resources recommended mitigation for impacts which are would be greatest under this alternative. Poten- direct and those which are indirect, between tially significant impacts would occur to air recommended mitigation for impacts on-site and quality, groundwater quantity and quality, cultural those off-site, and between recommended mitigation resources, and riparian-wetland habitat along Yellow for impacts on private land and those on public C reek. land.

The policy also states that while the cost of mitigation is the responsibility of a project proponent and project beneficiaries, it will not be part of the Division's recommendations to suggest COLORADO WILDLIFE COMMISSION APPROVES who should pay for specific mitigation. The cost WILDLIFE MITIGATION BANKING of mitigation is a responsibility that should be shared by the State of Colorado in those instances At its meeting on November 20, 1986, the Colorado where initiatives of the State cause the impacts or Wildlife Commission accepted in principle a new where the State receives economic or wildlife draft of a proposed Wildlife Mitigation Policy. benefits from the project. This document has been undergoing numerous revi- sions by its working committee for a number of Mitigation banking, a method of crediting a project months. A series of public hearings has been held sponsor for its activities that benefit wildlife and around the state. wildlife habitat in other areas, is an innovative concept that should allow greater flexibility in In essence the policy suggests that any industrial meeting the States wildlife needs. The Division development which impacts wildlife in the state was specifically directed by the Commission to in- should develop mitigating or offsetting measures. vestigate the concept of mitigation banking to put The policy statement defines mitigation as 'a the concept in a workable form as soon as prac- mechanism for addressing undesirable impacts on ticable. fish and wildlife resources. It can be accomplished in several ways, including reducing, minimizing, rectifying, compensating, or avoiding impacts. Where a project can be reasonably modified to avoid or minimize specific impacts, while still ac- complishing the purposes of the project, that course is preferable. In making mitigation recommenda- BLM TO PREPARE NEW WILDERNESS EIS IN tions, the next priority will be given to mitigating NORTHWEST COLORADO the loss of fish and wildlife resources with similar resources in the general vicinity of the impact. Mitigation which can only be achieved by avoidance The U.S. Bureau of Land Management in Craig, of the total project shall be recommended only as Colorado, is preparing a wilderness environmental a last resort in the most extreme of cir- impact statement (EIS) for the White River, cumstances." Kremmling, and Little Snake resource areas in northwest Colorado. Figure 1 shows the location Mitigation measures proposed by the Colorado Divi- of each of the Wilderness Study Areas (WSAs) being sion of Wildlife are advisory recommendations to analysed. The draft EIS which is now being project proponents and permitting agencies. Al- prepared, will consider seven WSAs: though such mitigation recommendations may be- come binding through conditions in permits issued by other agencies, the mitigation policy itself does not vest authority in the Commission or Division to require such mitigation measures.

2-30 SYNTHETIC FUELS REPORT, DECEMBER 1986 Name Location Affected Land Use Plan Bull Canyon Moffat County, CO and White River MFP (Cob) C0-010.001/ Uintah County, UT Bookdiffa RMP (Utah) UT-080-419 Approx. 4 mites north of Dinosaur, Co White River Resource Area Willow Creek Moffat County, Co White River MFP CO-010-002 Approx. 7 mites northeast of Oinoea',r, CO White River Resource Area Skull Creek Moffat County, CO White River MFP CO-010-003 Approx. 7 miles northeast of Mastodons, CO White River Resource Area Black Mountain Rio Blanco County, CO White River MFP CO-010-117A Approx. it mites west of Meeker, CO White River Resource Area Windy Gulch Rio Blanco County, Co White River MFP CO-010-007C Approx. ii miles northwest of Meeker, CO White River Resource Area Oil Spring Mountain Rio Blanco County, CO White River SI t'P CO-010-046 Approx. 25 miles southwest of Rangoly, CO White River Resource Area Troublesome Grand County, CO Kremmling RMP CO-OlO-ISS Approx. 18 miles north of Kremmllng, CO Kremmllng Resource Area • MFP - Management Framework Plan • Rfl - Resource Management Plan

FIGURE 1 WILDERNESS STUDY AREAS

lULL CANYON OIL SPRiNG MOUNTAINSLACK MOUNTAIN TROUILESOIIE WltLOWcREE,r WINDY GULCH 5ICULL CREEK WYoNØ ca,y,/4 atjLsI

I9 ' r eI r" •ou / V" 4. Aye" I UNCLe . AtlQft&l__.l . I tea us u,aTaa an. I ) an I lOSLaNC 1 ' _•___•j hr RD 7 UTAH aapaSOt jI i . , Lactt j

I . pawa i]_. " ' _1.__. I 4 I — 4-CL a aaa ,5 Os.Sl.ewa '—I 1, INELT , c.o a'. ISaAC coat LEiCUMEST ausalsoc - CT A — •_l --I —

"e. •AYeCN\ ajuac ------j aacuacHc \ S -

2-31 SYNTHETIC FUELS REPORT, DECEMBER 1986 WATER

COMPROMISE DEVELOPED TO PROTECT (2) Refining operations at Federal reservoirs. ENDANGERED FISH IN COLORADO RIVER For example, the Bureau of Reclamation would refine operations at Ruedi Reservoir The United States Fish and Wildlife Service of the to release an additional 5,000 acre-feet in Department of the Interior is preparing an en- the months of July-September on an vironmental assessment on a program to recover average of 4 out of 5 years four rare and endangered fish species in the Upper (supplementing the 5,030 acre-feet with- Colorado River Basin. held from sale). Flaming Gorge Reservoir has already adopted an interim flow The four fish species of concern are the Colorado release schedule Intended to improve rare squawfish (Ptychocheilus Lucius), humpback chub and endangered fish spawning and survival. (Gila cypha), bonytail chub (Gun elegans), and Blue Mesa Reservoir will also release razorback sucker (Xyrauchen texanus). The first water to ensure that n 2,000 cubic fcut/ three species are listed as endangered, and the second minimum flow occurs below the fourth is a candidate for listing under the En- confluence of the Gunnison and Colorado dangered Species Act. Rivers on an average of 0 out of 10 years. Though once abundant in the upper basin, these fish are now threatened with extinction. Their decline (3) Purchasing or leasing existing water rights, is attributed to a number of factors, ranging from on a willing sailer basis. habitat reduction or alteration to introduction of non-native species. The Service has stated that (4) Acquiring "excess" water resulting from continued water development within the upper basin agricultural water conservation and salinity is likely to further jeopardize those fishes' exist- control projects. ence. (5) Changing the point of diversion for senior The affected area is located in oil shale regions of water rights to downstream locations. Colorado, Utah, and Wyoming. (C) Acquisition of nontributary ground water The proposed action was developed by a subcom- that could be pumped and put into mittee of the Upper Colorado River Basin Coor- strea ms. dinating Committee. The Coordinating Committee is composed of representatives from the States of (7) Applying for original appropriation of in- Colorado, Utah, and Wyoming; Bureau of stream flows in surface streams. Reclamation; Fish and Wildlife Service; private water development interests; and environmental or- Habitat Management ganizations. The Department of the Interior is considering adopting their proposal for resolving Other recovery actions might include such habitat water use conflicts involving rare and endangered management measures as artificial creation of fish as follows: spawning areas and winter habitat, building fish passages, and propagation and stocking. Administration Funding A Recovery Implementation Committee repre- senting Federal, State, private water development, Congress would be requested to establish two spe- and conservation interests in the upper basin would cial funds: oversee implementation of recovery actions for the four rare and endangered fish species. The (1) Water rights fund ($10 million): Used to recovery timeframe is estimated at 15 years. acquire water rights to secure instream flows for the rare and endangered fishes. Recovery Actions (2) Construction fund 05 million): Used for After determining the locations, times and quan- recovery actions involving capital expendi- tities of instream flows needed to protect and tures, e.g., constructing hatchery or fish recover the fish, the committee would evaluate al- passage facilities, changing the point of ternative means for providing necessary flows. diversion of a water right, or modifying Potential sources of water may include: habitat. Some $2.4 million would be provided yearly for recovery actions. The (1) Water from Federal storage projects. For Federal share would total $2.1 million, and example, the Bureau of Reclamation would the States' share, $300,000. Private water withhold from sale 5,000 acre-feet of developers would contribute a one-time water at Rued! Reservoir. This water amount of $10/acre-foot (based on average would be released in the months of July- annual depletion and adjusted annually for September, as needed. inflation) for new water depletion projects.

2-32 SYNTHETIC FUELS REPORT, DECEMBER 1986 The proposed action has drawn fire from a number of sports and recreation oriented interests who lump the species in question as 'trash fish". They fear that the proposed measures could inhibit some Gold Medal Trout fisheries and inconvenience beaters in the Federal reservoirs. Water develop- ment interests object to the $10 per acre-foot charge as excessive.

Others feel that the plan may resolve what has been a potential major stumbling block for water development in the Upper Colorado River Basin. Although the draft plan will likely be modified ex- tensively in the coming months, its release marks a turning point in coping with conflicts between water development and endangered species. While water interests may resent paying to supplement stream flows, contending that other factors con- tribute to the species decline, the guaranteed in- stream flows proposed in the plan may be the only way around the logjam blocking new water projects.

2-33 SYNTHETIC FUELS REPORT, DECEMBER 1986 RESOURCE

COURT SUPPORTS UTE TRIBE IN UTAH CASE Corporation. Upon approval of the exchanges, the lessees would relinquish the State Oil Shale Leases liintah and Duchesne Counties in Utah, and the and they would then receive a preferential oil shale state of Utah are appealing a decision by the lease on the acquired lands, United States Tenth Circuit Court of Appeals which gives the Ute Indian Tribe jurisdiction over lands On December 4, 1985, Paraho Development Cor- between the trust land and the original reservation poration filed a preferential application for Oil boundaries. This area encompasses much of Utah's Shale Leases MLA 42749, on those parts of the richest oil shale resource (seePace Synthetic Fuels lands acquired under U.S. Patents 43-85-0027 and Report, December 1985, page 2-49 and June 1986, 43-85-0013 subject to the agreement between the page 2-43.) Division of State Lands and Forestry and Paraho Development Corporation. With the relinquishment The problem was created when Congress first es- of the State leases, the agreement is complete. tablished the reservation, and then later opened it Preferential lease application MLA 42749 was to homesteading without dis -establishingthe reser- therefore approved on the following lands: vation. The lawsuit has been ongoing for the past 10 years and was initially a law enforcement and T95, 11245, SLB&M. hunting rights issue. Now Uintah and Duchesne Section 24: Lots 1, 4, 5, 6, 7, 10, N1/25E1/4 County commissioners fear that jurisdiction will in- Section 25: Lots 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, volve taxation, planning, and water rights. The 12 NWI/4SWI/4, S1/2S1/2 ruling awarded the tribe jurisdiction over most of Duchesne County and the southern half of Uintah T9S, R25E, SLB&M. County. Section 19: SW1/4 Section 30: Lots 1, 2, 3, 4 In early November 1986, the U.S. Solicitor General Section 31: Lots 1, 2, 3, SWI/4NEI/4, S1/2 advised the U.S. Supreme Court not to hear the appeal of the Ute jurisdiction case. TieS, 11245, SLB&M. Section 1: Lots l,2,3,4,5,S1/2NE1/4,SEI/4NWI/4, In late November the Supreme Court refused to N1/2S1/2,N1/251/25W1/4,SW1/45W1/ hear the appeal, allowing the 10th Circuit Court of 45W 1/4 ,W l/2E1/45W1/45W1/4,SE 1/4 Appeals ruling to stand. 551/45W l/4,S1/2SEI/4,SWI/4 SE 1/4S W 1/4 The ruling gives civil jurisdiction to the Ute Tribe over its Tribal members in the outer boundary. 2,176.10 Acres -- Uintah County

The Tribe's official stance, when the 10th Circuit Since this application was filed, Paraho Develop- Court decision was handed down, is that there will ment Corporation was merged into a new corpora- be no immediate change. tion, The New Paraho Corporation.

Federal and state lands will continue to be ad- In separate actions, the Division cancelled the fol- ministered by the federal and state government, lowing oil shale leases for non-payment of 1986 non-Indian hunting rights on these lands will not be rental: affected. Name Account No. It may take years to determine the long-term af- fect of the decision. Some other tribes in similar Al T. flays ML 30447 situations have imposed sales taxes and it is pos- Booker T. Green ML 30532-A sible to conceive of a severance tax on minerals. Michael P. Huber ML 30532-C Prehiad S. Vachher ML 40170 Prehlad S. Vachher ML 40171

Relinquishments were received on the following oil shale leases:

NEW PARAHO CORPORATION SETS UTAH LAND EXCHANGE

In August, the Utah Division of State Lands and Forestry and Paralio Development Corporation en- tered into an agreement for the acquisition of cer- tain federal lands by exchange with the United States Bureau of Land Management. The lands used as base for these exchanges are covered by State Oil Shale leases held by Paraho Development

2-34 SYNTHETIC FUELS REPORT, DECEMBER 1986 ML 20679 Amoco Production Co. 1105, R23E, SLB&M. 640.00 acres Sec. 36: All

ML 20680 Amoco Production Co. 1105, lt24E, SLB&M. 640.00 acres Sec. 16, All ML 20682 Amoco Production Co. 1105, R24E, SLB&M. 640.00 acres Sec. 32: All

ML 40335 Paraho Development 195, R23E, SLB&M. 120.00 acres Sec. 10: N E1/4 N £1/4 Sec. 13: NW1/4NE1/4 Sec. 17: NW 1/45W 1/4

In its October 6 actions the Division accepted a bond in the amount of $2,000 from Miracle Rock Mining and Research, the lessee on leases ML 42844 and ML 42844-A NCM (shale) to cover operations on those leases. Cancelled was non- classified minerals (shale) lease ML 33389 for failure to meet diligence requirements.

OIL SHALE LAND TRANSFERS FINALIZED In the face of this controversy, the Interior Department then announced a delay in the actual As reported in the Pace Synthetic Fuels Report for transfer of title to the lands. However, when the September, 1986, page 2-49, the U.S. Department Colorado appeals failed and the Congressional of the Interior agreed to settle decades-long litiga- amendment proved inoperative, Interior again moved tion over unpotented oil shale claims in the forward in October to complete the transfer of Piceance Creek basin by granting patents on some 64,000 acres. Some 18,000 acres were delayed be- 82,000 acres of claims. cause of incomplete survey information.

The announcement of the settlement immediately Table 1 presents a summary of the current status invoked storms of protest from Congross and of the patent applications. Note that all applica- Colorado state officials who protested that the tions in status categories B, C, D, and C have agreement was a surprise to them, even though it been or will he patented as part of the settlement had been clearly mandated by Judge Finesilver's agreement. decision in 1985 (Pace Synthetic Fuels Report, June 1985, page 2-38). Several members of Congress announced hearings intended to block the transfer and the State of Colorado filed motions in both the U.S. District Court in Denver and the 10th U.S. Circuit Court of Appeals to set aside the settle- ment. Colorado Senator Gary Hart introduced an amendment to the Interior Department appropria- tions bill forbidding Interior to complete the trans- fer for six months.

2-35 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1

OIL SHALE MINERAL CLAIMS STATUS

Owner Mineral Number Status Contest ship Entry Of Category Number Group Number Applicant Claim Nnmes(,) Claims Acreage

B 688 1 C-07667 Union Oil Girls Group 1 37 5,930.07 B 688 C-09072 Union Oil Girls Group 2 78 12,167.00 660 2 C-012327 Pacific Oil Oyler 1-4 4 836.38 B 193 3 C-014 671 Weber Sunset 1-31 31 4,957.01 C 699 4 C-BUSS? Gabba Exploration MouThs 13-20 8 1,123.53 B 686 C-018673 Gabba Exploration Greeley 1-6,8 7 897.50 B 260 5 C-016334 ERTL, Inc. Tomboy 1-12 12 1,926.56 B 260 C016671 ERIL, Inc. Liberty Bell 1-12 12 1,921.12 B 260 C-029127 ERTL, Inc. Bute 29 1 160.00 B 260 C-029428 ERTL, Inc. Bute 20 1 160-00 B 260 C-031342 ERTL, Inc. Atlas 4-6,8,11,13-iS 9 1,140,00 C 696 6 C-022159 Savage, at al hydrocarbon, at at 7 7770.00 C liD? C-0221 69 Savage, at al 07 2,281-98 C 698 CO22461 Savage, at iii 02 1,010,66 B 658 7 C-028751 Farnum at al Compass Group 4 526.00 B 659 8 C-030979 Wasatch Development Carbon 1-5 t6 2,100.00 Elizabeth 1-2,4-12 B 685 9 C-031270 Savage Hoffman 20 1 75.07 B 685 C-031271 Savage Hoffman 18 1 75.03 B 687 10 C-045092 Hugg Jackpot t-li Il 1,718.43 C 692 Il C-23936 Amerada-liess, et at Ohio I-SB 50 7,801.91 C 694 12 C26407 Toaco Bute 3348 16 2,551.60 C 690 13 C-25406 £RTL, Inc. Atlas 12,17,18 23 3,688.16 Campbird 1-20 C 689 C-25408 CRTL, Inc. Atlas 1,2,3,7,9 5 788.70 C 695 C25109 ERTL, Inc. Bute 1-19,21-28,30-32 30 1,820.07 A 359 14 CO23661 Frank W. Winegar Mtn. Boys 6 17 2 329.00 Shell Oil Company A 360 15 C-050450 D.A,Shele, Inc. Ii. Shoup 14 4 565.01 O 711 16 C-31841 Thee Ertl, Trustee Pueblo 23-26 4 640.00 D 718 C-31842 Theo Em, Trustee Nancy 1-8 8 1,276.15 D 713 C-33132 Dorothy Joseph, at at Ruth 29-32 4 640.00 (36426) Dorothy Joseph, et ai N SW 712, WAW 25-28 W & W 40-43 22 2,240.00 D 714 C-33143 Dorothy Joseph, et at Ruth 9-20 16 2,560.00 GJ 1-4 D 715 C33114 Dorothy Joseph, at al Ruth 25-28 4 630.00 0 717 C-33445 Dorothy Joseph, at al Ruth 20-24 12 - 1,920.00 (36428) WAN 32-39 O 716 C-33446 Agnes Churchell GJ 5, Rugh 6-8 4 640.00 O 705 C-33447 Theo Cal, Trustee Pueblo 29-38 8 1,280.00 O 706 C-33448 Theo Cr11, Trustee Pueblo 15, 17-22 7 1,120.00 O 704 C-33449 Theo Ertl, Trustee Pueblo 1-6, 8,16 8 1,280.00 O 707 C-33460 Theo Ertl, Trustee Pueblo 9-14 6 980-00 D 719 C-33451 Thee Cal, Trustee Pueblo 27,28,37-14 10 1,600.05 0 708 C-33452 moo Em, Trustee Cedar 1-8 16 2,564.97 Helen Agnes O 708 C-33732 Theo Ertl, Trustee Cathedral 17-27 11 1,708.97 O 710 C-36426 (Sea C-33432) O 712 C-36428 (See C-33445) E 20 C-38402 Union Oil Company French 13-16 1 1,903.00 17 C-35080 Harlan S Dorothy Iiugg Pickup 1-7 7 1,120.00 E 18 C-36203 Harlan ft Dorothy Hugg Bluebird, etc. 13 2,080.00 C 725 19 C38122 ERTL, Inc. Atlas 10 1 120.00 E 21 C-38579 Exxon Corporation Washington 1-8 Atlantic 1-8 Princess Ann 1-4 20 3,200.00 C C-39464 Union Oil Company French 1724,Land 21310 1,216.14 C-41835 Toaco Hydrocarbon 76-87 12 1,880.00 C-43354 Company Portland 1-6 6 982,92

Total 609 82,800.00 Legend

A - Substantially completed through United States Supreme Court. Patent Issued November 12, 1982 for H Shoup 1-4 claims B - Completed through Interior Board of Land Appeals and District Court —Judge fllhesilver decision May 1, 1985 (In settlement) C - In Judge Flnesilver's January 27, 1981 court order, Judge Flnesilver decision May 1, 1985 (in settlement 0 - In contest action; hearing completed before Administrative Law Judge Sweitzer, appealed to IBLA then directly to 10th Circuit court C - Patent applications awaiting aIidlcation, field examination completed F - Patent applications awaiting asdlcation and field examination G - Atlas 10 in suspended contest and moved directly to settlement

2-36 SYNTHETIC FUELS REPORT, DECEMBER 1986 RECENT OIL SHALE PUBLICATIONS/PATENTS

The following papers were presented at the American Institute Of Chemical Engineers 1986 Annual Meeting, Miami Beach, Florida, November 2-7, 1986: Carter, S.D., et al, 'Some Aspects of the Optimization of Parameters for Fluidized Bed Retorting of Eastern U.S. Oil Shale." Camp, D.W., et al, "Modeling of an Oil Shale Retort with Packed-Bed Pyrolyzer and Cascading-Bed Combustor." Roberts, M.J., et al, "Effect of Temperature and Pressure on the Ilydroretorting Yields of Three Eastern Oil Shales." Parkinson, E.J., et al, "Yield Optimization of an Experimental Retort Using the ASPEN Computer Code." Bickel, T.C., et al, "Applications of Laboratory Retorting Results to the Design of a high Yietd VMiS Oil Shale Retort." The following presentations were made at the Second Annual Oil Shale Contractors meeting in Morgantown, West Virginia, August 12-13, 1986; Petersen, E . , "Effect of Mineralogy on Oil Shale Processing, "Los Alamos National Laboratory. Grinin, U . , "Size Distribution of Minerals/Organic Matter in Oil Shale," METC. Gregoire, C., "Oil Shale Mechanistic Models," METC. Khan, R., "Wcathoring/Prcoxidation of Oil Shale," METC. Shadle, L., "Studies of the Initial Stages of Retorting Using the Flashlamp Reactor," METC. Ilasfurther, V . , "Evapotranspiration of Shale Oil Waters," University of Wyoming. Room ert, P . , "Comparison of Processing Parameters for Generic In Situ and Surface Processes," Sandia National Laboratory. Bickel, T., "Demonstration of Uniform Retorting of Oil Shale Beds with Void Contrasts," Sandia National Laboratory. Kuszmaul, J., "Status of Overall Fracture Modeling Development," Sandia Na- tional Laboratory. Rex, R., "Moving-Bed 1-lydroretorting Research," Flycrude Corporation. Tippin, R.B., "Beneficiatian-Hydroretorting Research," Mineral Resources Institute, University of Alabama. Carr, V.," In Situ Conversion of Eastern Oil Shale," Eastern Shale Research Corporation. Aho, G. , "Preliminary Design of 500 TPD Roller-Grate Retort System," Cliffs Engineering, Inc. Inguva, R., "Radio Frequency Retorting and Modeling," University of Wyom- ing. Sudduth, B . , "Radio Frequency Retorting in the Low Void Retort," Western Research Institute.

2-37 SYNTHETIC FUELS REPORT, DECEMBER 1986 Sullivan, P., "Acid Drainage in Eastern Oil Shales," Western Research In- st i tute.

Rob I, T . , "Lysimeter Studies in Eastern Oil Shales," Kentucky Center for Energy Research.

The following paper was presented at the 36th Canadian Chemical Engineering Con- ference held in Sarnia, Ontario, Canada, October 5-8, 1986:

Tam, T., et 01, "Pyrolysis of New Brunswick Oil Shale In A Spouted Bed.

The following papers were presented at the 1986 Eastern Oil Shale Symposium held in Lexington, Kentucky, November 19-21, 1986:

Weinecke, M.H., "An Update: Cliffs Engineering, Allis Chalmers Indiana Oil Shale Project."

Corr, V.11,, "Eastern Shale In-Situ Project--An Update."

Bartke, T.C., "U.S. Department of Energy Funded Research /Projects."

Damukai t is, J .," Ilydrogenat ion -Extract ion Process."

Piper, E.M., "The Petrosix Project in Brazil--An Update."

Ward, M.C., et al, "An Evaluation of the Processing Options for Ontario Oil Shales--The Canmet Study.'

Cena, R . J . , et al, "Results of Rapid Pyrolysis Experiments Using Eastern U.S. Oil Shale in the Livermore Solid-Recycle Retort."

Carter, S.D., "Flu idized Bed Kinetics of New Albany Oil Shale.'

Lau, F.S., et al, "Gasification Characteristics of Eastern Oil Shale."

Lamont, W.E., et al, "Beaeficiation--Hydroretort Processing of U.S. Oil Shales."

Ilanna, J., et al, "Agglomeration and Retorting Characteristics of Beneficiated Oil Shale."

Flynn, G.T., "The Chatham Station Circulating Fluidized Bed Demonstration Project."

Res tam-Abadi, M., et al, "Co-Processing of Coal and Oil Shale: Advantages and Disadvantages."

Fahy, L.J., et al, "Horizontal Low-Void Retorting of Eastern and Western Oil Shale."

Shamsi, A. et al, "Catalytic Effect of Low-Temperature Ashed Shale on llydrodesulfurization of Thiophene."

Rex, R.C. Jr., et al, "A Comparison of Hydroretorting and Thermal Retorting Fact lit ies for the Processing of Eastern Oil Shales."

Sethi, V.K., et al, "Corrosion and Wear of Materials in Oil Shale Retort- - ing.

Rubel, A.M. et al, "Pressurized Steam Retorting of Kentucky Oil Shale: An Investigation of the Role of Steam in Oil Yield Enhancement."

Brown, G.O., et al, "Aspects of Vapor and Liquid Flow in Retorted Oil Shales.

Sullivan, P.J., "Acid Potential of Eastern Oil Shale and Waste Products

2-38 SYNTHETIC FUELS REPORT, DECEMBER 1986 Misra, M. eta!, "Characterization and Recovery of Accessory Trace Elements from Alabama Oil Shale Waste Waters."

Willard, D . E ., 't Environmental Monitoring Plan for a Demonstration Oil Shale Retort in Southern Indiana."

Selby, C.dP., et al, "Detection of Carcinogenic Potential in Shale Oil."

Stranger, D.A. , "Socioeconomic I nip uc ts of Oil Shale Develupirietit in the Eastern United States; Applying Lessons Learned from the West."

Rob!, T., et al, "Elemental Release Characteristics of Eastern Oil Shale Materials: Comparison of Laboratory and Field Results."

Barnhiscl, R.I., "Reclamation Research Results from the hope Creek Eastern Oil Shale Field Station."

Kalkreuth, W., et a!, 'The Organic Petrology and Geochemistry of Car- boniferous Oil Shales from Eastern Canada."

[lower, J.C., et al, "Petrology and Geochemistry of the Breckinridge Seam-A Torbinite from Western Kentucky."

Taulbee, D.N. , et al, "Kentucky Oil Shale Kerogen Studies: Part II Ecrogen Pyrolysis in the Presence of Various Inorganic Matrices."

Dyne, J.R., et a!, "Geochemical and Uydroretorting Analysis of Selected World Oil Shales."

Coburn, T.T., eta!, "Analytical Support for Application of the LLNL Retort Model to Devonian Shale."

Leininger, ILK,, et al, "A Summary of Data on the Geochemical Reference Sample SDOI."

Frankic, W.T., et al, "hydrocarbon Production from the Devonian Shale in Letcher, Knott, and Floyd Counties, Eastern Kentucky."

Ettensohn, F.R., "Tectonic Control of Interbasinal Relationships Between Devonian Black Shales in the Illinois and Appalachian Basins of Kentucky."

Conkin, J.E. , et al, "Disconformities and Weathered Pyroclastics: Tools for Determining Age Relationships of the Devonian Black Oil Shales of East- - ern North America."

Barron, L . S . , et a!, "A Determination of Oil Shale Resources Along the Central Kentucky Outcrop Belt from Bullitt to Estill County."

OIL SHALE - PATENTS

"Oil Shale Retorting Process", Ardis L. Anderson, James R. McConaghy, Jr. - Inven- tors, 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.

"Method and Catalyst for Removing Contaminants From flydrocarbonaceous Fluids Using a Copper-Group Via Metal-Alumina Catalyst", N. Le Quang, Daniel J. Neuman, Stephen M. Olcck - Inventors, Mobil Corp., United States Patent 4,601,998, July, 22, 1986. There is provided a method and catalyst for removing catalyst poisoning impurities or contaminants such as arsenic, iron and nickel from hydrocarbonaceous fluids, par- ticularly shale oil and fractions thereof. More particularly there is provided a

2-39 SYNTHETIC FUELS REPORT, DECEMBER 1986 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 desulfurizotion, denitrogenation, catalytic hydrogenation, etc.

"Process for Oil Shale Retorting Using Gravity-Driven Solids Flow and Solid-Solid Heat Exchange", Robert L. Braun, Arthur E. Lewis, Richard C. Mallon, Otis R. Walton - Inventors, U.S. 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 en- ters at the middle of a retort column into a mixer stage where it is rapidly mixed with hot recycled shale and thereby heated to pyrolysis temperature. The heated mix- ture 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.

"Process for Treating Waxy Shale Oils", Timothy L. Carlson, 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 con- taining a crystalline aluminosilicate zeolite of the ZSM-5 type and a porous refrac- tory 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,

"Apparatus for Aboveground Separation, Vaporization and Recovery of Oil from Oil Shale". Ray C. Edwards - Inventor, Edwards Engineering Group, 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 lo- cated 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 as- sociated with the separating device from maintaining a predetermined operating pres- sure in the preheat and waste heat recovery zones to prevent separated hydrocarbon vapors from leaking to the atmosphere.

"Retorting Process with Contaminant Removal", Arlo J. Moffat, James Scioto - Inven- tors, 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,

"Static Mixer Retorting of Oil Shale", John M. Forgot, Jay C. Knepper, Earl D. York, - Inventors, United States Patent 4,597,852, July 1, 1986. Oil shale is well mixed and efficiently, effectively, and economically retorted in a special gravity flow retorting process and system which utilizes novel arrangements of internal baffles in a static mixer.

"Two-Level, Horizontal Free Face Mining System for In Situ Oil Shale Retorts", Chang Y. Cha, Thomas E. Ricketts - Inventors, Occidental Oil Shale Inc., United States Patent 4,611,856, September 16, 1986. A subterranean formation containing oil shale is prepared for in situ retorting by forming a fragmented permeable mass of formation particles containing oil shale in an in situ retort site. The retort is formed by excavating a lower level drift adjacent a lower portion of the retort site and ex- cavating an upper level void adjacent an upper portion of the retort site. An under-

2-40 SYNTHETIC FUELS REPORT, DECEMBER 1986

cut is excavated below a zone of unfragmented formation remaining within the retort site above the lower level drift. The undercut can be free of roof-supporting pil- lars. Explosive is loaded in the zone of formation from access provided by the upper void, and the zone of formation is blasted downwardly toward the undercut for forming the fragmented mass. The volume of the void space within the undercut prior to ex- plosive expansion is similar to the void volume within the principal portion of the fragmented mass being formed. The zone of formation is blasted downwardly in lifts, with each lift being blasted toward a void space larger than a limited void, except for the last lift, which can be blasted toward a limited void. Blasting designs are also disclosed for providing reasonably uniform void fraction distribution in the fragmented mass.

2-41 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS

COMMERCIAL PROJECTS

AMERICAN SYN-CRU DE/IN DIANA PROJECT - American Syn-Crude Corporation and Stone & Webster Engineering (5-5) 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 (T3S, R96W, 6PM) (5-10) 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 1971. 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. In June 1986 Cathedral Bluffs began discussions with the Department of Interior for the purpose of obtaining a lease suspension. Three headfrarnes—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. A new monitoring plan is part of the lease suspension request. 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) (S-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 fled (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. Chevron is continuing to develop its Colorado River water rights through its participation in a joint venture with two other energy companies.

Project Cost: Semi-Works - Estimated at $130 million

2-42 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

COLONY SHALE OIL PROJECT - Exxon Company USA (TSS, R95W, 6PM) (S-30) Proposed 47,000 barrels per day project on Colony Dow West property near Parachute, Colorado. Underground room-and-pillar mining and Tosco 11 retorting was originally planned. Production would be 66,000 TPD of 35 GPT shale from a 60-foot horizon in the Mahogany zone. Development suspended 10/4/74. Draft EIS covering plant, 196- mile pipeline to Lisbon, Utah, and minor land exchanges released 12/17/75. Final EIS has been issued. EPA issued conditional PSD permit 7/11/79. Land exchange consummated 2/1/80. On August 1, 1980, Exxon acquired ARCO's 60 percent interest in project for up to $400 million. Preferred pipeline destination 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 environ- mental 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 - SO 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 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 tour 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 feedstock. Two 41,000 barrels per day upgrading plants were incorporated into the project design.

2-43 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 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 $US4 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 $US9 per barrel represents corporation taxes and royalty. Capital costs were estimated to an accuracy of +1- 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 SI'P, 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) ED WARDS ENGINEERING - Edwards Engineering Corporation (5-33) At the present time Edwards Engineering Corporation is in the process of designing and building at their manufacturing plant in New Jersey a portable oil shale retort that will produce between 1,000 and 2,000 barrels of shale oil per day. The completed unit can be easily trucked to any suitable location. The design of the plant is based on engineering data obtained over the past 6 years from a pilot plant oil shale retort constructed at the Edwards plant in New Jersey. The production unit is being built to process typical oil shale as found in Utah, Colorado, or Wyoming. The portable unit has a low capital cost, and will produce a quality product with an API gravity between 26 to 28, having a pour point between 350 and 550?. The system will not produce any air or ground . The system includes a heat recovery arrangement resulting in very low energy costs per barrel of oil produced. At least 80 percent of the energy for retorting is recycled, no water is required. The portable retort system should operate profitably at present oil prices. The system can be readily scaled upward from the 1,000 to 2,000 barrels per day to any conceivable capacity desired. Patents have been granted and additional patents are pending. Edwards is willing to discuss the licensing of the process with anyone having a serious qualified interest Edwards is a proven manufacturer of heat transfer equipment. The company is in its 40th year of operation and provided many hundreds of millions of dollars worth of proven proprietary heat transfer equipment. 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 Piceance 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 9,600 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 (JP-4) to the Air Force over a four year period.

2-44 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 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 (5-38) The majority of Baltic oil shale () found in 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 l{ivitcr 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 lW/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, Oravo Corporation, and Southern Pacific Petroleum (5-36) 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 Dravo 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.

2-45 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 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 currently evaluating development plans for its shale property located on 10,000 acres five miles north of Parachute. The project is planned to have initial production of 10,000 to 25,000 barrels per day with an incremental buildup to 100,000 barrels per day. 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..

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 Timandit, Tangier, and Tarfaya from which the name T 3 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 T3 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 T 3 process developed jointly by Science Applications, Inc., and the Office National de Recherche at d'Exploitation Petrolieres (ONAREP) of Morocco. The T 3 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 GPT 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 (T6S, R98W, 6PM) (S-60) 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 Defleque, 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.

2-46 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 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 day 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 110,000 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. Plant start-ups have resulted in 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 fro:n 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! "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 Kaiser Engineers, Inc.; The Signal Companies; Texas Eastern Synfuels, Inc. (T9S, R25E, Sec. 32, SLM) (5-80) 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 SEC'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 SEC, construction on the project could possibly get underway in 1986 with production beginning in 1988-1989. In November 1985, the SEC 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 SEC on December 19, 1985 before any assistance could be awarded to the project. Project Cost: Not available

2-47 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continued)

PGTROSIX -- Petrobras (Petroleo Brasileiro, S.A.) (S-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 'nodule, is being constructed and will produce 2,950 barrels per day of oil, 40 tons per day of LPO, and 60 tons per day of sulfur in the beginning of 1988.

Project Installed Costs: $68.4 (US) Million

RAMEX OIL SHALE GASIFICATION PROCESS—liamex 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 . 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-100) 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 24,190 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 or the five years suspension period expires. 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 May 1985 and June 1986 in accordance with plans 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.

2-48 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

RUNDLE PROJECT -- Central Pacific Minerals/Southern Pacific Petroleum (50 percent) and Esso Exploration and Production Australia (50 percent) (S-ho) The Rundle Oil Shale deposit is located near 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. S 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 SPP/CPM'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 (T9S, R2IE, 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

2-49 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (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 (S-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

GELSENKIRCI-IEN-SCFIOLVEN CYCLONE RETORT PROJECT-- Veba Del Entwicklungs-Gescllschaft mbfl (S-165) Veba is developing a cyclone retorting process. They are building a pilot plant at Gelsenkirchen-Seholven. This program is subsidized bj 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 6500 to 700°C. Hydrocarbons remaining in the spent shale are burned in a fluidized bed at soo° 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

GEOKINE'rlCS, INC. — (see Seep Ridge)

JAPANESE RETORTING PROCESSES -- Japan Oil Shale Engineering Company, Ltd. (JOSECO) (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 !. 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 day. 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 fro:n 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

2-50 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (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 $US 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 has been completed. 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 recent collapse of oil prices led to the postponement of the demo plant for oil. In the meantime, PAMA has concentrated on development of a new process, based on use of entrained bed, which is more suitable to Israeli oil shales. The relevant studies are being carried out primarily in a small pilot plant which began operation in November 1985. There is, however, a promising potential for oil shale-based generation of power. PAMA's studies have shown that electricity from oil shale is competitive with electricity produced in large coal-fired utility plants located along the shore and not employing FaD. Accordingly, PAMA has embarked on a demonstration power project. The boiler will deliver 50 tons per hour of steam at high pressure. Low-pressure steam will be sold to process application in a chemical plant, and electricity produced in a back-pressure turbine will be sold to the grid. The project is in its final design stage. Commissioning is expected in 22 months.

Project Cost: Not disclosed

JULIA CREEK PROJECT - CSR LIMITED (S-iSO) 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 twine. 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

2-51 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

NAVAL OIL SHALE RESERVE (NOSR) DEVELOPMENT -- United States Department of Energy (S-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 Garfield 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-1. NOSR-2 is an oil shale 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 Rifle, 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 Development (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. Life tests of some catalysts containing molybdenum and promoting metals showed that steady 94 percent denitrogenation can be attained for 2,000 hours. Optimum reaction conditions of the above process, properties of products were also sought and gained. 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. (5-215) 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.

2-52 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continued)

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 occurin 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

YUGOSLAVIA INCLINED MODIFIED IN SITU RETORT -- United Nations (5-230) 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 (lMlS) 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 1 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.

2-53 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

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 UNOP support. Establishment of the IMIS experiment is expected in 1988.

Project Cost: See above

COMPLETED AND SUSPENDED PROJECTS

Project Sponsors Last Appearance in SFR

DX 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. Foster Wheeler Corporation Davy McKee Magic Circle Energy Corporation Direct Gasification Tests Tosco Corporation September 1978; page B-4 Exxon Colorado 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 S-3 Nahcolite Mine #1 Multi-Mineral Corporation September 1982; page 2-40 Oil Shale Gasification Institute of Gas Technology; December 1978; page 8-3 American Gas Association Paraho Oil Shale Full Size Paraho Development Corporation December 1979; page 2-35 Module Program Silmon Smith Kellogg Corporation March 1985, 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 Mecco, Inc. September 1978; page B-3 Unnamed Fracture Test Talley Energy Systems September 1978; page 8-4 White River Shale Project Phillips Petroleum Company March 1985; page 2-72 Company (Ohio) Sun Oil Company

2-54 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SHALE PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

American Syn-Crude Corporation American Syn-Crude/Indiana Project 2-42

Amoco Coporation Rio Blanco Oil Shale Project (C-a) 2-48

Beloba Pty. Ltd. Yaamba Project 2-53

Cathedral Bluffs Shale Oil Company Cathedral Bluffs Project (C-b) 2-42

Central Oil Shale Pty. Ltd. Yaamba Project 2-53

Central Pacific Minerals Condor Project 2-43 Means Oil Shale Project 2-45 Rundle Project 2-49 Yaamba Project 2-53

Chevron Shale Oil Company Chevron Clear Creek Project 2-42

Cleveland-Cliffs Iron Company Pacific Project 2-46

Conoco Inc. Chevron Clear Creek Project 2-42

CSR Limited Julia Creek Project 2-51

Dravo Corporation Means Oil Shale Project 2-45

Duo-Ex (Solv-Ex Corporation) Duo-Ex Solvent Extraction Pilot Project 2-50

Edwards Engineering Company Edwards Engineering 2-44

Esso Australia Ltd. Rundle Project 2-49

Exxon Company USA Colony Shale Oil Project 2-43

Exxon Research and Engineering Baytown Pilot Plant 2-49

Gary Refining Company Gary Refinery 2-44

Geokinetics, Inc. Seep Ridge (Wolf Den and Agency Draw Projects) 2-50

Japanese Ministry of International RAPAD Shale Oil Upgrading Project 2-52 Trade and Industry

Japan Oil Shale Engineering Company Japanese Retorting Processes 2-50 (JOSECO)

Mobil Oil Corporation Mobil Parachute Oil Shale Project 2-46

Occidental Oil Shale, Inc. Cathedral Bluffs Project (C-b) 2-42

Office National de Recherche et Morocco Oil Shale Project 2-46 d'Exploitation Petrolieres (ON A RE P)

PAMA Inc. Israeli Retorting Development 2-51

Paraho Development Corporation Paraho-Ute Shale Oil Facility 2-47

Peabody Australia Pty. Ltd. Yaamba Project 2-53

Petrobras Petrosix 2-48

2-55 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Ramex Synfuels International Ramex Oil Shale Gasification Process 2-48 Raymond Kaiser Engineers, Inc. Paraho-Ute Shale Oil Facility 2-47 Rio Blanco Oil Shale Company Rio Blanco Oil Shale Project (C-a) 2-48 Science Applications, Inc. Morocco Oil Shale Project 2-46 Signal Companies, The Paraho-Ute Shale Oil Facility 2-47 Solv-Ex Corporation Duo-Ex Solvent Extraction Pilot Project 2-50 Southern Pacific Petroleum Condor Project 2-43 Means Oil Shale Project 2-45 Rundle Project 2-49 Yaamba Project 2-53 Standard Oil Company (Indiana) Rio Blanco Oil Shale Project (C-a) 2-48 Standard Oil Company (Ohio) Pacific Project 2-46 Stone & Webster Engineering American Syn-Crude/Indiana Project 2-42 Pacific Project 2-46 Tenneco Cathedral Bluffs Project (C-b) 2-42 Texas Eastern Synfuels, Inc. Paraho-Ute Shale Oil Facility 2-47 Tosco Corporation Tosco Sand Wash Project 2-49 Triad Research Inc. Triad Donor Solvent Project 2-52 Union Oil Company of California Parachute Creek Shale Oil Program 2-47 Union of Soviet Socialists Republics F{iviter Process 2-45 U.S. Department of Defense Naval Oil Shale Reserve Development 2-52 U.S. Department of Energy Duo-Ex Solvent Extraction Pilot Project 2-50 Naval Oil Shale Reserve Development 2-52 United Nations Yugoslvania Inclined Modified In Situ Retort 2-53 Veba del Ent wicklungs-Gescllschaft Gelsenkirchen-Scholven Cyclone Retort Project 2-50 Yaamba Joint Venture Yaamba Project 2-53

2-56 SYNTHETIC FUELS REPORT, DECEMBER 1986

PROJECT ACTIVITIES

PANCANADIAN FROG LAKE PROJECT DETAILED As reported in the Pace Synthetic Fuels Report, FIGURE I September 1986, page 3-4, PanCnnnclion Petroleum Ltd applied early this year for approval of Phase I •1 • LINDBE R GH I of a proposed three phase commercial bitumen recovery project in the Cold Lake Deposit. The F ROG LAKE OIL S A N DS P R O JECT company announced later that it was reducing its capital budget by 50 percent, and would be delay- ing the project schedule. Details of the original plans are given in the decision of the Alberta Energy Resources Conservation Board. The project location is shown in Figure 1. ••nnuuu•••nt •Ufl•UUU•UU••U•I••••••uuu•suuni The details of the application include •n•nuuu•n•ni The production of an average of 500 cubic •n•u•••••n•nnui meters per day of bitumen over the 20-year •.nw•nn•••••nuu project life with a peak production of 700 \palll\ cubic meters per day. Rd•UU•b^SS a•sui SEE •••••t MEME All bitumen production from Phase I would be ___14R•UUUSM•tk ••••••• trucked to an existing CPP where it will be .nsnn.nnin••MEN • mixed with condensate to form a pipelineable product. This mixture would be pumped nnuunu MEN io••••• through pipeline to the Husky Lloydminster nflfl.nIuhun lateral to the east. nnnniuuuu•u••u IN No Cyclic steam stimulation of the Cummings ED PROPOSED THERMAL DEVELOPMENT REA Formation in sections 3-56-BW4M and 7-55- 5W4M. Incremental bitumen recovery using PROPOSED 16ho PRIMARY DEVELOPMENT cyclic steam stimulation is estimated to be 12 per cent of the original bitumen in place (091 P). Primary recovery for the project area is es- timated to be three percent of the crude bitumen in place for the 16-hectare well spac- ing. A produced water recycle system is not proposed as part of the Phase 1 development. Phase 1 includes the existing 113 wells and an Water disposal would be handled by two exist- additional 165 wells to be drilled over the next ing disposal wells by injection into the Lloyd- 20 years. minster and/or Beaverhill Lake Formations. Directional wells would be drilled from pads (12 The Board expressed concern with the relatively wells per pad and 4 previously drilled vertical low recovery, estimated at 15 per cent of the wells) for each quarter section approved for OBIP, for the initial thermal recovery process. cyclic steam stimulation, according to an in- However, the Board also noted Pan Canadian's plans verted 7-spot pattern on a 4-hectare well spac- to follow-up the cyclic steam stimulation process ing. with a steamflood or fireflood process which is ex- pected to increase the bitumen recovery to ap- Forecasts show that for Phase I development proximately 25 percent of the OBIP. the water demand will increase from about 200 cubic meters per day in 1986 to a Capital expenditures for Phase 1 are estimated to of 1,200 cubic meters per day in 1996. If be $91 million (1985 dollars), not including invest- Phases 2 and 3 of the project were to proceed ments prior to 1985. Project operating costs are at a later date, a peak demand of 9,600 cubic predicted to average approximately $26 million per meters per day would be required. At present, year, resulting in an estimated total of $668 mil- PanCanadian receives fresh water supply via lion over the project life. Westmin Resources' river intake facility and pipeline from the North Saskatchewan River.

3-1 SYNTHETIC FUELS REPORT, DECEMBER 1986

Development Schedule AOSTRA recently acquired a new $1.7 million un- derground horizontal oil drilling rig for use in the A modified schedule from that proposed in the UTF. The rig was scheduled to undergo above- original application was put forward by Pan- ground testing near Exshaw, Alberta until November Canadian in order to clarify the timing of 1986, at which time it was to be moved to the development plans for some of the lands in the Underground Test Facility. At the UTF site, the project area. The following schedule is an es- rig will be placed about 15 meters below the base timate of the timing for the development of the of the oil sands. It will operate from horizontal areas to be subjected to the cyclic steaming tunnels four meters high by five meters wide and process. can drill up to 1,000 meters of horizontal hole. It is powered by a combination electric/hydraulic sys- Schedule Pad to be Developed te m. 1990 NWI/4 3-56-6W4M 1993 NEI/4 3-56-OW4M 1995 SEI/4 3-56-6W4M 1997 NWI/4 7-55-5 W4M 1999 NEI/4 7-55-SW4M SHELL DEDICATES PEACE RIVER EXPANSION 2001 SEI/4 7-55-5W4M PROJECT 2003 SW I/4 7-55-5W4 M In early October Shell Canada Limited officially The development schedule shown in the original ap- dedicated its Peace River Expansion Project. The plication also included the drilling of primary wells project location is showti in Figure 1. on 16-heetare well spacing. No official revision has been made to this schedule, however, the Board noted that this development has been delayed for at least one year as well. FIGURE 1 The Board notes that the proposed development schedule has slipped in general terms from that proposed in the original application. Therefore the PEACE RIVER EXPANSION PROJECT Board proposes to introduce a lapse time for reasonable progress of the Phase 1 activities. The Board considers a lapse period of about 3 years •7_ g': from the date of the approval suitable for that i' purpose, after which approval of the commercial scheme would be cancelled if project construction had not commenced or the operator had not __ received approval to extend the date based on cir- • S i•n•u I..... - cumstances existing at that time. us-In. - • ii .1UI...0 - •W• ,.A MENNEN iIr N I AOSTRA GETS UNDERGROUND DRILL RIG rAt I Alberta Oil Sands Technology and Research Authority (AOSTRA) is developing an Underground Test Facility (UTF) at a site 45 km northwest of Fort McMurray, Alberta. After nine years of study With ten billion cubic meters of bitumen in place, by AOSTRA and others, the economic feasibility of the Peace River deposit is the third largest of emplacing horizontal wells at the base of the oil Alberta's oil sands deposits. The deposit is found sands reservoir will finally be determined by in- at 400 to 500 meters below the surface. A reservoir testing. favorable feature of this deposit is a water saturated zone in the bottom few meters of the The UTF is designed to test thermal processes by reservoir. This zone of high water saturation using horizontal wells to heat and drain the reser- makes it possible to inject hot water or steam into voir. The testing program will include the design, the reservoir at much less than the fracture pres- construction, and operation of new horizontal well sure. drilling equipment, completion hardware, and production systems. These have been designed to To alternately heat and drain the bitumen from the achieve maximum recovery of bitumen from the overlying sands, the pressure of the steam in the reservoir using gravity drainage mechanisms in an lower sands is raised and lowered in a cyclic man- underground environment. ner.

3-2 SYNTHETIC FUELS REPORT, DECEMBER 1986 Shell has already demonstrated that with the pany. The remission will apply to $36 million of "Pressure Cycle Steam Drive", in excess of 33% of PGRT payable on Husky revenue from production the oil-in-place can be extracted. Over 50% ul- on or after April 1, 1985. The remission order timate recovery is expected. That Is an unusually also ensures that the PGRT relief is not treated as high percentage for such an extra heavy material. assistance and, therefore, does not affect the As a result, the pilot project called the Peace company's federal income tax liabilities. River in Situ Project (PRISP) project was expanded to a 10,000 barrel per day commercial project. The governments of Canada.i Alberta and Saskat- The expansion involves an investment of US$200 chewan, and Husky had prev ously entered into a million, Memorandum of Understanding, signed on June 6, 1984, to advance the Husky Upgrader Project. Un- The expansion, began last year, finished ahead of der the April 8, 1986 agreement, each of the schedule and under the initial budget. In total, the parties will decide whether, and on what basis, to company drilled 213 wells, all completed four participate further in the project after the comple- months ahead of schedule. In October, the com- tion of the pre-construction engineering work, ex- pany began steam injection, and the first sales pected in the spring of 1987. were anticipated by the end of 1986. With 250 Husky and consulting engineering person- The 1986 fall in oil prices, which stopped many nel currently at work, engineering is well along and EOIt expansions, had no effect on the Peace River progressing as expected, according to Husky. project because much of the capital costs, including C$60 million for drilling, had already been sunk. Earlier in the year the Alberta government indi- But phases two and three of the project to expand cated it was considering funding most of the production to 30,000 barrels per day have been put project by itself to keep it going, if the federal on hold. Shell continues to do some preliminary government decided to pull out of its commitment work on the expansions, however. to Husky.

Shell Canada holds about 150,000 acres of tar sand Previous delays in reaching a government-backed mineral rights in the Peace River project. This is financial plan already have pushed back startup of an area with gigantic resources and approximately the project to 1990. Husky's initial financing plan 75 billion barrels in place have been delineated so for the upgrader called for the provincial govern- far. ments each to match half of the federal government's promised C$780 million loan In August the Alberta Energy Resources Conserva- guarantee. Husky is to pay 596 of the gross in- tion Board approved an amendment changing the come from royalties to the provincial governments designation "Peace River Sector" to "Cadotte Lake until payout, then royalty payments to the govern- A rca ments would be increased to 30% of the profits.

Husky estimates that oil prices of US$22-24/bbl will be required to make the plant economic in 1990, when it is scheduled to come on stream. GOVERNMENT ASSISTANCE FINALIZED FOR BIPROVINCIAL UPGRADES A recent report by the Alberta Energy Resources Conservation Board says that the project is unlikely It was announced in September that Government of to proceed until the late 1990's unless massive Canada support for the current phase of the government support is provided. Husky's Biprovincial Upgrader Project will be delivered through tax relief to Husky Oil Opera- tions Ltd. ## ## SYNCRUDE MAY DELAY COMPLETION OF On April 8, 1986, the governments of Canada, Al- EXPANSION berta and Saskatchewan agreed to share in the es- timated $90 million cost of completing pit- Syncrude Canada Ltd has said that it may delay construction engineering work related to the for one year the balance of a $750 million expan- proposed $3.2 billion 55,000 barrel/day upgrader sion program at its Fort McMurray, Alta, oil sands project at Lloydminster, Saskatchewan. The project plant. would upgrade heavy crude oil, which is currently exported from Canada, into a higher quality crude The company says it needs loans or loan guarantees oil that can be processed by Canadian refineries. to complete the project because of low oil prices. In addition to the federal support, the governments Synerude has spent about $400 million on the ex- of Alberta and Saskatchewan agreed to provide pansion program that began in 1983 and was to be $13.5 million each toward the pre-construction en- completed in 1988. The project will increase gineering costs. capacity to about 140,000 b/d from 120,000 b/d. Alberta is reviewing Syncrude proposals for finan- The federal government's support will take form of cial aid. a remission order providing relief from Petroleum Syncrude also has asked for assistance from the and Gas Revenue Tax (PGRT) payable by the com- federal government for the expansion program.

3-3 SYNTHETIC FUELS REPORT, DECEMBER 1986 CORPORATIONS

SOLV-EX DETAILS PROCESS DEVELOPMENT phase; a middle water phase; and a lower spent ACTIVITIES sand phase. Each of these phases is thereafter processed to produce product bitumen; recovered In its 1986 Annual Report to the Securities Ex- solvent, which is recycled; clean hot water, which change Commission, Solv-Ex Corporation outlined Is recycled; and damp, clean spent sand for back- the history and status of Its efforts to develop a filling the mine. solvent extraction process for tar sands. The bitumen recovered contains some of the fine On August 30, 1985 Solv-Ex and its joint venture particles contained in the tar sand ore body. partner Enercor submitted an application to the These fines are removed from the bitumen to United States Synthetic Fuels Corporation (SFC) for produce a marketable synthetic crude oil by using financial assistance for their PR Spring Tar Sand one of several alternative fines removal processes Project. This project involved the construction and available by license from other parties. operation of a 4,700 barrel per day plant which would use Solv-Ex's extraction process. In Novem- Tar sand ore samples from Santa Rosa, New ber 1985 the SFC determined that the project ap- Mexico; Sunnyside and PR Spring, Utah; and peared to meet the qualification criteria for finan- Athabasca, Canada have been tested. Pilot plant cial support under the SFC's solicitation. However, runs on a total of 170 tons of PR Spring tar sand in December the Government eliminated the fund- ore were completed in late 1983 and ing for the SFC. February/March 1984. Three pilot plant runs on a total of 70 tons of high grade Athabasca ore were In December of 1985 Solv-Ex temporarily closed its completed in November, 1984, and one pilot plant pilot plant operation and laid off eighteen of its 45 run on ten tons of low grade Athabasca ore was employees. completed in February of 1985. Product bitumen has been subjected to fines removal testing in the Effective March 1, 1986 Solv-Ex entered into laboratory and at pilot plant scale, and south agreements with Shell Canada Limited (Shell removed have been checked for fluidized bed com- Canada) and the Government of Alberta, reopened bustion for the cogeneration of steam and its pilot plant and rehired the laid off employees. electricity. The agreements call for a $10 million (Canadian) feasibility study which, if successful and if As of August 29, 1986 SoIv-Ex had processed economic forecasts for the price of oil in the through the pilot plant approximately 460 tons of 1990% are acceptable, would lead to the construc- tar sand from Shell Canada's lease in Alberta. Ap- tion and operation of a $260 million (Canadian) proximately 700 more tons of ore were scheduled mine and extraction plant on a lease held by Shell to be processed. Canada and which would be designed to produce 7,500 barrels of bitumen per day. Solv-Ex's pilot plant in Albuquerque, New Mexico processes up to 72 tons of tar sands per day and With the development of the extraction process produces up to 25 barrels per day of bitumen, substantially complete, Solv-Ex is currently per- whichever limit occurs first. forming work under its agreement with Shell Canada and marketing its technology in the The Product development of tar sand resources in North America and elsewhere. Solv-Ex currently anticipates that a pipelineable synthetic crude oil which can be used as a refinery Solv-Ex's two subsidiaries, Duo-Ex Corporation feedstock will be the product produced after (Duo-Ex) and Shale Research, Inc. (Shale), have upgrading (fines removal). Alternatively, the been involved in the development of processes to bitumen produced from the extraction process alone extract hydrocarbons from oil shale. During the could be sold to the asphalt market or used as a fiscal year ended June 30, 1986 Shale was inactive coker feedstock. and Duo-Ex was primarily involved in attempting to obtain funding for the further development of its Shell Canada Project oil shale extraction process. The March 1, 1986 agreement with Shell Canada The Solv-Ex tar sand extraction process has been involves test work and a detailed engineering study tested in the laboratory and in a pilot plant. The (Phase I) which, pending successful results and ac- process combines both solvent extraction and hot ceptable economic forecasts, is planned to lead to water treatment of tar sands without air flotation. the construction and operation of a commercially- Crushed tar sand is first conditioned in hot water sized demonstration plant (Phase II). after which any oversize and inert rocks are removed by screening. The bitumen content of the Phase I is currently estimated to cost $10,000,000 resulting tar sand-hot water slurry is then ex- (Canadian) which funds are to be provided by Shell tracted into a water immiscible solvent of low den- Canada and the Alberta Oil Sands Technology and sity to form a solvent-bitumen solution, or extract Research Authority (AOSTRA). SoIv-Ex's 25%

3-4 SYNTHETIC FUELS REPORT, DECEMBER 1986 equity participation in Phase I is being carried by sands to the joint venture. Thus, through its 50% Shell Canada. The carried amount is to bear In- ownership in the joint venture with Enercor, Solv- terest at the Canadian prime rate and if Solv-Ex Ex has a 50% interest in the rights to the tar participates in Phase II, is to be repaid out of 10% sands in the PR Spring area of Utah on a lease of the proceeds the Company receives during Phase area of approximately 27,000 acres. II. Under the terms of the agreements with Exxon and After the conclusion of the pilot plant test work, the PG&E subsidiaries, these two parties have an Shell Canada is to pay Solv-Ex an engineering fee overriding royalty interest of 6.24% of the market for preparing preliminary and final process design value of the tar sands at mine mouth. in addition, packages and for reviewing engineering and cost es- the Federal government has a royalty interest of timate packages. Solv-Ex also has the right to bid 12.5% of mine mouth value. on the contract for preparing the engineering and cost estimate packages. As of June 30, 1986, Legal Proceedings Solv-Ex had recorded revenues of $922,606 under its agreement with Shell Canada. On March 30, 1983, a suit entitled Solv-Ex Cor- poration v. Gilbert Sanchez was filed in Bernalilto If the decision is made to enter into Phase II, County District Court, Albcquerque, New Mexico. which is currently estimated to cost C$260,000,000 SoIv-Ex is to have a 25% working interest in the SoIv-Ex alleges that the defendant fraudulently en- project unless Shell Canada elects to convert SoIv- tered into a personal services contract to develop Ex's interest to a license arrangement by payment further a microbial process for the extraction of of an up-front and running royalty. If Solv-Ex hydrocarbons from oil shale by representing that elects not to participate in Phase II as a working the process was more efficient than it actually is. interest participant, Shell Canada may take over Solv-Ex is seeking to recover expenses, salaries and the 25% participation by paying Solv-Ex the 50,000 shares of common stock which were paid to aforementioned royalties. The government of Al- the defendant under the contract. On May 27, berta has agreed to provide a loan guarantee for 1983, the defendant counterclaimed against Solv-Ex 30% of the Phase II construction costs to a maxi- for continuing consultant fees and for breach of mum of C$85,000,000 plus capitalized interest. contract in the amount of $110,000 and for $100,000 in punitive damages. A trial date has not If Solv-Ex maintains its 25% working interest in been set. Phase II, it is to have the right to a 5% equity participation on any expansion of the project on Shell Canada's lease. Shell Canada and AOSTRA are to receive certain portions of future fees the OHS CORPORATION REPORTS PROGRESS ON Company receives from licensing its technology. PROJECTS Other Leases In its October letter to shareholders, ORS Corpora- tion reported that it continues to improve finan- Solv-Ex is actively pursuing opportunities for use of cially and has settled the majority of its lawsuits its extraction process on other leases in the and is presently working on agreements to settle Athabasca region of Alberta. the remaining lawsuits. Effective October 4, 1983 Solv-Ex and Enercor ORS and its subsidiary, Uentech Corporation, have formed an equally-owned joint venture to which negotiated a new licensing agreement with III Re- Enercor assigned its rights to tar sand mining search Institute covering IITRI's basic patents and leases in the PR Spring area. Solv-Ex is currently know-how on the electromagnetic well stimulation pursuing alternative funding sources to enable it to process. Unlike the license under which (iRS pre- use its extraction process on the leases to produce viously operated, the new license is exclusive asphalt and/or coker feedstock. world-wide. Enereor, Natural Gas Corporation of California and Status reports were given for a number of the Pacific Transmission Supply Company, subsidiaries Company's projects: of Pacific Gas and Electric Company (PG&E), and Exxon Corporation (Exxon) have received approval Coastal Well - Panhandle Field, Texas under the Combined Hydrocarbon Leasing Act of 1981 from the United States Bureau of Land Ten months after the first introduction of Management to convert their existing Federal oil electromagnetic energy in this well, it continues to and gas leases to combined hydrocarbon leases. produce substantially more oil than projected based Enercor has agreements with these corporations on field experience. It is the only well out of al- which provide for the conveyance of the rights to most 400 Coastal wells in the field which has extract tar sands from these leases to Enercor required no treatment to remove . upon the issuance of the combined hydrocarbon Low oil prices and high drilling and completion leases. Under the joint venture agreement with costs have prevented further Installations in this Solv-Ex, Enercor has conveyed its rights to the tar field.

3-5 SYNTHETIC FUELS REPORT, DECEMBER 1986

Husky Farm-In Well - Wlldmcre Field, Alberta 14.4 million barrels and virtually equalled total production for all of 1985. Stimulated production operations continue with very satisfactory results. In the four months of Although there were production disruptions in Sep- electromagnetic heating of this well, stable produc- tember, by mid-October record production rates tion of about 20 barrels per day has been achieved were again being achieved. October production for a production enhancement of about 30096. A averaged 64,800 barrels/day, the best rate in 19 second well will be drilled on this property. It is years of operation. expected that this well will be part of a much larger joint venture currently under negotiation Despite the improved performance, the Oil Sands with another Canadian company. Group recorded a loss in the first nine months of 1986 of $12 million compared to earnings of $32 Tenneco Farm-In - White Wolf Field, California million in the first nine months of 1985. Average crude oil selling prices were 48 percent lower than One well has been drilled and completed in this in the first nine months of 1985. The impact of field. Electromagnetic heating of this well has just lower crude prices was substantially offset by the commenced and no production data are yet avail- record production volumes, 35 percent higher than able. Other wells in this and other California in the first nine months of 1985. Cost reductions fields are being planned. and lower royalty and revenue tax rates also mitigated the effect of lower prices. Brazilian Project with Petrobras As part of restructuring the company's Resources ORS was scheduled to meet with Petrobras in Na- Group it has stopped work on the $1 billion Burnt tal, Brazil in November for a project kick-off Lake project. The first of the four-phase develop- meeting. The first test operations should start ment, costing $114 million, was slated for comple- about the first of the year and will run four tion this fall. The overall project was to be months. A successful initial test will be followed finished in 1991. Burnt Lake is an in situ steam by a ten-well pilot. Petrobras states that the total recovery project located in the Primrose area, number of potential installations under their present similar to the company's Fort Kent operation. The development plans is about 700 in three fields. operation has a potential of 25,000 barrels per day. The budget for the Resource Group, which controls Tuba Test Facility the heavy oil projects, was slashed to $70 million from $200 million early this year. Development and testing work continues at the ORS Tulsa site. Field tests are scheduled to start Both Oil Sands and Suncor announced staff cutbacks within 30 days on a version of the electromagnetic through layoffs, attrition and early retirement. process that can be installed in old wells. This in- stallation work will be done in concert with HT Alberta Energy Company, Canadian Hunter Explora- Research Institute and should be concluded by tion Ltd. and Pangaea Petroleum Ltd. are partners year's end. with Suncor Inc. in the Burnt Lake project.

SHELL CANADA NOTES DROP IN EARNINGS SUNCOR SEES LOSS IN OIL SANDS, SHELVES BURNT LAKE Shell Canada Limited's consolidated earnings for the first nine months of 1986 were $74 million or 56 cents per share compared with $88 million or 68 Suncor Inc. reported that earings from operations cents a share for the corresponding period in 1985. for the first nine months of 1986 were $1 million, Third-quarter earnings were $16 million after a compared to $27 million for the same period last write-off of $27 million resulting from the suspen- year. However, improved productivity at the oil sion of the East Coast offshore exploration sands plant and better margins in the downstream program. business were among the positive factors helping Suneor record a third quarter operating profit of $2 million. Cash from operations for the nine months was $445 million, up from the $400 million reported in 1985 because the increase in Oil Products cash flow The Oil Sands Group maintained good production more than offset the decrease in Resources cash rates during the third quarter, despite equipment flow. Total capital and exploration expenditures and power disruptions and a lockout/strike of plant were $367 million or 24 percent higher than 1985 employees. Daily production during the third due to increased outlays in both Resources and Oil quarter (48,800 barrels), was an increase of nine Products. Resources capital and exploration expen- percent over the same period last year. In July ditures increased to $299 million from $241 million the plant achieved its second best month ever, with in 1985 as a result of more development drilling, average daily production of 60,900 barrels. Produc- frontier exploration and the Peace River in situ oil tion for the first nine months of 1986 was a record sands expansion project.

3-6 SYNTHETIC FUELS REPORT, DECEMBER 1986 The nine-month results were encouraging in view of in the corresponding period last year. However, the current depressed oil price environment and earnings from continuing operations for the first considering the large write-off absorbed with nine months of 1986 were $108 million, compared respect to the East Coast program. with $249 million for the corresponding period of 1985. The 1986 earnings include gains on the sale Shell's nine-month report notes that it is continuing of certain resource properties. Partially offsetting to review the scope of its operations in view of these items was the write-off of the conical drill- depressed world energy prices. It is the ing unit Kuliuk totalling $52 million. Corporation's planning assumption that oil and will remain volatile and generally The 1986 results also include $228 million from depressed for the remainder of this decade. The discontinued operations (including gains of $212 mil- Corporation is adjusting to this by reducing expen- lion on downstream asset sales). diture and staffing levels. OH and gas operating earnings for the first nine According to Shell, elimination on October 1 of the months of 1986 were $101 million, a decrease of federal government's Petroleum and Gas Revenue $66 million from the first nine months of 1985. Taxes (POST) represents a welcome start at The major factor contributing to the decline was rebuilding investment capability in Canada's oil in- lower crude oil prices reflecting the over-supply of dustry. oil on world markets. Other factors were lower crude oil and natural gas production volumes, It provides a first step toward halting the invest- mainly reflecting reduced demand. ment downslide precipitated by sharply lower inter- national crude oil prices. The 10 percent PGRT, Partially offsetting these items were lower originally scheduled to be phased out by the federal Petroleum and Gas Reveune Taxes due to the lower government in 1988, amounted to $50 million for revenues and the rate reductions in January 1986. Shell Canada in the first nine months of this year. This tax was eliminated October 1, 1986. In 1985, Shell paid $123 million in PGRT at a 12 percent rate. Net production of crude oil and natural gas liquids, including synthetic crude oil, was 74,945 barrels per Peace River Expansion Opened day, a decline of 13 percent from the first nine months of 1985. The initial expansion of the Peace River complex in northern Alberta was officially opened in special During the third quarder, improved demand and ceremonies in early October. reduced pipeline constraints combined to increase the volume of crude oil shipped from Alberta. Expansion of Shell's in situ oil sands project began However, there is still substantial shut-in oil in the in 1985 and was completed on schedule by mid- province, and Gulf's gross production of liquid September and under budget. Construction involved hydrocarbons, including Syncrude production, was a new processing plant and associated facilities and still down 10 percent from the third quarter of the drilling of more than 200 wells. Commissioning 1985. in September was followed by first steam injected into the reservoir. The expansion increases Peace River's production capability to 1,600 cubic meters of bitumen a day. FIGURE 1 NEW GULF CANADA RE-STRUCTURED GULP CANADA SHOWS ORGANIZATION STRUCTURE CHANGES IN EARNINGS

Gulf Canada Corporation is now a company with a significant presence in five major businesses -- oil and gas, natural gas distribution, pipelines, forest ______I I products, and distilled spirits. Figure 1 shows the ;21% current arrangement. Guucanada — The executive offices of Gulf Canada Corporation have been established in Toronto with Marshall A. Gu Cohen as Chairman and Chief Executive Officer. 'tarn Wafica,. lade persincl S. K. McWalter is President and Chief Executive Goathv,, & wn Pipe U'e — Officer of Gulf Canada Resources, which has head- 0' quarters in Calgary. 49% 41%

Earnings for the nine months ended September 30, 1986 were $264 million, compared with $245 million

3-7 SYNTHETIC FUELS REPORT, DECEMBER 1986 Gulf's share of Syncrude production for the quarter High Bitumen Recovery averaged 13,015 barrels per day, 33 percent more than the same period a year ago. Also, a new The Sieve achieves high bitumen recovery from maintenance procedure involving Syncrude's coking mined oil sands. Oleophilic Sieve bitumen units has produced encouraging results in extending recoveries and Hot Water Process recoveries from coker runs, and holds potential for increasing an- mined oil sands are compared in Table 1. The nual production. Sieve recovers much more bitumen from a tonne of mined oil sand than the Hot Water Process, par- ticularly with low grade ores. Other Advantages

OLEOPHILIC SIEVE SEEKS INTEREST IN PUBLIC In commercial Clark Hot Water separation, heat OFFERING requirements correspond to almost 10% of the produced bitumen. The Oleophilic Sieve requires Oleophilic Sieve Development of Canada Ltd is less than half as much energy. Slurry is prepared seeking expressions of interest for a public stock at a colder temperature and bitumen extraction offering to finance further development of its from the slurry is done at an even lower tempera- process. ture. The Oleophilic Sieve Process was first tested in Caustic soda is needed in the Hot Water Process to 1975 at the Alberta Research Council and then was disengage bitumen from the sand grains and cause turned over to the private sector for development. it to float. The Oleophilic Sieve does not require The process has a large number of applications that such chemical help to separate most oil sands or range from mined tar sand extraction to gold tar sands. Fine clay mineral particles of the tail- recovery from river sands. Several of these ap- ings compact more readily in tailings ponds when plications have proven successful in pilot plants caustic soda is not used. with capacities up to 40 tonnes per day. A large prototype separator, designed for separation rates Bitumen product from the Oleophilic Sieve is a up to 1,000 tonnes per day, is now under construc- free flowing warm oil that has been successfully tion. It is intended for field testing and for design processed with dilution centrifuges and upgraded to studies to construct commercial separators, each synthetic crude oil in a commercial plant. having capacities exceeding 20,000 tonnes per day. It is estimated that a production cost of US$10.00 Operation of the Separator (1986) per barrel of synthetic crude oil will be a reasonable target for mined-oil-sands plants using Operation of the Oleophilic Sieve separator is il- this process. Development funding, exceeding lustrated in Figure 1. The mixture to be separated several million dollars thus far, has mainly been is fed into the central inlet of a rotating separa- with loans repayable from royalty income after the tion drum which distributes the mixture over the process has been commercialized. full length of the drum interior. An Oleophilie The Oleophilic Sieve Process takes a unique ap- proach to oil sand separation. It does not require density differences to recover bitumen from sand and water but makes use of the affinity of bitumen for an "oil-loving' sieve. A slurry or mined oil sand is dropped onto an Oleophilic Sieve conveyor. Sand and water pass through the Sieve apertures but bitumen is captured and conveyed by the Sieve to a recovery unit where globules of bitumen are squeezed from the Sieve. Major improvements in design have been made recently to make this process a good candidate for commercial bitumen recovery. Figure 1 is a schematic drawing of the new separator design. The larger separator under construction uses a 1.3 meter wide Oleophilic Sieve conveyor belt wrapped around a 2 meter diameter drum. Commercial separators will use 3 meter diameter or larger drums and up to 10 meter wide sieves.

3-8 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1

COMPARATIVE BITUMEN RECOVERIES

8% 10% 11% 12% Mined Oil Sand Containing By Weight: Bitumen Bitumen Bitumen Bitumen

Recovered by the Hot Water Process 62% 83% 90% 93% Recovered by the Oleophilic Sieve 90% 96% 98% 98%

Sieve conveyor belt is mounted around the aper- Oversized rocks, clay lumps and gravel are rejected tured outer wall of the drum and around four at several stages of the process. The slurry is fed heated rollers. to the first separator to yield a stage 1 bitumen product. The tailings are discarded. The drum is like a rotating grizzly. It is partly filled with oleophilic balls that tumble with and Stage 1 bitumen product is blended with cold water capture bitumen from the separating mixture. and is washed in a second separator to remove After the bitumen is removed, the sand and water residual minerals. Stage 2 bitumen is a suitable pass out of the drum through the sieve into a tail- product for bitumen treatment and upgrading. The ings sump. Water and small amounts of bitumen tailings from stage 2 are recycled to the inlet of floating on the sump are recycled. The tailings stage 1 where they dilute the incoming slurry. are discarded. Bitumen from Tailings Bitumen collects in the voids between the balls and extrudes to the sieve at the left of center. The A large percentage of the total bitumen discarded layer of bitumen thus moved to the sieve can be by the current plants can be recovered if the ex- very thick. This relatively cold bitumen is con- traction tailings are processed by the Oleophilic veyed away from the separation drum past steam Sieve before flowing into the ponds. heated rollers in an enclosed recovery zone. Like butter on a hot knife the bitumen sloughs off the Pilot plant tests with the Oleophilic Sieve for hot sieve before the sieve cools and revolves back recovering bitumen from extraction tailings of the to the separation drum. Hot Water Process have been successful. Using the Sieve for processing tailings from existing mined oil Mined Oil Sands sands plants can provide a major improvement in total commercial plant bitumen recovery, as is il- A simplified flow diagram for separating mined oil lustrated in Table 2. sands by the Sieve is illustrated in Figure 2. Mined oil sand and limited amounts of warm water The economic merits of recovering bitumen from or steam are blended in a preparation drum to tailings by the Oleophilic Sieve are shown in Table make a free flowing slurry for separation by the 3. Sieve. Pilot plant slurries prepared at 30 0 to 800C have separated without any problem. A total of 29,000 barrels of bitumen are discarded into ponds each day with the tailings from the cur- rent Alberta mined-oil-sands plants. Of this, it is estimated that more than 20,000 barrels could be FIGURE 2 recovered daily by commercial Oleophilic Sieve tail- ings processors. PROCESS FOR EXTRACTING Other Prospects MINED OIL SAND The Sieve may have other applications. In addition to oil sand separation, sludge and tailings process- ing, and froth dewatering, it has been used to separate emulsions that were produced by steam in- jection from an oil sand deposit. It may be ap- plied to the clean up of heavy oil or tar sludges, and it can be developed to remove sand and silt from the products of heavy oil wells. The Sieve can also be applied to the recovery of minerals from mined ores and from river sands. Tests conducted with gold bearing sand have been

3-9 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 2

BITUMEN RECOVERY BENEFITS FROM PROCESSING TAILINGS BY THE OLEOPIIILIC SIEVE

8% 10% 11% 12% Mined Oil Sand Containing By Weight: Bitumen Bitumen Bitumen Bitumen

Initially Recovered by the Hot Water Process 62% 83% 90% 93%

Additionally Recovered from the Tailings 26% 12% 7% 5%

Total Combined Bitumen Recovery 88% 95% 97% 98%

TABLE 3

ECONOMIC BENEFITS OF TAILINGS EXTRACTION BY THE OLEOPUILIC SIEVE

% Bitumen % Return On Simple Pay Back In Oil Sand Investment Period In Years

Case 1 12 37 2.7 (When Mining Limits 10 90 1.1 Total Production) 8 165 0.6

Case 2 11.7 11 9.5 (When Upgrading Limits 10.9 47 2.1 Total Production)

successful on a bench scale. During these tests, water and grease were added to the sand and tumbled with oleophilic balls. The recovered grease contained most of the flour gold originally present in the sand.

3-10 SYNTHETIC FUELS REPORT, DECEMBER 1986 GOVERNMENT

DOE SMALL BUSINESS PROGRAM SOLICITS EOR bitumen from reservoirs through the use of injected AND TAR SANDS PROJECTS fluids are: (1) low displacement efficiency and (2) low volumetric sweep efficiency (areal and vertical) The United States Department of Energy has in- when a low-miscibility fluid, such as steam in vited small business firms to submit proposals for steam flooding or air in in situ combustion, is used. its fifth annual solicitation for the Small Business New approaches are needed to accomplish the more Innovation Research (55111) program. Firms with effective displacement of the heated heavy oil or strong research capabilities in science or engineer- bitumen, such as a combination of steam flooding ing in any of the topic areas described in the and in situ combustion with other processes. Also, solicitation are encouraged to participate. new ideas are needed for surface extraction processes for the recovery of tar sand bitumen or 58111 program awards are made in 3 Phases. Under heavy oil. Phase I, DOE anticipates making approximately 100 firm, fixed-price awards during fiscal year 1987 to Award winners for FY1986 in the Enhanced Oil small businesses in amounts up to $50,000 over a Recovery and Tar Sands category included, 6-1/2-month project period. Successful completion of Phase I will be prerequisite to a Phase II A System to Avoid Tailings Pont When Processing proposal. Utah Tar Sands--Applied Utility Systems, Inc., Santa Ann, CA, Mr. William A. Samuel, Principal Phase It awards are expected to be made during Investigator. fiscal year 1088 to firms with approaches that ap- pear sufficiently promising as a result of the Phase The process is based on the use of solvent, fol- I effort. Phase II cost-reimbursable awards are ex- lowed by addition of small amounts of electrolyte pected to be in amounts up to $500,000 and to and surfactant to produce an effluent with a cover a period of up to 24 months. It is an- neutral pH suitable for disposal. ticipated that one-third to one-half of Phase I awardees will receive Phase II awards. A High-Efficiency Technique for Steamflooding Deep, Heavy Oil Reservoirs— Carbotek, Inc., Hous- Under Phase 111, it is intended that non-Federal ton, TX, Dr. Michael A. Gibson, Principal Inves- capital be used by the small business to pursue tigator. commercial application of the research or R&D. This concept supplies heat to the reservoir face Innovative methods and concepts for enhanced oil with a downhole unit augmented by heated feed- recovery (Eon) and recovery of syncrude (bitumen) water and uses a gas turbine to supply heat and from tar sands are being sought only in the follow- cogenerated electrical power. lag three topics: Water Cleanup Via New Processes for Fluid Diversion--In FOR Ultrasonic Coalescene—S. R. Taylor and Associates, recovery processes, one of the major problems is Bartlesville, OK, Dr. Scott R. Taylor, Principal In- the loss of injected fluids to high-permeability vestigator. layers and bypassing of lower permeability zones. Innovative processes that will effectively prevent The project will demonstrate the feasibility of injected fluids from flowing disproportionally into using an ultrasonic field to cause coalescence of these high-permeability layers are needed. These the fine solids and emulsified liquid droplets to processes should divert the injected fluid without achieve successful separation of the three phases plugging zones of low or medium permeability. (oil-water-solid) in one treatment step. Innovative-Tracking of Flood Fronts in Recovery Passive Seismic Mapping of Thermal Flood Fronts— Processes--Methods are needed that will enable Utah Geophysical, Inc., Salt Lake City, UT, Mr. tracing of injected fluids in chemical, miscible, and Lewis J. Katz, Principal Investigator. thermal recovery processes. Tracking may be ac- complished through measuring properties of reser- A proposed surface mapping method to track the voir fluids to detect injected fluids or through location of a thermal front without drilling addi- measurements of saturation changes (oil, water, tional wells is passive seismic monitoring. This gas, or additives). Presently, the means of detect- project is designed to show that seismic events ing flood fronts is through sampling of produced created by a thermal front can be detected by sur- fluid or logging at observation wells. Methods or face or near-surface seismometers and used to map processes that can make these measurements at the the location of the flood front. surface, without drilling additional wells, are espe- cially desirable. Improved Recovery Efficiency in Heavy Oil and Tar Sand Reservoirs--Two of the most difficult problems in the recovery of heavy oil and tar sand

3-11 SYNTHETIC FUELS REPORT, DECEMBER 1986 ALBERTA PROVIDES AID PACKAGE FOR OIL AOSTRA ISSUES TEN-YEAR REVIEW INDUSTRY The Alberta Oil Sands Technology and Research In order to stimulate exploration and development, Authority has issued a Ten-Year Review document the Alberta government will cut royalties by as summarizing its work in developing methods for the much as 12% on existing production and grant economic recovery and processing of crude bitumen royalty exemptions for as long as 5 years on new and other products from the oil sands deposits of wells drilled outside existing fields. The total Alberta. package includes: Although AOSTRA has been in existence for only - Royalty cuts for wells drilled before 1974 to 10 years, it has made a significant contribution to an average 31% for oil and 25% for natural the growth in production of bitumen and synthetic gas, about 2% lower than previous rates. oil. These products now account for 13.5% of Canda's total oil production. - Royalty cuts for wells drilled since 1974 to an average 23% for oil and 19% for gas, a The Ten-Year Review of AOSTIIAs performance drop of about 4%. was undertaken by some 65 external expert reviewers. They concluded that 'the overall per- Royalty holidays setting rates at zero for 5 years formance of AOSTRA has been more than satisfac- on wells drilled in the 12 months following tory and the authority should continue to pursue its October 1, 1986, 3 years for wells begun in mandate. This conclusion was reported along with the 12 months after November 1, 1987, and recommendations for renewed or increased ac- 1 year for wells begun in the 12 months tivities in some technology areas and suggestions starting November t, 1900. for change of emphasis or new areas for research. AOSTRA's funding history is shown in Figure 1. - A $75 million increase for 1907, to $525 mil- lion, in the royalty tax credit program, which refunds royalty payments through the corporate tax system.

The government also created a Small Producers As- sistance Commission, which will try to help small companies negotiate plans with creditors to restruc- ture debts. Small producers had sought a price support plan, but proposals made by Alberta for the federal government to participate were rejected.

Alberta Premier Don Getty said there also will be incentives to help stalled heavy oil and oil sands projects get started.

Alberta is working with the Canadian Federal government to determine what sort of incentives would be needed to start an oil sands project. Direct investment in a plant or loan guarantees are options being considered.

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

UNITAII SEES FAVORABLE OUTLOOK FOR In the case of conventional crudes the production HEAVY CRUDE AND TAR SANDS costs vary widely, between $2 to $18/bbl. The Statistical Office of the Government of Norway Speaking to the 1986 Eastern Oil Shale Symposium published production costs for the . held in Lexington, Kentucky in November, R. The estimated average cost in the British part of Oniana of the UNITAR/UNDP Information Centre the North Sea was $13.31/bbl and in the Norwegian for Heavy Crude and Tar Sands stated that the fields $11.50/bbl Such figures indicate that the worst part of the oil price crisis is over. Prices production cost of the bulk of heavy crude can must now seek a new equilibrium. With a low favorably compare with higher priced conventional priced oil barrel (below 15 dollars) exploration ac- oil. tivities are stopped; research and development can not be maintained; nuclear power plants become A study made for the State of California on the unattractive; natural gas and coal are placed in an comparative cost between offshore heavy crude and uncomfortable position; and many other alternate conventional light crude brought from Prudhoe Bay, sources of energy become non-competitive. Com- Alaska, showed that California offshore crude was panies are going bankrupt and governments of cheaper because of its nearness to shore and the producing countries are financially distressed with refineries. consequent negative impact on social structures. This situation cannot last forever. Therefore, Resource Availability 0 mona believes that the disturbing political forces and the restoring market forces must soon find a Heavy crude is available worldwide in large quan- working equilibrium, a non-volatile solution. Some titits. In many countries the potential of heavy evidence of this has been reflected in the slow but crude is only partly explored or largely unknown. positive upward movement of oil prices. He es- Heavy oil and bitumen resources far exceed con- timates that by early 1987 prices will attain the ventional oil resources. $18 to $20 price level. With that scenario in mind the economic outlook for heavy crude was assessed. There are vast resources of heavy crude and tar sands in China. The Beijing government is invest- Oil Prices ing heavily in heavy crude exploration and man- power training. If the present policy continues The economic outlook of heavy crude and bitumen China will be one of the leading countries in tech- basically depends on three factors: the future of nology within a period of 20 years. oil prices; the cost of production; and the availability of the resources. Omana believes it Estimates by the U.S. Geological Survey indicate unlikely that conventional oil prices will continue that the petroleum belt from Alaska to Argentina below $15/bbl. The sharp drop during the first may have more heavy oil and bitumen than all eight months of 1986, was the result of an interna- conventional oil in the world. tional policy designed to eliminate high cost oil producers. Heavy oil, whose production expanded Gradually, the world is beginning to realize the consistently until the beginning of 1986, became a vast potential of heavy crude and bitumen. victim of this policy when differentials between light and heavy crude become small. Outlook

Production Costs o mann concludes that the economic outlook for heavy crude is optimistic because: Technology developed by the largest heavy crude and bitumen producing countries has contributed to (a) The worst of the oil price crisis is over a significant decrease of production costs at the and oil prices should recover to at least well head in those countries. For example, $18/bbl. Petrolens de Venezuela S.A. (PDVSA) announced that the production cost in the Orinoco Petroleum (b) Research and development in the tradi- Belt had fallen to $2 per barrel. The Centre es- tional heavy oil producing countries and in timates that in California the cost of onshore China and the U.S.S.R. will result in ob- production at the wellhead is between $5 to taining higher recoveries and lower $10/bbl. In Canada, in the Cold Lake Area, the production costs. cost of production is estimated at $6 to $8/bbl. In the two surface mining projects in the Athabasca (c) The heavy oil and bitumen resources are area of Alberta the production cost is estimated at plentiful, larger than conventional oil $14 to $16/bbl. Obviously, more research is needed resources, and become competitive with to continue decreasing production costs, in conventional oil at higher oil prices. general, if oil prices are low the research and development budget is constrained and production costs will not decline rapidly.

3-13 SYNTHETIC FUELS REPORT, DECEMBER 1986

SUNCOR ESTIMATES OPERATING COSTS AT not exceed the 1985 yearend debt position. Suneor C$20/BA RREL implemented a staff reduction program across the company to eliminate 500 positions through early In testimony before the Standing Senate Committee retirement and other voluntary programs, reloca- on Energy and Natural Resources in Canada, T. tions and some terminations. Thomson, President of Suncor, addressed the ques- tion of break-even oil prices. In response to the question "Under what pricing conditions is integrated oil sands development Suncor's project at Fort M eMurray commenced feasible in Canada?", Thomson stated that Suncor operation in 1967 and was the pioneer commercial has not been involved in the analysis of any new producer of synthetic crude oil from the Athabasca integrated oil sands development projects and, oil sands. In 1985, Suncor mined 30 million tonnes therefore could not offer any particular insight into of oil sand from which about 40,000 barrels a day this question. of synthetic crude oil was produced. Because of operational difficulties, this was significantly below A further question was, "Should the federal the plant operating capacity of about 50,000 barrels government intervene to support higher cost oil a day. The operation employs over 2,000 people production when prices are depressed?" In including contractors. Since 1980, Suneor has spent response, it was stated that Suncor does not more than $500 million in expansion and new re- generally advocate subsidies for energy production. placement facilities to improve reliability and It believes that business decisions for Canadian production capability. energy investments are best made on the basis of prices available to Canadian producers in the inter- Thomson stated that, assuming a normal working national market. Although the situation at Suneor's environment and an efficient plant operation at a oil sands plant is that the price received for syn- production rate of 50,000 barrels a day, Suneor's thetic crude oil is lower than the plant's production current oil sands operating costs should be ap- costs, Thomson emphasized that Suncer is not a proximately $20 a barrel in Canadian funds, down passive hostage of fate. The company is working by about $5 a barrel from 1985. The $20 a barrel very hard to bring cost per barrel down so that it figure embraces all cash costs and stay-in-business may weather the price storm. Oil sands production capital. Royalties and taxes are being paid now at costs are now considerably lower than they were a rate of about $1 a barrel, compared to about $7 last year, and the company is still pushing to get a barrel last year. This is because provincial production up and costs even lower. Suncor Crown royalties have been reduced substantially and believes the operation has to stand on its own the federal PGRT eliminated from May 1 to the economic merits. Suncor is confident that it has a end of this year. He emphasized that the es- good chance of keeping Fort McMurray open, timated cash cost is based on the synthetic crude despite the enormous price pressure and ensuing production rate mentioned above. If Suncor fails cash losses. to meet the 50,000 barrels a day objective, then cash costs will be higher for each barrel. However, he went on, if crude oil prices move even lower or should they stabilize below the cash The Alberta government recently advised that it is costs of Suncor's synthetic crude oil production, reducing its royalties on Suncor's oil sands revenues despite best efforts to reduce costs further, then from 12 percent to 1 percent for the nine-month Suncor may not have the financial resources needed period from April 1 to December 31, 1986. This to continue the oil sands operation. At some means that Crown royalties and PGRT will drop point, if this situation arises, "we shall have to from an estimated level of about $2.25 a barrel to shut down". There is a point at which Suncor can- about 20 cents a barrel for the period. not allow the Fort McMurray operation to pull down the rest of the company. It is recognized The price received for Suncor's oil sands production that termination of oil sands production would have in mid 1986 averages C$17.05 a barrel or US$12.25. a very significant financial cost and far-reaching social implications. Furthermore, there is a sig- Acknowledging Suneor's 1986 cash cost, including nificant risk--both economically and technically-- royalties, of about $21 a barrel for its oil sands that the plant could not be brought back to full operation, the collapse of crude prices has neces- production. Certainly it would be a costly, dif- sitated an all out effort to stem the cash losses ficult and disruptive process and one that the com- that the company is suffering at current prices. pany would prefer to avoid. If the plant were to The bulk of the operating costs at an oil sands close, the economic impact would be felt not only plant is fixed, and a large proportion of the costs in northern Alberta, but throughout the country. continue to be incurred regardless of production Canada's light crude oil supply would be sig- levels. Therefore, there is no advantage in cutting nificantly altered and the country's long-term back the operation. Indeed, there is advantage in energy security would suffer. maximizing production.

Thomson's strategy at the oil sands plant is to min- Notwithstanding Saucer's fundamental belief in the imize the losses and to stay in the oil sands busi- market system, the foregoing suggests that, under ness. Suncor does not want to close the plant. certain conditions, there is a need for government The cost to everyone involved would be enormous. support for existing, strategic high-cost energy Suncor's 1986 corporate financial strategy was to projects for a limited period of time. The object

3-14 SYNTHETIC FUELS REPORT, DECEMBER 1986 of the support would be to sustain the operation It could be extremely expensive to bring that plant long enough to assess long-term market conditions back up at all. It is very harsh environment; if and to ensure that every possible cost reduction the plant is shut down for a while, regardless of and production efficiency has been found and how well you think you have shut it down and how implemented. much money you are spending to maintain it in good state, when it is not operating, you do not In the absence of economic viability at the end of know what kind of state it is in. It could cost the limited transitional period, both government and dozens or even hundreds of millions of dollars to industry would have exhausted every reasonable and get It back up again, depending on how long it was responsible means and the reality would, in fact, be down and on many other variables. So, economi- termination of the project. cally, unless you thought prices were going to be very high, you might be precluded from starting up. In response to a further question about the price which would be necessary to induce the building of a new tar sands plant, Thomson said that to provide 10 percent after tax return on the Suncor facility, (built many years ago) and to upgrade it regularly--it would require a price of $28 or $29 Canadian.

Other questions concerned whether it would be pos- sible to shut the plant down, and then restart it when prices improved. Thomson's reply was that one of the biggest problems of shutting down, aside from the economical and technical problems of coming back up, has to do with people. Equipment can be managed, though it is very costly. Re- establishing the team and the know how would be a problem, not only on the research and technical side. There is a tremendous amount of know how involved in running the plant well and people are quite important to the process.

3-15 SYNTHETIC FUELS REPORT, DECEMBER 1986 ECONOMICS

HEAT PIPE PROCESS COULD PRODUCE SYNCRUDE FOR OPERATING COST OF $13.32/BARREL FIGURE 1 THREE SCHEMES FOR Work at the University of Utah has been focused TRANSFERRING HEAT on a two-stage fluidized bed process utilizing heat pipes for retorting Utah tar sands. Researchers in TO THE PYROLYSIS ZONE the University's Department of Chemical Engineer- ing note that all important thermal recovery processes are characterized by chemical reactions occurring at two separate zones in the process. In the first zone, bitumen is pyrolyzed at 450-550 °C to produce coke and a gas, which when condensed yields a synthetic crude oil that can be upgraded 41^Pluidiung 'r^iuidlung and then blended with conventional crude oils. The Hot 81nd remaining sand, coated with coke, is transported to a second zone, where the coke is combusted at 550 O C or higher with air or enriched oxygen. Energy is required in the pyrolysis zone to preheat the tar V. sand and to supply the endothermic heat of P. pyrolysis. This energy can be obtained from the combustion zone, where exothermic reactions occur.

Comparative Process Efficiency 1) RECYCLE 2) RECYCLE 3) USE OF Lost work calculations for a second law ther- OF HOT OF HOT HEAT PIPES modynamic analysis were made for the three PYROLYSIS SAND generic thermal processes shown in Figure 1. All GAS three schemes utilize separate fluidized beds for the pyrolysis and combustion reactions. In the first case, heat of combustion is transferred to the A comparison was made for the energy self- pyrolysis bed by recycle pyrolysis gas. In Case 2, sufficient condition at the minimum bitumen con- recycle hot sand carries heat of combustion to the tent. The results are given in Table 1. Case 1 pyrolysis bed. In Case 3, heat of combustion is has the highest specific energy recovery, but must transferred directly by heat pipes. In all three operate with a relatively high tar-sand bitumen eases, three sets of external heat exchangers are content of 11%, and a relatively high fluidizing used to recover energy from hot pyrolysis gases, gas-to-tar sand ratio of 2. Case 2 can operate hot sand, and hot flue gases.

TABLE 1

LOST WORK ANALYSIS AT MINIMUM ENERGY SELF-SUFFICIENCY CONDITION

Pyrolysis Gas Hot Sand Use of Heat Energy Transfer Recycle Recycle Pipes Mode Case 1 Case 2 Case 3

Bitumen weight fraction (minimum value) 0.11 0.085 0.085 Combustion temperature (°K) 810 750 785 Hot sand recycle ratio 0 18 0 Fluidizing gas/tar sand ratio 2 0.35 0.05 Energy recovered from hot sand (kJ/kg tar sand) 373 317 352 Total lost work (kJ/kg tar sand) 739 539 423 Thermodynamic efficiency, % 5.5 10.8 30.0

3-16 SYNTHETIC FUELS REPORT, DECEMBER 1986 with a bitumen content of only 6.5%, but requires elevated by bucket elevator B-1 and fed into the an extremely high hot sand recycle ratio of 18 and reactor R-1, which comprises two stages; the upper has the lowest specific energy recovery. Case 3 stage constituting the pyrolysis section and the can also operate with a bitumen content of only lower stage the burner (combustion) section. The 8.5%, and has a specific energy recovery almost as upper bed is fluidized with a recycled stream of low as Case 1. Case 3 has by far the lowest lost fuel gas (3) and the lower bed with air (7), which work and the highest efficiency. bums the coked sand (4) that flows by gravity from the upper bed. Steam is generated at two levels, Process Design high pressure (36) and low pressure (34), by heat recovery in S-i and 5-2 using hot spent sand (5) Preliminary process designs were developed for the from the burner. Finally, the cooled sand (14) is heat pipe system (Case 3) at production levels of discharged to a landfill. Hot gases (2) containing 15,000 and 50,000 barrels/day of synthetic crude vaporized bitumen, cracked products, and fluidizing Oil. At the lower level, the weight percent gas leave the reactor Il-i, and pass through heat bitumen in the tar sand was taken at 12%, while exchanger E-2 where the recycle stream of 10% was taken at the higher level. The tar sand pyrolysis gas (16) is preheated. Low-pressure steam was assumed to be from a Utah deposit with zero is generated in 5-3 using the process heat in the water content. pyrolysis gas stream (15). Pyrolysis gas stream (17) is then cooled with air in E-4 and water in E-5, Considerable effort was spent in developing an ef- and the condensed oil (20) is removed in the phase ficient heat exchanger network. The resulting separator 6-3. process flow diagram is shown in Figure 2. Follow- ing crushing and grinding in 6-2, tar sand feed is

FIGURE 2 DIAGRAM FOR HEAT PIPE RECOVERY OF BITUMEN

P-i

Tar Sand C-2

B-I -3 [-1 E-3 Flue Gas

8.2 Air C-2

Legend .-.-.--.. E-4 6. 1 Bucket Elevator 6-2 Crusher and Grinder C-i 6-3 Reflux Drum 4... - C Direct-Drive Steam Turbines ( Heat Exchangers P Pump S-i R-1 Reactor S Steam Generators Gas P.2 - r 5-2 C-] Power (-6 P-i 8-31 Spent Sand

fl Oil

3-17 SYNTHETIC FUELS REPORT, DECEMBER 1986 The recycled pyrolysis gas (22) is compressed at C- TABLE 3 2 using high-pressure steam generated in Si, and preheated (16) in E-2 before finally heating it in E TOTAL CAPITAL INVESTMENT FOR 15,000 BBL/DAY 1 with the combustion gas (6) leaving the burner.

Fresh air feed (12), compressed at C-i using part Item Cost in $1,000 of the high-pressure steam generated in S-i, is then preheated in E-3 with the hot combustion gas Equipment 112,710 (9) leaving E-1. The rest of the heat in combus- Off-site Facilities, Site Development tion gas stream (1) is used to generate low-pressure & Building (iO% Equipment) 11,270 steam in 5-3. 2% Contractor Fee 2,480 Fixed Cost Investment 126,460 Part of the high-pressure steam generated in Si, Working Capital 11,000 remaining after running the compressors C-i and Total Investment 137,460 C-2, and all the low-pressure steam generated in 5- 2 and 5-3, is then utilized to drive a turbine to generate electrical power at C-3. The water vapor mixture leaving the compressors C-i, C-2, and C-3 is cooled with air in E-6 and pumped back to Estimated annual operating costs are summarized in steam generators S-i and 5-2. Table 4. The total annual operating costs of $65,297,000 are equivalent to $14.54 per barrel. The energy necessary to sustain the pyrolysis process is obtained from the burner section in fl-i For a production level of 50,000 barrels/day, the by transferring the heat to the upper section result was $13.32/bbl of oil. These values are very through heat pipes filled with liquid potassium. sensitive to the assumed cost of mined tar sand, The advantages of this system over other common which contributes from $10 to $12 per barrel of oil means of heat transfer are high energy flow per to the annual operating cost. unit of cross sectional area, small driving force, and uniform temperature of operation (close to TABLE 4 isothermal operation at each end). ANNUAL OPERATING COST FOR 15,000 BBL/DAY Economic Evaluation

Equipment sizes and estimated costs are sum- Item Cost in $1,0001yr marized in Table 2 for an estimated production level of 15,000 barrels/day. Total capital invest- 1, Mined Tar sand at 5 $/ton, ment is given in Table 3 as $137,480,000. 330 days/year 49,121

TABLE 2 2. Variable Operating Costs: EQUIPMENT SIZE AND COST FOR 15,000 BBL/DAY Cooling water, $0.11/1,00 gal 220 Electricity, $0.065/kw-hr -10,347 Unit No. of Total Installed Code Units unit size Cost in $1,000 3. Fixed Process Costs: Direct Operation Cost (DOL): a-i 2 26 It dia, 110 it height, 6 men shift, io s/hr 004 1180 heat pipes 13,290 E1 2 7,422 It 720 Operating Supervision, 50% DOL 452 E-2 6 8,739 ft 2,160 Operating Payroll Burden, 50% DOL 452 E-3 3 6,639 ft2 1,686 It Operating Supplies, 20% DOL 181 E-4 3 8,816 1,377 it 6,330 E-5 5 6,339 1,510 Maintenance, 5% FCI E6 5 9,800 ft2 2,640 Plant Overhead, 50% DOL 452 Administrative Cost, 50% DOL 452 s-I 2 71940 tubes 10 it x 2 in 3,174 Taxes and Insurance, 496 FCI 5,060 S-2 4 7,540 turs, 10 it x 2 in 5,648 5-3 5 7,901 It 3,685 Depreciation, 10% FCI 12,650

C-I 1 13,602 HP 13,400 Total Operating Cost 65,927 C-2 1 10,708 HP 12,000 C-3 1 20,100 HP 16,120

P-I 1 14.2 HP 80 P2 1 82.8 HP 306

8-1 2 75 HP 4,8880 The economic evaluation did not consider on-site 8-2 (crusher) 2 925 HP 1,400 upgrading of the synthetic crude oil, which might 8-2 (grinder) 8 925 HP 8,000 be needed before the oil could be transported and 8-3 1 6 it dia, 24 it height marketed. Light hydrotreating at the site could Subtotal 93,930 serve this purpose. 20% contingency 18,780

TOTAL 112,710

3-18 SYNTHETIC FUELS REPORT, DECEMBER 1986 LEWIN ESTIMATES 2 BILLION BARRELS OF U.S. - Size of prospect TAR SAND RECOVERABLE AT MID $20/BBL - Depth - Pay thickness In 1983, Lewin and Associates prepared a report - Topography and lithology of overburden and for the Interstate Oil Compact Commission (10CC) ore entitled Major Tar Sand and Heavy Oil Deposits of the United States. The study established that the Engineering Cost Models U.S. tar sands resource amounts to over 60 billion barrels of bitumen in-place. The engineering-based costs used for analyzing steam soak bitumen recovery include: However, no estimate was made of the technically or economically recoverable portion of this - Drilling and Completion Costs resource. More recent work carried out by Lewin - Equipment Costs for the U.S. Department of Energy presents an ap- - Field Development Costs praisal of technically and economically recoverable - Annual Operating Costs tar sands. Costs were estimated as a function of geographic Tar Sand Resource In-Place region, reservoir depth, oil and water production rates, steam injection rates, fuel used for steam Tar sand was defined in the study as having an in generation, and pattern spacing. situ viscosity greater than 10,000 centipoise at reservoir conditions. If viscosity data were not The engineering-based capital costs used for available, a 10 degree API gravity cutoff was used. bitumen recovery from surface mining included; The U.S. tar sand resource base is currently es- - Pre-development Costs timated by Lewin at 63 billion barrels in-place. - Pre-production Clearing This is higher than the 54 billion barrel estimate - Support Systems presented in the 1983 IOCC/Lewin study, primarily - Mining Equipment due to the large amounts of hydrocarbons recently - Crushing Equipment defined in the Cretaceous and Tertiary sands over- - Bitumen Separation (Solvent Extraction) lying the Kuparuk River oil field in Alaska. The most recent estimate for tar sand resource in-place Costs were estimated as a function of ore and in Alaska, is 19 billion barrels in the Lower and overburden production rates and bitumen recovered Upper Ugnu formations, compared with a 10 billion per ton of sand. Equipment was sized according to barrel estimate for this deposit in the 1983 production rates determined as a function of IOCC/Lewin study. prospect size and depth, overburden and ore topog- raphy and lithology. For the major deposits (oil in-place greater than 100 million barrels), the U.S. tar sand resource in- After the low gravity bitumen is produced from a place is estimated at 22 billion barrels of measured tar sand deposit, additional costs must be incurred resource with an additional 40 billion barrels of for upgrading the bitumen if it is to be refined speculative resource in-place. The minor deposits into a transportation-grade liquid fuel. A fully- contribute at least 1.0 billion barrels of speculative loaded cost of $9.50 per barrel was used as the tar sand, although little data are available on the cost of upgrading bitumen to refinery-grade crude numerous small tar sand occurrences. The study oil. This estimate was based on various upgrading did not address the offshore California area where porcesses, including; tar sand deposits are reported to exist but where data are lacking. - Asphalt residual treating (ART) - Flexicoking, and Tar Sand Recovery Models - Ebullated-bed hydrocracking. The Lewin study relied on two different tar sand A 10% loss in crude oil volume was assumed to recovery models. A steam soak recovery model occur during the upgrading process, where a 300 combined a radial geometry, finite-difference heat API gravity oil is achieved. conduction simulator with a simplified oil recovery model based on pseudo steady-state flow and Economic Analysis of Steam Soak Prospect gravity drainage. An example of the results of the steam soak cost A surface extractive mining recovery model as- and economic model for a tar sand prospect were sumed a modified open pit/terrace pit mining sys- presented by M. Godec of Lewin at the 1986 East- tem. Algorithms were used to determine project ern Oil Shale Symposium. This prospect contains life, rates of topsoil removal, overburden removal, 736 million barrels of bitumen in-place and covers ore recovery, and overall recovery efficiency based an area of about 10,200 acres at a depth of 414 on the following prospect characteristics; feet. The economic analysis of this prospect shows that it can be produced economically at a 1096

3-19 SYNTHETIC FUELS REPORT, DECEMBER 1986 alter-tax rate of return, including upgrading and/or TABLE 2 gravity penalties, at an oil price of about $20.20 ($1985) per barrel, as summarized in Table 1. In- ECONOMICS OF OIL PRODUCTION vestment costs for this project represent about FROM TAR SAND SURFACE MINING $2.00 per barrel, operating costs are $5.90 per bar- rel, financial costs are about $3.60 per barrel, and return-on-investment requires $1.70 per barrel. In 1985$/Barrels of addition, the gravity adjustment (penalty) to make Cost Category Oil Equivalent this 80 API gravity crude comparable to 40 gravity marker crude is $7.00 per barrel. Over the 22-year life of this prospect,. over 72 million bar- Total Revenues 47.90 rels of oil are produced from the field, repre- Less Gravity Adjustment (1.60) senting roughly 10% of the bitumen in-place. Less Upgrading Adjustment (9.50) Net Revenues 36.80 TABLE 1 Total Investment 2.40 Operating Costs Plus Overhead 11.20 ECONOMICS OF BITUMEN PRODUCTION FROM Financial Costs (Royalties and Taxes) 14.30 STEAM SOAK After-Tax Cash Flow (ROI) 8.00 Total Upgraded Production 660 Million Barrels Cost Total Resource In-Place 812 Million Barrels Cost Category Per Barrel (1985$/Barrel) Total Revenues 20.20 Less Gravity Adjustment (7.00) Net Revenues 13.20 Total Investment 2.00 Estimate of Domestic Tar Sands Resources Total Operating Costs 5.90 Recoverable Financial Costs (Royalties and Taxes) 3.60 After-Tax Cash Flow (ROI @10%) 1.70 The results of the Lewin study show that 5.7 bil- lion barrels of domestic tar sand are technically Total Bitumen recoverable, using cyclic steam injection and sur- Per 10-Acre Pattern face extractive mining. Of this, 4.9 billion barrels are technically recoverable from surface mining - In-place 721,000 Barrels methods, with 0.8 billion recoverable from steam - Recoverable 71,000 Barrels soak applications. Total Field Production 72.4 Million Barrels Steam soak technology, while limited in overall recovery efficiency, shows economic promise for domestic tar sands. The analysis shows that the Economic Analysis of a Surface Mining Prospect threshold price for the geologically most favorable tar sand deposits is about $20 per barrel and that A sample surface mining prospect contains 812 mil- one-half of the technically recoverable target can lion barrels and covers approximately 8,900 acres be produced at $25 to $30 per barrel, as shown in at an average depth of 148 feet. The average net Table 3. (productive) thickness of the prospect is 87 feet, Surface extraction of tar sands appears to be more with a gross interval thickness of 252 feet. Based costly, even though it recovers a higher proportion on the reservoir characteristics for this prospect, of the oil in-place. The threshold price in the an overburden removal rate of over 1 million geologically most favorable tar sand deposit is metric tons per day is assumed, along with an ore about $25 per barrel and one-half of the techni- production rate of nearly 270,000 tons per day. cally recoverable target can be produced at about $45 per barrel (Table 3). The economic analysis for this prospect shows that it can be developed at a crude oil price of $47.90 A substantial portion of the production costs for per barrel ($1985), including upgrading costs and mineable tar sands results from bitumen upgrading gravity price differentials. Alternatively, the raw and gravity differentials (generally 11 to 12 dollars bitumen can be economically developed for road per barrel) required for converting the bitumen into asphalt at a price of $36.80 per barrel ($1985). A a liquid fuel. As shown in Figure 1 the summary of the economic analysis for this prospect price/supply curve for domestic tar sands recovered is given in Table 2. Financial costs (e.g., royalties, by mining shifts substantially when upgrading costs severance taxes) represent the greatest cost com- or gravity differentials are included. This implies ponent, at over $14.00 per barrel, with investment that the economics of producing bitumen for the costs at $2.40 per barrel and operating costs at domestic asphalt market may be more favorable $11.20 per barrel. Over the project life, nearly than for production for the domestic liquid fuel 660 million barrels of bitumen are produced from market. The threshold price for the asphalt this prospect.

3-20 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 3

DOMESTIC TAR SAND RESERVES Economically Recoverable Resources (Billion Barrels)

Crude Oil Price Surface Mining Steam Total ($1985/Barrel) Liquid Fuel Asphalt Soak Liquid Fuel Asphalt

15 - 0.5 0.1 0.1 0.6 20 - 1.1 0.2 0.2 1.3 25 0.4 1.4 0.4 0.8 1.8 30 0.9 2.0 0.5 1.4 2.5 35 1.4 2.1 0.5 1.9 2.6 40 1.6 4.2 0.5 2.1 4.7 45 2.1 4.3 0.6 2.7 4.9 2± Total 4.9 4.9 0.8 5.7 5.7 (Technically Recoverable Target)

market is about $15/barrel for the geologically more favorable surface mineable deposits. One-half FIGURE 1 of the resource can be produced for the asphalt market at prices of about $35 per barrel. COST / SUPPLY RELATIONSHIP Lewin concludes that under conventional extraction OF U.S. TAR SAND (MINING) technology, domestic tar sands can make a sig- nificant contribution to the domestic market for hydrocarbons (either as asphalt or as conventional liquid fuels), but at higher oil prices than those ex- isting in 1986. Advanced extraction technologies, IO,ADI"O improved geological definition, and more cost- efficient methods are required to convert this mas- sive domestic resource into an economically af- 0 fl*ono O oa*vrrY PESALTY forable reserve. The study only considered conventional or 'base case" recovery technologies. Significant potential exists for the application of advanced tar sand recovery technologies. Further study will be required to assess the potential of these more ad- vanced recovery technologies.

I • • I • I

flCOVtI.ILS fl*nI WtLIOI I*fltLtJ

3-21 SYNTHETIC FUELS REPORT, DECEMBER 1986 TECHNOLOGY

IN SITU HYDROGENATION PROCESS DEVELOPED The viscosity reduction ratios in the tests run at BY WORLDENERGY SYSTEMS standard conditions vary from a low of 112:1 (California A) up to 18,000:1 (Texas A). These WoridEnergy Systems, Rocky Mount, Virginia, has reduced viscosities, extrapolated to reservoir conch- been working on the in situ hydrogenation of tar tions, form the basis for expected higher production sands bitumen to upgrade it and make it more rates with the technology. easily producible. At standard conditions, the median gravity increase To test the concept, hydrogenation tests have been was 7.40 API while results from individual runs vary carried out on eight crudes; two each from Al- from 6.0 (California A) to 11.1 (Alberta A). Al- berta, Utah, California and Texas. The heaviest though it is understood that these higher-gravity (Texas A) has an extrapolated viscosity at 1000 F of crudes are more valuable, the specific price advan- greater than 1,000,000 cSt, a 175°F pour point, and tage for any particular upgraded produced crude -2 0 API gravity. The lightest, Texas B, has a 1000F was not established. viscosity of 1,200 cSt and 16.3°A P1 gravity. Some results were discussed at the 1986 DOE Tar Sand A very general assessment of the results in Table 1 Symposium. is that significant upgrading has been achieved at modest hydrogen consumption levels. The results Test results are shown in Table 1. In the source are widely different among the crudes, but four of identification, A and B refer to different crudes them produced promising results: Alberta A, Utah from the same province or state. The designations B, and the two from Texas. of 'mild' and "standard" refer to the time- temperature levels: short times and low tempera- Thus, hydrogenation without a catalyst, taking place tures are mild conditions while longer times and at conditions which can be created in a reservoir, higher temperatures are designated as standard. At can upgrade the oil-in-place to a commercially sig- still longer times and higher temperatures (severe nificant extent. conditions) the results were unsatisfactory: coke and gas become significant. The downhole hardware is designed to operate in an near the oil zone and deliver the super- According to WoridEnergy Systems, an important heated steam and hydrogen required to stimulate result of this work is that while coke and gas are chemical reactions and oil production. As shown in produced under some conditions with some crudes, Figure 1, hydrogen and oxygen are supplied by a change in the conditions will eliminate the coke separated tubes to a downhole burner where they formation. are injected into a cylindrical combustion chamber in one or more stages. A coolant stream consist- The experimental data show significant improve- ing of either water or excess hydrogen is supplied ments in viscosity, sulfur, gravity and, in most to the burner at several locations to moderate the samples, hydrogen content of the oil. Calculated combustion, protect the hardware from excessive values for C/H ratio show reductions in all cases. temperatures, and adjust the effluent to the desired

TABLE 1

HYDROGENATION TEST RESULTS

Viscosity Gravity Sulfur Hydrogen Ratio Increase Reduction Addition at 100°F °API Wt96 SCF/bbl Mild Conditions Alberta B 52 3.8 -- 1,101 California B 82 5.5 13 702 Utah A 289 2.6 0 452

Standard Conditions

California 112 6.0 29 32 Texas B 246 7.4 33 555 Alberta A 429 11.1 29 289 Utah B 9,090 6.6 35 140 Texas A 18,000 10.7 38 1,084

3-22 SYNTHETIC FUELS REPORT, DECEMBER 1986 Two important operating benefits result from the FIGURE 1 use of hydrogen as fuel. One is that, regardless of operating conditions, there will be no combustion residue or acid gases to contaminate the equipment W E S PROCESS FOR or the formation; steam is the only product of the SUPERHEATED STEAM AND reaction, making the combustion process easier to control. The other is that the extremely short dis- HYDROGEN GENERATION tance required to get complete combustion permits a very compact combustor design. For the small diameter available within a well and the high heat rates required, a much greater length would be NATURAL GAS RAW WATER AIR required for complete combustion of methane or I 1000 PPM tIDS other fuels in a downhole device. t EVAPORATOR Downhole steam generators have been plagued with corrosion problems due primarily to the presence of HYDROGEN I PPM OXYGEN sulfur in the fuel, which forms highly acidic sulfur 99.91 IDS dioxide that attacks stainless steels. Since there is 300 Psis no sulfur in the hydrogen, this problem is FINAL COMBUSTION TEMPERATURE eliminated. Likewise, the absence of carbon in the COOLANADJUST fuel means that no carbon dioxide will be formed, which is the principal constituent in carbonic acid, COMPRESSOR _ another corrosive chemical. WE S PROCESS The WES development work has centered on a cylindrical main combustion chamber fed by fuel, oxygen, and coolant streams as well as hot exit gases from a pilot (or preburner) stage. The main I chamber is a linear burner with highly turbulent flow and rapid combustion.

The pilot, depicted in Figure 2, consists of a cylindrical chamber with cones on both ends into CO Wa a 0 I. E which are injected fuel and oxygen. Flow rates BURNER are set so that combustion volume is low compared to the chamber capacity, and the flame is cooled by excess fuel. A very restrictive orifice is used to exhaust the hot gases from the pilot into the main chamber where they propagate a stable flame PACKER downstream. The conservative flow coupled with I (OPTIONAL) / / high pressure drop serves to ensure that the pilot I flame is maintained regardless of transient pressure / I / SUPERHEATED or combustion conditions downstream. STEAK A prototype dowohole system was designed and built, consisting of a pilot section and a combustion section. The combustion section has not been operated but has undergone testing. It operates with an excess of hydrogen which is the only inter- nal coolant at design temperatures of 1400-18000F. delivery temperature. The coolant may be con- veyed by a third downhole tube, the mechanical Reservoir Proce support pipe, or the well casting. The process which WES believes to have the best potential for success uses the following steps: The hardware provides a means for injecting heat and hot hydrogen into a formation to create the t. Drill wells in inverted five-spot, five-acre pat- conditions under which hydrogenation takes place. terns. The two conventional heating methods are steam injection and in situ combustion, and the downhole 2. At an intended producer, use huff and puff system can use either of those methods. When the with wet steam to clear out the region around quantities of hydrogen and oxygen are matched for the welibore. complete combustion, steam is produced for heating the reservoir. An excess of oxygen can be added 3. Inject superheated steam into the intended to induce in situ combustion. With an excess of producers. The superheat vaporizes the water in hydrogen, the effluent is hot hydrogen and steam, the reservoir around the weilbore and carries it which is used for hydrogenation. deeper into the formation.

3-23 SYNTHETIC FUELS REPORT, DECEMBER 1986 hydrogenation huff-and-puff up to the economic limit of production. WES has estimated recoveries FIGURE 2 ranging from 4060+%. The permeability distribu- tion in the reservoir is very important in these COMBUSTOR PILOT STAGE calculations. A feature of the process is the use of the region around the wellbore of the intended producer as a superheated zone. This essentially creates a reac- TEMP PRESS PORT PORT tor region in the reservoir in which the hydrogena- tion takes place and that region is re-used. The untreated oil outside that region is driven into it and, as a result, the treated oil is displaced and produced. The mobility ratio for this displacement process is excellent because, at the reservoir tem- perature, the viscosity of the untreated oil ( the displacement medium) is roughly five to ten times higher than that of the treated oil. During produc- tion, the gravity or viscosity of the produced oil is monitored and when it rises above a control point, the well is shut in, and superheated steam and

COMBUSTION hydrogen are injected. At that moment the super- heated region will have a significant fraction of its CHAMBER oil saturation comprised of untreated oil. When the same "reactor" region is superheated and pres- sured with hydrogen, the hydrogenation will take place. This procedure avoids heating the entire reservoir in order to treat the oil and is one of the reasons for good heat economy. FUEL OXYGEN Estimated Economics

One set of economic studies was done for an Al- berta reservoir using the reservoir parameters shown in Table 2. The production, operating costs, and capital investments are presented in Table 3.

EXIT NOZZLE EXIT GASES OXYGEN TABLE 2

RESERVOIR CHARACTERISTICS FOR ALBERTA PROJECT

Depth to top 1,370 ft. 4. Inject hot hydrogen into each intended producer of pay zone and soak in order to hydrogenate the oil. Overall thickness 155 ft. 5. of pay zone Lower the pressure in each intended producer Net pay and produce treated oil. Some of the hydrogen 90 ft. Permeability dissolved in the oil will be released and aid in 1,500 md production by solution gas drive. Porosity 35 co Oil Saturation 9.9 v,t% 6. Repeat steps (3), (4), and (5) for as long as 58 vol% economically advantageous. Water Saturation 7.0 wt-6 42 val% Initial reservoir 7. From the central injection well conduct a drive 55 °F to push the untreated oil from the center of the temperature Oil viscosity at pattern towards the intended producers. The 60,000 eSt drive can be based upon in situ combustion, wet reservoir temperature oxidation, superheated steam or other means. Original oil in place 1,575 bbl/acre-ft

8. Alternately produce oil and inject heat and hydrogen into the intended producer to maintain the reservoir temperature and hydrogen pressure.

The drive from the injectors will eventually be switched to cold water and will continue along with

3-24 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 3 In general, horizontal wells have been successful for enhancing oil production rates and reducing PRODUCTION AND CASH FLOWS water and gas coning problems. Although horizon- FOR ALBERTA PROJECT tal wells have been used to produce 12 degrees API heavy oil using only pump assistance (without steam), some sort of steam and horizontal well Production alter 6.972 MM bbl/yr combination is necessary to produce highly viscous 3 years oils. Operating Costs after 3 years (C$MM/yr) Table 2 lists nine horizontal well thermal projects. Fluid injection 43.58 The table shows that in conjunction with horizontal Central plant 24.40 wells, steam drive, cyclic steam stimulation, and Fixed production 0.48 steam assisted gravity drainage have been used to Hydrogen compression 0.67 produce heavy oil and tar sand reservoirs in pilot Labor for WoridEnergy tests. Systems equipment 0.78 Water disposal 0.67 Currently, technology exists to drill up to 2 1 000 It Home office 0.35 long horizontal wellbores. These long weilbores are 70.93 used to augment oil production rates; also the high contact area of horizontal wells facilitates the in- Capital Expenditures (C$M M) jection of large steam slugs. Horizontal well drill- Project Year Startup 1 2 3 -14 ing costs are about 1.5 to 2 times greater than Steam generation 1.17 vertical well costs. Wells 2.75 7.0 7.0 7.0 Compressor 0.56 Cyclic Steam Stimulation Production 15.00 Water disposal 3.50 Horizontal wells can be used for cyclic steam WorldEnergy Systems stimulation, continuous steam drive, and the steam- equipment 2.26 2.04 assisted gravity drainage process. In many heavy Totals 3.92 28.32 9.04 7.0 oil and tar sand reservoirs, cyclic steam stimulation is necessary to establish initial steam injectivity. A numerical study compared the performance of a steam stimulation of a vertical well and a horizon- The calculations assumed a 30% return on invest- tal well. The horizontal well was assumed to be ment by discounted cashflow and then calculated 840 feet long. As shown in Figure 1, at the end the required wellhead net revenue -- market price of one cycle (90 days; 7 days production, 17 days minus transportation, royalties, and fees. Com- injection, 4 days soak, and 62 days production), pared with current operations which require the use cumulative production from a horizontal well was of a diluent for pipeline transportation, WES es- about five times larger than that obtained from the timates the wellhead price to be at least vertical well. However, the large difference be- C53.00/bbl higher because the diluent will be tween horizontal and vertical well production will eliminated. Under all these conditions, the price decrease in successive stimulation cycles. received for the oil must be C$14.47/bbl to achieve the target profitability. Steam Drive These profitabilities are based in part on low-cost A few numerical studies have reported results with natural gas at C$2.50/MSCF which leads to low- steam drive using horizontal wells. One study cost hydrogen at C$2.75/MSCF. numerically investigated the use of horizontal wells in a mature vertical well steam drive with a sig- nificant steam override. As shown in Figure 2, vertical wells showed an overall 64.7% OOIP recovery in 15 years. To mitigate the steam over- HORIZONTAL WELL TECHNOLOGY ADVANCES ride, after six years of 13 spot operation, eight 374 foot long horizontal wells were introduced along The technology of drilling long horizontal wells, the edge of a square drainage boundary. The in- either for gravity drainage alone, or for steam- troduction of eight horizontal producers along with assisted processes, has advanced considerably in vertical producers not only shortened the project recent years. It appears to hold great promise for life to nine years, but it also increased the overall application to a number of tar sand reservoirs. A recovery by one percent to 65.9% of OOIP. These useful review of the state of the art was given by results indicate that horizontal wells can be used in S. Joshi of Phillips Petroleum at the 1986 DOE Tar a mature steam drive to reduce gravity segrega- Sand Symposium held in Jackson, Wyoming. tion, improve sweep efficiency, and produce more oil. Table 1 gives a brief history of significant horizon- tal well projects.

3-25 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1

HORIZONTAL WELLS DRILLED

Reservoir No. of Depth Contact Year Company Field Wells (ft.) Length (ft)

1937 -- Yarega, USSR many -- 1000 max 1941 Leo Ranney, McConnesville, Ohio 6 -- 1000 et al. 1942 -- Franklin Heavy Field, 4 388 1000 Venango County, PA 4 388 600 1942(?) -- Midway Sunset, San 2 1100 70 Joaquin Valley, CA 1946 -- Round Mountain Field, 9 1650 56 Kern County, CA 1952 -- San Joaquin Valley, CA 1200 50 (Midway Sunset) 3700 50 1952 Venezuelan Oil La Pas Field, 9 10,000 50- 100(?) Concessions, Ltd. Venezuela 1952 Long Beach Los Angeles 8 3500 50 Oil Development (Wilmington) to4800 1957 -- USSR 1 1000 300 1967 -- China 1 3600 1600 1968 Mareovo, East 1 7200 1800 Siberia, USSR 1977 Conoco Tisdale, Wyoming 6 -- 1700 max 1970 Esso, Canada Cold Lake, Alberta 1 1558 1000 1979 Texaco Fort McMurray, Alberta 3 415 1000 1979 Esso, Canada Wells under MacKenzie 1 1603 1860 River, Alberta, Canada 1900- Elf-Aquitaine Lacq Field 1 2195 330 81 & IFP Southwest France 1 4100 1214 1981- Elf-Aquitaine Rospo Mare, 1 4500 1988 83 & IFP Offshore Italy Casters Lou, 1 9500 1300 South France 1980- ARCO Empire Abe Unit, 2 6200 300- 400 84 New Mexico 1901- ARCO Empire Abe Unit, 8 6200 300- 400 84 New Mexico 1982- ARCO Southeast Douglas 1 6500 300- 400 84 Garfield County, OK 1985 Esso, Canada Old Lake, Alberta, 1 1558 3330 Canada 1985 Petrobras Fazenda Belam Field 1 1000 554 1985 Sohio McMullen Co., Texas 1 10300 1908 1985 Sohio Glassock Co., Texas 1 -- 295 1985 Sohio Prudhoe Bay, Alaska 1 8989 1400 1986 Sohio Prudhoe Bay, Alaska 1 9000 --

Steam Assisted Gravity Drainage which reduced oil viscosity. Even then, oil produc- tion rates are only of the order of 0.3 bbl/day/ft In cyclic steam stimulation and in steam drive, length of a well. Sufficiently high production rates even though gravity drainage plays a part in oil are obtained by using 1000 to 3000 ft long production, most of the oil production is due to the w ellbores. reservoir pressure gradient. On the other hand, in the steam assisted gravity drainage process there is Figure 3 shows a counter current flow of hot oil no pressure drop, other than gravity head, between and steam with two parallel horizontal wells. The the injection and production wells. The oil is well pair is located near the bottom of an oil produced solely by gravity drainage. The rate of column with the injection well on top and the gravity drainage is enhanced by steam heating production well at the bottom. The wells are lo-

3-26 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 2

HORIZONTAL WELL - STEAM FLOOD PROJECTS

Horizontal Welts Length Steam Company & Year Location Number (ft) Process Status & Comments

Yarega USSR Many 300 max -- Active/Mine Assist.

Si gnal Oil Co. Sunny Side, 3 370 ft. cyclic & Inactive, 90-100 (1965-66) Utah drive API oil, drilled from a outcrop side

Petro-Canada Fort McMurray 1 330 cyclic & Inactive, Ca 10°A P1, MAISP-1 (1978) Alberta 2 120 drive drilled from a outcrop side

llopco Kern County, 4 430 cyclic Inactive, 130 API oil, (1979) California 4 730 drilled from a shaft

Esso - I (1979) Cold Lake, 1 1000 cyclic Active, ca 10°A P1 Esso - II (1985) Alberta, 1 3200 steam & Active, ca 100API Canada steam assisted gravity drainage

Texaco (1979) Fort McMurray 3 1000 cyclic & Inactive, ca 10°A P1 Alberta, Canada drive drilled from the surface

(1986) California 1 -- cyclic Active, 130 API oil

Petrobrass Fazenda Belam 1 544 (?) 14°A P1 oil (1985) Field, Brazil

Planned Project

MAISP (1985-87) Athabasca, 356 -- -- Mine/shaft project, Alberta 10°API oil

FIGURE 1 cated as close as possible with no pressure drop, other than gravity head, between them. CYCLIC STEAM STIMULATION USING HORIZONTAL Figure 4 shows three possible well configuration schemes for field application. Vertical injectors AND VERTICAL WELLS and a horizontal producer is a preferred well scheme for reservoirs with non-continuous shale barriers. All the laboratory results indicate that the sweep efficiency will be high for all well so schemes even in the presence of non-continuous shale barriers. Numerical simulation shows that the steam assisted gravity drainage process gives a higher recovery of OOIP than cyclic steam or steam drive.

Horizontal Well Drilling

As seen from Table 1 1 several companies have drilled horizontal holes In the last decade. Ini- tially, horizontal drilling was developed for shallow reservoirs using a shaft and tunnels. However, recent advances in drilling technology facilitate LT TIME (DAYS) FIGURE 2 FIGURE 4 PRODUCTION WITH AND WITHOUT DIFFERENT WELL CONFIGURATIONS HORIZONTAL WELLS FOR STEAM ASSISTED IN A MATURE STEAM DRIVE GRAVITY DRAINAGE

$0 CENTRAL AND INFILL WELLS ARE INJECTORS SCHZIIE t * NOSIZONTAL WELl. PAIR 70 A. ONLY CENTRAL o so VERTICAL INJECT0R ,4I -. 0 o. EIGHT HORIZONTAL - - - o PRDDUCERS ARE - DRILLED 2 50. U a 40

30 CIIESE It VERTICAL •TEAU INJECTION WELLS AND A HORIZONTAL PWOOUCTION WELL S ______x 20 -J o sun., -

0• 1 3 6 7 I II 13 15 •t—p.oauEl,E.WlLt YEARS

SCHEME III: SINGLE SLANT INJECTION AND PRODUCTION WELL

FIGURE 3 STEAM ASSISTED GRAVITY DRAINAGE CONCEPT

HORIZONTAL WELL PAIR

STEAM FWS TO INTERFACE AND drilling horizontal wells from the surface. Techni- OIL CONDENSES cal advances have successfully solved problems such SERVOIR HEATED OIL / AND as bit weight, directional control, and the dragging Nt CONDENSATE and sticking of drill pipe. Significant advances FLOW TO WELL have also been made in logging and completing these wells. Presently, available technology can be STEAl classified as follows: 1) short, 100-200 ft long INJECT I drainhole drilling, 2) medium length, 100-700 ft WELL long drainhole drilling and 3) 1000-2500 ft long horizontal well drilling. \ PRODUCTION WELL. OIL AND CONDENSATE A method of drilling 100-200 ft long drainholes in ARE DRAINED CONTINUOUSLY an unconsolidated formation using water jets is shown in Figure 5. The short radial drainholes are drilled through an underreamed portion of an exist- big vertical well. The process involves the follow- ing operations: 1) mill a S to 10 ft window in the casing and underream a 4 ft diameter cavity using

3-28 SYNTHETIC FUELS REPORT, DECEMBER 1986 water jets. 2) lower a whipstock in the hole and length of 700 ft. Recently, technology has been erect it at a right angle to the hole. 3) use a developed to complete such a hole by inserting a specially developed pipe with water jets to drill a slotted liner. 4 inch diameter hole. 4) cut off the production tube down hole. 5) de-erect the whipstock, turn it, Institute France du Petrole (IFP) and Elf Aquitaine and re-erect it at a desired angle with the last have developed the technology to drill, complete, drilled hole. 6) drill a second hole using steps 1 and log very long (2000 It) long horizontal wells. through 5. So far they have drilled four horizontal wells in Europe. Most of these wells were drilled at 2000 to 10,000 foot depths in a consolidated formation. A combination of regular drill bits with bent subs and downhole mud motor was used. FIGURE 5 Most heavy oil and tar sands reservoirs are not SHORT DRAINHOLE only unconsolidated sands, but are also shallow, on the order of 400 to 2000 ft. Such a shallow depth DRILLING SYSTEM poses n problem for kicking off from a vertical to

CABLE IN RESTRAINT TRUCK. , j(.wORxOVER RIG FIGURE 6 MEDIUM LENGTH DRAINHOLE DRILLING: a) WHIPSTOCK ASSEMBLY CABLE RESTRAINT b) WIGGLY COLLARS HIGH PRESSURE c) HOLE SCHEMATIC TUBING STRING A 1.114 INCH STEEL PRODUCTION TUBE

a) b) HIGH PRESSURE SEAL C.... 4J OIL ,I (it FORMATION uNOERRE;Mw rEAD RADIALDIAL BORE .1 13 I j J INTO FORMATION tiliril

HYDRAULIC ERECTION CYLINDER

c)

Recently, 200-700 ft long drainholes have been drilled through an existing vertical well. First a A...-,, window is cut into the existing casing by a milling operation. The "wiggly" collars, shown in Figure 6 .._—r C...n along with the angle buildup assembly are used to drill off the whipstock and into the formation, turning 3 degrees per foot with a turning radius of 30 feet. This continues up to 85 degrees, and then, a second stabilized bottom hole assembly drills the rest of the drainhole. Hydraulics and friction combine to limit the maximum drainhole length to between 600 to 1,200 ft. So far, Texas Eastern has reported the maximum drilled drainhole

3-29 SYNTHETIC FUELS REPORT, DECEMBER 1986 a horizontal direction. To overcome this problem, was about 6 to 8 times more than a vertical well. Texaco used a 45 degree slant rig to drill three In the last six years, advances in drilling technol- 1000 foot long horizontal welts at 415 ft. depth In ogy have progressed sufficiently to reduce a long the Athabasca deposits. Loxam reports a drilling horizontal well cost to 1.5 to 2 times a vertical method using a specially developed, hydraulically well cost. The costs could be reduced even further powered slant rig. A downhole mud motor powers if drainholes are drilled from an existing vertical the drill bit and a hydraulic force applied to the well, i.e., by using short drainhohe or medium drill pipe at the surface provides the needed weight length drainhole technology. on the bit. A similar technique is used by several river crossing rigs. These river crossing rigs may Joshi concludes that various commercial tech- be used to drill long horizontal wells. nologies are now available for drilling horizontal wells in an unconsolidated formation. Although In summary, various drilling technologies are avail- horizontal welts costs more than vertical 'veils, able to drill horizontal holes. Other than short they also produce more oil than vertical wells and length drainholes, most of these wells could be therefore many justify the increased cost. completed only using slotted liners. Presently very little information is available for cementing the The steam-horizontal well combination not only highly deviated welibores. Further improvements gives higher oil production rates but also gives are needed in the area of cementing and selective higher recovery of original oil in place as compared completions of horizontal wells. Recent develop- to that obtained using cyclic steam or steam drive ments in M IYD (measurement while drilling) offers with vertical wells. the possibility for more exact trajectory control. lie believes that steam assisted gravity drainage Horizontal Well-Steam Flood Projects using horizontal wells is probably the most suitable process to produce tar sands and bitumen. Table 2 lists nine horizontal well thermal projects; it shows only four active projects, two with a steam assisted gravity drainage process in Canada, one recently started with cyclic steam in Califor- nia, and one in Brazil. HEAVY LIQUID BENEFICIATION DEVELOPED FOR Since 1978, Esso's steam assisted gravity drainage ALABAMA TAR SANDS pilot, with a 1000 foot long horizontal production well and vertical steam injection wells, is producing The tar sand deposits in the State of Alabama con- tar sand oil in Cold Lake, Alberta, Canada. From tain about 1.8 billion barrels of measured and more 1978 to 1982, the well produced over 100,624 bbls than 4 billion barrels of speculative in-place of oil. The average daily production works out to bitumen. A comprehensive research program is in about 75 bbl/day. This is better than the average progress for the separation of bitumen from these daily production rate of 51 bbl/day expected from deposits. In general, Alabama tar sands are oil cyclic stimulation of a vertical well drilled at four wetted, low grade and highly viscous in nature. In acre spacing. Due to the encouraging results of view of these facts, a beaeficiation strategy has the first pilot, Esso recently announced plans to been developed to recover bitumen enriched con- drill a second 3228 foot long horizontal well in centrate which can be used as a feed material for Cold Lake, In contrast to Esso's success with further processing. horizontal wells, other tar sand projects with cyclic steam stimulation and steam drive were discon- The Mineral Resources Institute of the University tinued, probably because of poor thermal efficiency. of Alabama has developed several conceptual ap- For example, Signal Oil Company's Sunnyside proaches for beneficiation and separation of project in Utah gave an SO It (steam oil ratio) of bitumen. A summary of the flotation beneficiation 23 using cyclic steam and steam drive. work was presented in the Pace Synthetic Fuels' Report September 1986, pages 3-26. Table 2 lists three projects for heavy oil produc- tion. The first one in California started steam In addition, heavy liquid separation tests at a stimulation of a single horizontal hole in early specific gravity of 1.5 have demonstrated that 1006. The initial results are encouraging, but cur- more than 70 percent of the bitumen can be rently production data are not available in the open recovered in the float fraction containing 60 per- literature. The second pilot, the IIOPCO pilot, was cent bitumen. shut down in April 1985. The third pilot in Brazil's Fazenda Belem field reports 75 bbl/day oil produc- Tar sands from two different Alabama deposits, tion with a 544 foot long horizontal hole. This is Lawrence County (Sample I) and Colbert County significantly better than adjacent vertical wells (Sample II) were used in this investigation. Initial producing about 16 bbls/day. size reduction of tar sand samples was ac- complished by conventional crushing techniques and Horizontal Well Economics the product was sized to minus 10 mesh.

In 1979-80, the cost of drilling a horizontal hole Sequential sink-float separations with decreasing specific gravities were performed. A 77% zinc

3-30 SYNTHETIC FUELS REPORT, DECEMBER 1986

bromide solution, with a specific gravity of 2.4, was used as the heavy liquid for the separations. The specific gravity of zinc bromide solution was FIGURE 2 adjusted by adding pH 2 distilled water to it. Samples I and It were ground in a rod mill for HEAVY LIQUID SEPARATION OF about half an hour. After filtration, the fines were dispersed in the heavy liquid using a magnetic COLBERT COUNTY TAR SAND stirrer for 20 to 30 minutes. The suspension was then centrifuged for 15 to 20 minutes. The sink was dried, weighed, and assayed, and the float fraction was further reseparnted in a zinc bromide lOG solution with a low specific gravity.

S AlSAMPLE 0 10 The results of the heavy liquid evaluations of a sample I and It (minus 200 mesh) are shown in Isi 0 Figures 1 and 2 respectively. The cumulative --4 bitumen grade and recovery are plotted as a func- 0 Mi tion of specific gravity of the heavy liquid used in z the separation. The cumulative recoveries for Z - Mi sample I increase from 5396 to 9096 as the specific Mi gravities increase from 1.36 to 2.24. The bitumen U flnov.ry recoveries for sample II increase from 38% to 9396 - - - • Grid. as the specific gravities increase from 1.4 to 2.2. • • I • I I • I • I • I • 1.1 II II 1.0 2.0 5.2 34 3.0 SPECIFIC GRAVITY FIGURE 1 HEAVY LIQUID SEPARATION OF LAWRENCE COUNTY TAR SANDS

TEXACO PATENTS HORIZONTAL WELL TECHNIQUE 0 to SAMPLE a? United States Patent 4,577,691 issued to W. Huang and S. Chien of Texaco describes a system for producing bitumen or other viscous hydrocarbons by thermal stimulation through horizontal wells.

As shown in Figure 1, a tar sand layer 10 is - • - C provided with a series of horizontally arranged wells 13 to 17 inclusive. The number of vertically " øGrad* spaced wells actually needed will be a function of the overall thickness of productive layer 10 and the II • I • 1,1,1,1. 1 composition of the formation. Li Li LI 34 I-i SPECIFIC GRAVITY The wells 13 to 17 are spaced vertically apart to define a series of discrete productive layers. In such an arrangement, the productive layers are sequentially heated and produced one at a time. By thus limiting the volume of the productive area which is heated and produced, the heating medium Figures 1 and 2 show clearly that the higher the is utilized to optimal efficiency. specific gravity, the higher the cumulative bitumen recovery and the lower the cumulative bitumen By the selective and individual heating and produc- percentage grade will be. A similar trend was ob- ing of the separate layers, starting at the upper- served for the carbon content for both sample I most, downward flow of bitumen emulsion can be and II. For a bitumen recovery of 70%, a grade of withdrawn sequentially from the wells in descending 65% can be obtained for sample I and 60% for order. sample II. This fact suggests that a heavy medium cyclone technique may be used for large scale in- To commence production of bitumen emulsion from dustrial processing. Either magnetite or fer- the uppermost segment, the area between and rosilicon can be used as the heavy media.

3-31 SYNTHETIC FUELS REPORT, DECEMBER 1986 segment will be commenced. Over a period of time, as the horizontal layer between wells 14 and 15 is produced though well 15, the next lower ad- jacent segment will be subjected to preheating by way of well 16. As each successive horizontal formation layer be- comes depleted of bitumen, the upper liquid cap will be applied through the well at the upper edge of that layer. However, since steam is introduced to the lower edge of the horizontal segment the steam will be confined so that its use is most ef- fectively applied rather than being dissipated over a larger area. A preferred method for assuring production from a formation by horizontal segments, utilizes direc- tional introduction of the hot steam and the sub- sequent water. One embodiment of a well liner which is capable of handling both the stimulating and production functions, is illustrated in Figure 2.

FIGURE[ about the upper wells 13 and 14 is initially preheated to a predetermined temperature. The CROSS SECTION OF LINI :1; optimal temperature will depend on a number of WELL COMPLETION factors including the composition of the substrate as well as the underground temperature. 44 39 As injected steam causes the bitumen to become less viscous, it mixes with hot condensate into a flowable bitumen emulsion. This preheating period can extend over several weeks or even months and a will substantially increase the pressure within the horizontal layer. After the initial preheating, introduction of steam t'( through well 14 is discontinued. However, steam introduction is continued through well 13 and in- itiated in well 15. Since the pressure in well 14 ty*Saa4Weest will now be abruptly decreased, the flow of hot bitumen emulsion into the intermediate well 14 will commence. Ir, Thereafter, steam injection by way of well 13 will continue until it becomes apparent from the emul- sion production rate at well 14, that the top layer is substantially depleted of bitumen. This factor will become evident by the added outflow of steam at producing well 14. During this heating and producing period, steam in- troduction has been initiated, at a lower pressure, As shown, well liner 38 includes a plurality of by way of well 15 to heat the next lower con- elongated conductors 39 and 41 disposed one above tiguous horizontal layer. However, with the end of the other to define flow passages 42 and 43. Each the bitumen production through well 14, water is of these conductors is provided with ports or open- introduced by way of well 13 to form a liquid cap ings 44 and 46 formed in the walls. on the uppermost horizontal layer. Conductors 39 and 41 are joined along their length After the liquid water cap has been applied, pres- at a welded joint 45 to form a unitary member. surized steam injection will again be commenced by Openings 44 and 46 formed in the walls of the way of well 14. By reducing the pressure at well conductors are aligned to direct steam or water in 15, bitumen will be produced at that well while either an upward and outward or downward and concurrently heating of the next lower horizontal outward direction respectively. Thus, pressurized

3-32 SYNTHETIC FUELS REPORT, DECEMBER 1986 steam and water flows which issue from the respective conductors, will assume a desired direc- tion.

To facilitate registering liner 38 within a horizontal borehole, the dual conductor arrangement is provided with lateral protrusions in the form of side panels 48 and 49. The latter have a curved peripheral edge which conforms to the borehole walls.

To maintain the thermal quality of steam used in the formation stimulating function, compartments 53 and 54 can be provided with tracer lines to conduct a flow of steam. Thus, the temperature of the entire liner 38 can be maintained at a preferred operating level.

3-33 SYNTHETIC FUELS REPORT, DECEMBER 1986

INTERNATIONAL

CHINA SHOWS INCREASING INTEREST IN HEAVY Resources OIL AND OIL SANDS A paper presented by Ilu Jianyi of the Scientific Research Institute for Petroleum Exploration and Several cooperative undertakings between China and Development gave an overview of heavy oil, asphalt Canadian and U.S. groups have emerged in the past year. and oil sand resources in China.

Husky Oil was selected to advise and assist heavy The mainland of China can be divided into two crude exploration and development in the Xinjiang petroleum provinces the eastern petroleum province Province in China. The husky agreement with the near the Pacific Ocean and the western plateau Chinese National Technical Import Corporation is petroleum province. In the east, by the action of based on a project financed by the World Bank. Pacific plate subduction, o large rift action has oc- The work in Xinjiang, which is an isolated inland curred forming numerous asymmetric rift-valley area with very cold weather in winter and hot basins in the Meso-Cenozoic eras. In general, the summers, will involve bitumen more viscous than gentle slopes of these basins favor secondary heavy oil accumulations. In the western petroleum Cold Lake oil sand. The contract will involve four to eight months training in Husky facilities in province, the earth's crust has been thickened and Canada followed by some Husky experts working in formed numerous large intermontaae and fore- montane basins; the paleo-stratigraphic units near China. The contract also includes the design of the foldbeht have been strongly uplifted and many surface facilities for a commercial cyclic steaming project to produce 2,900 cubic meters per day, as paleo oil pools have been damaged, forming many asphalt, oil sands, and heavy oil deposits on the well as various pilot units for other reservoirs and the establishment of a heavy oil research west or northwest margins of some of these large laboratory. basins.

Chevron Figure i identifies the major asphalt, oil sands and heavy oil areas. Chevron recently concluded an agreement with Chinese authorities to provide assistance in the design and production of catalysts for the Shengli Refinery, close to the Shengli heavy crude field south of Beijing. Twelve Chinese engineers are working at Chevron facilities in California. The FIGURE 1 two heavy crude units to be built in the Shengli refinery are expected to go into operation by the ASPHALT, OIL SANDS AND middle of 1988. HEAVY OIL IN CHINA A 0 ST R A

In response to an invitation received from the I Chinese Ministry of Petroleum Industry, Alberta Oil ) t..--S,• . f?....; Sands Technology and Research Authority formed a six-man delegation, including members from AOSTRA staff, government research institutions and . .>".. Z private sectors, to visit China's heavy oil develop- ment last spring. This visit pertained principally to AOSTItA's cooperative programs with the Research Institute of Petroleum Exploration and Development N..:f t *t,..._ (RIPED) in Beijing, Xinjiang Petroleum Administra- • ra(.# / •:--'- tion (XPA), and Liaohe Petroleum Exploration H,-S• 0 ct " Bureau (LPEB). (t:r '- • D :.- While in China, a series of discussions and nego- tiations took place in order to develop a coopera- tive research program. Six cooperative research LII.* — - 5..bn eti, t fln rom-. ..qM.f —5.5 projects were finalized and an agreement between • Thfl —t ,. .1 US. e 7. S,$a. AOSTRA and RIPE[) was signed in June 1986, in S 5W5d t A, I, . .-*I pt *4 d Edmonton. • ,•_,

China sent a three-man delegation to Alberta and presented five technical papers at the 1986 AOSTRA conference on "Advances in Petroleum Recovery and Upgrading Technology", held in Cal- gary on June 12-13.

3-34 SYNTHETIC FUELS REPORT, DECEMBER 1986 The eastern petroleum province near the Pacific cm wide are found in sandstone and shale. Ocean includes the following: Many asphalt bodies can be found at Kuan- shanlian and Tianba areas. These asphalt - The western slope in Songliao basins: The and oil sands deposits have resulted from famous Daqing oilfield is located at the cen- deep oil reservoirs rising. In Guanguuan- ter of the basin. The specific gravity of Jiangyou region, a heavy oil reservoir exists crude oil changes from 0.84 in Daqing oil- in the Jurassic sandstone on the Dalianshan field in the center of the basin to 0.96 at structure at a depth of less than 1,000 m. the western margin. The non-hydrocarbon and asphaltcne fraction increases up to 47%. - Majiang asphalt deposit in Guizhou province: This asphalt deposit is a Paleo-oil reservoir - The western slope in Liaoxi depression: in the Majian anticline which covers 876 Numerous structural oilfields exist in the km 2 . At present, the asphalt is reservoired central part. In the western slope overlap in a Silurian sandstone with a width of 2 - belt, that is more than 100 km in length, 27.8 m. The asphalt content is ap- there are a series of heavy oilfields which proximately 1.0 - 5.6% and the amount of include the Gaosheng, Shuguang, Huanxiling, residual asphalt in place is estimated at ap- and Xibaquiah oilfields. proximately 350 million tons.

- The southern slope of Bingxian rise in the - Other asphalt deposits: highly metamor- Dongying depression: A series of heavy oil phosed asphalt and heavy oil seepages are reservoirs including the Shanjiasi and Lingfan- distributed widely in Paleozic and jia are present in this area. strata in southern China. For example, as- phalt veins are known to exist at more than - Gudao Oilfield: This field is located on the 50 sites in west Zhejiang and south Anhui eastern part of the Zhanhua depression. In provinces, most of them are being produced. addition, a series of heavy oil fields have been found near the mouth of the Yellow The occurrences of heavy oil, asphalt, and oil sands River. in China are derived from many different geologi- cal backgrounds. The systems of source rocks are - Ningjin heavy oil reservoir: On the slope of widely distributed over the strata of middle the Shulu depression, the units of the Proterozoic, Paleozoic, Mesozoic, and Cenozoic Oligocene Shahajie formation overlap older ages. As a result, asphalt, heavy oil, and oil sands strata. The oil has migrated from the lower are widely dispersed in strata of varying age. part of the depression to the margin. During migration, the oil was affected by During Meso-Cenozoic time, strong tectonic and contact with formation water and strongly faulting action changed the previous structures and oxidized. As a result, the oil has been created the geological conditions that led to the changed into a soft asphalt. formation of heavy oil and asphalt deposits.

The west plateau petroleum province includes the Based on the present knowledge of oil and gas, following: heavy oils account for 20% of China's total crude oil reserves. However, based on geological - Heavy oil and asphalt belt located in Junggar evidence, it is expected that the heavy oil Basin: The belt extends for 250 km and in- resources will exceed those of conventional light cludes numerous heavy oil and asphalt crude oil. Therefore, it is certain that heavy oils deposits such as oil sands and black oil hills, will constitute an important part of future asphalt , asphalt veins, etc. hydrocarbon energy resources in China.

Shiyougou heavy oilfield: This is an asphal- tic heavy oil reservoir, which became sealed and covered by asphalt and Quaternary sedi- ments. - Other heavy oil and asphalt deposits: The Ganchaigou and Youshashan (oil sands hill) at the western margin of the Qaidam basin and the Uuoyanshan tar sands are found in the Turpan basin.

The southwest petroleum province includes the following:

- heavy oil-asphalt deposits in the northwest Sichuan province: Asphalt deposits can be found in the Sinian-lower Paleozoic strata which extend for 160 km. Asphalt veins 10

3-35 SYNTHETIC FUELS REPORT, DECEMBER 1986 WATER

WATER TREATMENT NEEDS CALCULATED FOR U.S. Department of Energy. The organic carbon IN SITU TAR SANDS PRODUCTION material in the wastewater is predominantly Light carboxylic acids. Smelt amounts of alcohols, Several of the major tar sands deposits of the phenols, , and creosols were also identified. United States are located in and Western states. The major inorganic species present are ammonia Recovery of this resource will require large and sulfate. Unlike the in situ steam drive was- amounts of water, a commodity in short supply in tewaters, no standard wastewater treatment prac- that area. For this reason, DOE-sponsored work at tice exists for in situ combustion processes. the University of Wyoming has focused on require- ments for treating and recycling this water. A The wastewater was subjected to a variety of presentation to the 1986 DOE Tar Sand Symposium treatability studies performed by contractors. Of began by observing that the water requirements all the methods investigated, reverse osmosis and will depend upon the recovery and treatment biological treatment with activated sludge seemed processes selected. It is estimated that at least to be the most effective. 85% of the tar sand resource in the United States occurs at depths that favor in situ recovery. Two Reverse osmosis successfully concentrated the or- methods to accomplish this are high-temperature ganic and inorganic constituents into a brine. Up steam injection and in situ combustion. Water to 98% of the total organic carbon was removed balances were worked out for both of these from the permeate. Biological treatment removed methods. 97% of the biological oxygen demand, 100% of the phenol, and 9396 of the ammonia. In Situ Steam Drive The reverse osmosis treatment requires several The amount of water, as steam, that must be in- pretreatment steps to protect the membranes from jected into a reservoir to produce one barrel of plugging. Pressure sand filtration is used to bitumen has been shown to range from 2.5 to 11 remove suspended solids. Weak acid ion exchange barrels. The high water demands associated with removes calcium and magnesium ions that might steam drive production can be reduced by recycling otherwise form insoluble salts. Disinfection with wastewater to the steam generator. chlorine prevents microbial growth. The brine resulting from reverse osmosis, representing about The hot-lime softening process is the standard 25% of the total effluent, requires further treat- method in Canada for treating in situ steam drive ment. wastewaters. The oil in the wastewater is reduced by gravity separation, followed by induced gas The unit operations required for biological treat- flotation and pressure sand filtration. The hot-lime ment of the combustion wastewater include the ac- softening process is then used in a pressure vessel tivated sludge reactor, a sludge settling basin, a at temperatures between 100 and 115 0 C. Lime and sludge thickening basin, and some form of sludge magnesium carbonate are added to the wastewater disposal. to precipitate calcium, magnesium, and silica. The effluent from the hot-lime reactor is passed Water Balances through an anthracite filter to remove floc. Residual hardness is then removed by ion exchange. Water balances prepared for each of the four The final treatment step is the addition of an treatment processes reveal significant differences in oxygen scavenger to bond dissolved oxygen in the makeup water requirements (Table 1). The makeup feedwater. water demands for the two treatment options con- sidered for in situ steam drive production are 1980 Strong acid ion exchange has been used in Canada gpm for the hot-lime softening treatment and 2150 as an alternative to hot-lime softening. Unlike gpm for the strong acid ion exchange treatment. hot-lime softening, strong acid ion exchange does The major difference in water requirements for the not remove silica; however, an advantage of the two processes is that 150 gpm are used to back- strong acid ion exchange treatment over the hot- wash the anthracite filters and perform the hot- lime softening process is the elimination of the lime softening step, whereas 320 gpm are used to lime sludge and the associated sludge lagoons. backwash, regenerate, and rinse the strong acid ion exchange beds. In Situ Combustion The makeup water demands for in situ combustion In situ combustion produces about two barrels of are much smaller. Not only is there no water lost wastewater for each barrel of bitumen. One barrel to the geological formation as in the case of steam of water results from the combustion process, and drive production, but there is water produced by the other originates from water injected for steam the combustion process. Only 580 gpm of makeup stimulation of production wells. water are thus required for biological oxidation. Moreover, the quality of the water from this An analysis of wastewater produced by in situ treatment may be high enough to meet effluent combustion of tar sand has been performed by the discharge standards. Reverse osmosis yields a

3-36 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 The selection of an appropriate wastewater treat- ment is governed not only by makeup water requirements, but also by treatment costs. MAKEUP WATER REQUIREMENT FOR BITUMEN RECOVERY PROCESSES It was estimated that the cost of treating was- tewaters per barrel of bitumen produced at a Water 20,000 bpd in situ steam drive tar sand facility Requirements Recovery Process would be $2.77 for the hot-lime softening process and Water Treatment Gal/Mm and $1.11 for the strong acid ion exchange process.

In Situ Steam Drive The corresponding costs at an in situ combustion Hot Lime Softening 1,980 facility were estimated to be $0.25 for biological Strong Acid Ion Exchange 2,150 treatment and $0.37 for reverse osmosis treatment.

In Situ Combustion 580 Biological Treatment Reverse Osmosis 0

water of even higher quality. The reverse osmosis effluent may be suitable for recycling to the steam generators, resulting in a net zero water demand.

The amount of wastewater to be treated from the In situ combustion process is much less than that from in situ steam drive. For example, the was- tewater treatment systems for in situ combustion receive only about 1,200 gpm, compared with 6,700 gpm for in situ steam drive systems (Table 2).

TABLE 2

AMOUNT OF WATER REQUIRING TREATMENT FOR BITUMEN RECOVERY PROCESSES

Amount of Recovery Process Water Requiring and Water Treatment Treatment (GPM

In Situ Steam Drive Hot Lime Softening 6600 Strong Acid Ion Exchange 6800

In Situ Combustion Biological Treatment 1200 Reverse Osmosis 1200

3-37 SYNTHETIC FUELS REPORT, DECEMBER 1986 RESOURCE

TAR SAND UNITS DISSOLVED, FORMED UTAII TAR SANDS RESOURCES TO BE MAPPED

Termination of PR Spring Tar Sands Unit The Utah Engineering Experiment Station is direct- ing a new study of tar sands in the Uinta basin of Mobil Oil Corporation, as unit operator, has northeastern Utah. notified the State of Utah that all of the working interest owners to the PR Spring Tar Sands Unit A $47,000 study is being co-funded by the Univer- wish to terminate the Unit Agreement. Such ac- sity of Utah and the State Department of Com- tion is allowable under the terms of the agreement. munity and Economic Development.

State leases that were committed to the PR Spring The Utah Geological and Mineral Survey plans to Unit are as follow: publish the study results next year. The study will map some 25 known deposits, examine their poten- Kerr McGee Corp ML 19899 tial for economic development and address en- Kerr-McGee Center ML 19900 vironmental concerns. Oklahoma City, OK 74125 ML 19901 (IL 19905-A ML 20888 ML 20889 ML 20890 ML 20892 TRAPPER CANYON DEPOSIT ILLUSTRATES ML 21900 TRAVAILS OF TAR SAND DEVELOPMENT ML 21908 ML 21909 The identification of a mineral deposit is often the least complex step in the process of mineral Texaco Inc. ML 27721 development. This is clearly illustrated by a his- Alternate Energy & Resources tory of attempts to put together a project in the 1670 Broadway, Suite 3033 Trapper Canyon Tar Sand Deposit in Big Horn Denver, CO 00202 County, Wyoming (Figure 1). The discussion was provided by the U.S. Bureau of Land Management These lenses may be extended for two years from at the U.S. Department of Energy 1986 Tar Sand the current date. Symposium held in Jackson, Wyoming.

Nutter Ranch Tar Sand Unit FIGURE 1 The Nutter Ranch Tar Sand Unit Agreement, Carbon County, Utah was approved on September 10, 1986 by the Bureau of Land Management. This LOCATION OF TRAPPER CANYON unit encompasses 41,908 acres in which applications TAR SAND DEPOSIT (at x) to convert certain Federal oil and gas leases to combined hydrocarbon leases are pending and the unit is effective when the conversion applications are concluded. MONTANA

This unit agreement has been designated No.

UT060P49-86U703 by BLM and the following num- BIG HORN BASIN STUDY AREA 0 bered state leases have been committed to the I 0 unit: r 2 It,/c 0 ML 39826 ML 30827 ML 40864 ML 40865 ML 41022 4 — WYOMING. Cd, ML 42476 4 ML 42892 0 L Lii UTAH COLORADO

3-38 SYNTHETIC FUELS REPORT, DECEMBER 1986

The Big Horn Basin lies in northcentral Wyoming On December 5, 1963, the Yellow Dog mining surrounded by volcanic platforms and uplifted claimants protested the proposed sale. Following mountain ranges. The Trapper Canyon deposit is review, the Director's Office of the USGS cancelled located on the west flank of the Bighorn Moun- the proposed competitive lease sale. tains 17 miles north of Hyattville, Wyoming (Figure 1). Trapper Canyon is one of a number of steep A validity examination was then initiated on June canyons that cut Paleozic strata along the west 26, 1964 on Yellow Dog mining claims. During the slope of the Bighorn Mountains. The study area examination, the claimants indicated that substan- has a long-standing claim history dating back to tial technical material would be forthcoming as the late 1800's; modern use conflicts have occurred well as the imminent construction of a processing almost continuously since 1960. plant.

The Paleozie oil and gas accumulations of the Big The USGS continued to monitor the status of the Horn basin have stimulated considerable interest application for the asphalt lease between 1963- and research for many years. Little interest has 1968. In 1969, the applicant indicated that he had been generated in the development of tar sand a "continuing interest" in the application. deposits in the basin because of abundant light hydrocarbon resources. In 1972 the BLM was directed to conduct another validity examination of the involved claims. While The tar sand deposits located in T52N,R89W, Sec- samples were collected, analyzed, and the deposit tion 33, 6th P.M., Wyoming, have been recognized assessed (see Figure 2), records indicate that this since the early twentieth century. examination was never completed.

Mining Claim History

An examination of the mining and mineral records contained in the Big Horn County Courthouse in FIGURE 2 Basin, Wyoming, indicates that efforts to establish rights on the deposit began under the General Min- HYDROCARBON RESOURCE ing Law of 1872. The first effort to initiate rights was begun on October 12, 1905, when a W. W. POTENTIAL OF THE Peay located a placer mining claim. TRAPPER CANYON AREA Eighty years and 107 location notices later show BOI)Y IftDROMWc*l POTEWflM. Zota that under the Mining Law, the area remains one of potential rather than current value. Only about one-third of these location notices reflected multi- I year interest in any of the mineral resources lo- • I cated and of these, only two location groups 'I • T'.'t' I showed consistent long-term interest in the area: S 9 9 9 - Yellow Dog 1-4 placer claims; for asphalt, located July 29, 1959 with annual assess- ments performed 1960-1971, and SSSSIa

- Mid-Day 1-4 placer mining claims; for un- common sand, located on April 14, 1974 with \ MEDIUM annual assessments performed 1974-1981. The failure to conduct annual assessments in 1981-1982 led to the decision by the BLM, in 0 1983, to declare the mining claims abandoned S and void. Subsequently, the Mid-Day Num- bers 1-4 were located again by the same I claimants and annual assessment performed I for the assessment year 1984-1985. ICH POTENTIAL I Asphalt Leasing Versus Mining Claim Location I I Leasing interest in the hydrocarbons of the area has also had a varied and substantial history. On / December 27, 1962, an asphalt lease was requested LOW on lands in Section 33. It was determined by the POTENTIAL USGS that the asphalt lease should be offered competitively and set terms for that competitive lease. The competitive lease sale was announced RtIW IR*WI tp.,wI on December 3, 1963.

3-39 SYNTHETIC FUELS REPORT, DECEMBER 1986

Finally, in November of 1981, the third validity ex- damages and the value of the resource removed amination of mining claims in Section 33 was continue today. begun. The Mid-Day, Silica Sands and Black Ore claims formed the subject of this examination; the Other Resource Values latter two claims groups having been located in the intervening years. The Yellow Dog claims were In order to assess the impact of tar sands not recorded with the BLM under provisions of the development on coincident resource values, the Federal Land Policy and Management Act of 1976 southeastern portion of the Big Horn Basin has (FLPMA), and had been extinguished. in April, been studied as part of a forthcoming BLM 1982 the examiner recommended that the Mid-Day, Resource Management Plan. Any future develop- Black Ore, and Silica Sands claims be contested in ment proposal will need to address impacts to their entirety. The BLM's Wyoming State Office three coincident resource areas: the Trapper chose to issue a decision declaring these mining Canyon Wilderness Study Area, the existence of ad- claims abandonded and void for failure to file jacent habitat suitable for reintroduction of evidence of annual assessment work. This left the threatened and endangered species, and the Spanish question of validity a moot point. Point Kant Area. The BLM informed the asphalt lease applicant on The Spanish Point Karst Area meets criteria for October 4, 1982, that the provisions of Public Law designation as an Area of Critical Environmental 97-78, effective November 16, 1981, had repealed Concern. The karat topography provides the basis the Bureaus authority to issue leases for asphalt. for two significant resources of national and regional value: caves and recharge areas for the Oil And Gas Leasing Madison aquifer. The present oil and gas lessee, Bronco Oil and Hurdles to Development of the Trapper Canyon Gas Company, acquired its interest through assign- Deposit ment July 1, 1980. Bronco initiated mine and process feasibility studies on the tar sand resources Having examined the development history and en- approximately at the time of assignment. Bronco vironmental context of the area, the BLM iden- subsequently proceeded to initiate an experimental tified a series of hurdles that would have to be oil recovery program to demonstrate the "natural overcome in order for development of Trapper flow" requirement set up by the Department of In- Canyon to proceed during favorable economic terior. times. Experimental Oil Recovery Program The first hurdle is that there are no Special Tar Sand Leasing Areas (STSLA) outside of the State of Communication between fluids injected and Utah. Congressional designation of new Special Tar recovered were to constitute the vehicle for Sand Leasing Areas is the only present remedy to demonstrating that formation oil could be drawn this deficiency in the Combined Hydrocarbon Leas- from the reservoir. The temperature of the in- ing Act of 1981. jected water was selected to distinguish secondary from tertiary recovery methods. The average A second hurdle is that present tar sand deposits reservoir temperature of the formation containing outside of the state of Utah lying within oil and the tar sands was to be the upper temperature gas leases that administratively predate November limit for the injected waters. Reservoir tempera- 16, 1981, must be processed as conventional oil and ture for the Tensleep Sandstone in and around the gas leases. The only way around this hurdle at Big thorn Basin averaged 1200F. present would be to show through some unconven- tional oil-recovery demonstration that utilized Communication was never achieved between the in- primary or secondary oil stimulation techniques that jection hole and the recovery hole. the hydrocarbons will flow "naturally", satisfying the definition as a pre-November 16, 1981 'oil". The lessee subsequently was granted an extension of the lease to permit a second experimental test, The last hurdle is that there are numerous en- this time with another injection medium, propane. vironmentally sensitive resources in the immediate This test is still pending. vicinity of the tar sand resources; these other resources may present an obstacle to commer- Unauthorized Use cializing tar sand resources. In August and September of 1981, unauthorized use The BLM analysis concludes that perhaps the only was instituted by Big Horn Tar Sand and Oil, Inc. way to develop the Trapper Canyon deposit would This group, using improper location notices for be to have congress designate it as a Special Tar petroleum and other hydrocarbons, proceeded to ex- Sand Leasing Area. Conversion procedures (from cavate a mine pit, set up a processing system, and oil and gas lease to combined hydrocarbon lease) produce oil from the deposit. The authority was would then require a plan of operation that conver- subsequently challenged, cease and desist order sion applicants would have to follow to satisfy en- given, and trespass notice served on Big Horn Tar vironmental concerns. Sands and Oil, Inc. Attempts to recover trespass

3-40 SYNTHETIC FUELS REPORT, DECEMBER 1986 RECENT OIL SANDS PUBLICATIONS/PATENTS

The following papers were presented at the 1986 Annual Meeting of the American Institute Of Chemical Engineers in Miami Beach, Florida, November 2-7, 1986:

Curtis, C.W., et al, "An Examination of the Role of Hydrogen Donation in C op r oces s lug.

Desoiza, C., et al, "Reaction Kinetics and Demetallation in Heavy Oil Processing."

Gray, M.R., et at, "Structural Kinetics of Gas Formation During Hydroprocessing of Heavy Gas Oil."

The following papers were presented at the 36th Canadian Chemical Engineering Con- ference in Sarnia, Ontario, Canada, October 5-8, 1986:

Bane rjee, D.K. , et al, "Kinetics of Bitumen Pyrolysis in the Presence of Sulfur."

Simpson, P., "Donor Solvent Bitumen Upgrading."

Chantal, P., et al, "Adsorption of Nitrogenous Type Compounds from Syn- thetic Crude Fractions into Various Sorbents.

Tiwari, P.M., et al, "Distribution of Products in the Maltene Fraction Derived from the Hydrocracking of Heavy Oil: Thermal, Catalytic and Hydrogen Donor Effects."

The following papers were presented at the 1986 Eastern Oil Shale Symposium held in Lexington, Kentucky, November 19-21, 1986:

Omana, ft., et al, "The Economic Outlook of Heavy Crude.

Westoff, J.D., et al, "U.S. Department of Energy Tar Sand Program Over- view."

Vello, A.K., "Appraisal of the Technical and Economic Potential of U.S. Tar Sands."

Mason, G.M., et al, "Mineralogy of the PR Spring Tar Sand Deposit, Uinta Basin, Utah."

Crawford, P.8., et at, "Thermal Oil Recovery Experiments on Texas Tar Sands and Heavy Crude Oils."

Harrison, W.E. Ill, "Aviation Turbine Fuels Produced from Kentucky and Utah Tar Sands."

Misra, M, et al, "Development of Integrated Processes for the Separation of Bitumen from Alabama Tar Sands."

Babcok, R.E., et al, "Wood-Beaver Process Pilot Plant for the Extraction of a Southern Oklahoma Surface-Mined Tar Sand."

The following papers were presented at the 21st lntersociety Energy Conversion En- gineering Conference held in San Diego, California, August 25-29, 1986:

Marchin, L.M. , et al, "Surface Characteristics of Reservoir Matrices Sub- ject to Enhanced Oil Recovery Process Design."

Gonzalez, G . , "Adsorption of Asphalteaes and Resins onto and ,"

3-41 SYNTHETIC FUELS REPORT, DECEMBER 1986 OIL SANDS - PATENTS

"Hydroconversion of Heavy Oils", Diwakar Garg - Inventor, Air Products and Chemicals Inc., United States Patent 4,606,809, August 10, 1986. High yields of desired dis- tillate oil are obtained by subjecting heavy oil to catalytic conversion with hydrogen at superatmospheric pressure in a temperature staged process, wherein the oil-catalyst slurry is subjected in the initial stage to a temperature In the range of 780°-825 0 F. (4150-4400 C,), and in a subsequent stage to a temperature which is at least 20 0 F. higher than that employed in the previous stage, preferably in the range of 800 0 -860 0 F. (4250-4600 C.

"Combined Replacement Drive Process for Oil Recovery", Caurino C. Bombardiari and Alec Rakach - Inventors, Exxon Production Research Company, United States Patent 4,612,089, September 23, 1986. Performing steam drive operations in critical manipulative steps can improve the recovery of viscous hydrocarbons from tar sand deposits. Steam is injected into an injection well at a rate that is less than the rate needed to fracture the formation, and fluids are simultaneously produced from a communicating production well. When steam breakthrough occurs at the production well, the production well is shut-in, and the injection rate is increased to a rate at least sufficient to fracture the formation. After the reservoir is sufficiently heated, injection ceases and production resumes. Once the production rate declines to a rate that is no longer efficient, the process can be repeated.

3-42 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS

COMMERCIAL PROJECTS

ATHABASCA PROJECT - Solv-Ex Corporation and Shell Canada Limited (T-01) The project is a joint venture of Solv-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 1)

81-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 Lloydminster, Saskatchewan. The facility will be designed to process 54,000 barrels per day of heavy oil and bitumen from the Lloydminster and Cold Lake deposits. The primary upgrading technology to be used at the upgrader will be H-Oil ebullated bed hydrocracking followed by delayed coking of the hydrocracker 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-Simmons 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 Suncor 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.

3..43 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 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 was to result in an ultimate capacity of 25,000 barrels per day from a total of 2,000 wells. However, in the Fall 1987 Suncor put the project on hold. Project Cost: $1.3 billion CALIFORNIA TAR SANDS DEVELOPMENT PROJECT -- California Tar Sands Development Corporation (T-06) California Tar Sands is developing a downhole 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 pressures led to a severe curtailment of expenditures in 1982. Canstar has continued at a reduced level of activity since then. Nova and Petro-Canada decided in early 1986 to suspend further expenditures on Canstar. 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: Approximately $500 million for first six phases 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 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.

3.44 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

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 cast of Edmonton, Alberta. Amoco Canada holds a 100 percent working interest in 6,600 hectares of oil sands leases in the area. The Phase I 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 Sparky. Amoco Canada has several development phases of the Elk Point Project. Phase 1 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 I 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 0 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 six injection wells taking 75 tons per day 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 ERCB 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! 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 day by 1991. Phase III 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. 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

3-45 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

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 was planned 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. Due to the dramatic decline of oil prices, drilling on the first phase of the commercial project has been halted after 31 wells were completed. These wells have been placed on primary production. Steaming, gathering, and processing equipment was committed prior to the oil price decline, and is being stored for use when the oil price recovers. Project Cost: $158 Million LINDBERGH COMMERCIAL THERMAL RECOVERY PROJECT-- Murphy Oil Company Ltd. (T-33) Murphy Oil Company Ltd., has completed construction of the first phase of its 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 construction of the commercial expansion involved the addition of 53 wells and construction of an oil plant, water plant, and water source intake and line from the north Saskatchewan River. Startup of the new wells has been postponed pending satisfactory oil pricing. However, pilot operations are continuing and oil from the new plant. 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 0API, and oil viscosity at the reservoir temperature is 30,000 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 was $29 million (Canadian) for the initial installations, with about $6 million in capital additions expected 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 III in 1990, and Phase IV in 1992. Total production from all four phases would be 10,000 barrels per day. Project Cost: Phase I -$29 million (Canadian) capital 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 day 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. NewOrade 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

3-46 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

PEACE RIVER COMMERCIAL EXPANSION -- Shell Canada Limited (T-35.5) Shell Canada Limited expanded the existing Peace River In Situ Pilot Project to an average production rate of 10,000 barrels per day. The expansion is 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 cost of $200 million, required the drilling of an additional 216 wells for steam injection and bitumen production, plus an expanded distribution and gathering system. Wells for the expansion were drilled directionally from eight common pads. The commercial project includes an expanded main complex to include facilities for separating water, gas, and bitumen; a utility plant for generating steam; and office structures. Additional off-site facilities were 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 was on stream October 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 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 1994. 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 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 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 produeton 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

3-47 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

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 1 kilometer northwest of Unit A. Unit A is being financed by Devran and Shell Canada. Devran received a $475,000 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. Engineering, procurement, and project management are being conducted by James Wade EnLincerinit Ltd. of

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. 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

3-48 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

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 GNC 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 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°API 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 day. In response to a solicitation by the United States Synthetic Fuels Corporation (SFC) 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. -- Esso Resources Canada Limited (25.0 percent); Petro-Canada Inc. (17.0 percent); Alberta Oil Sands Equity (16.74 percent); Canadian Ltd. (13.23 percent); Alberta Energy Company (10.0 percent); Gulf Canada Resources Inc. (9.03 percent); Dome Petroleum Limited (5.0 percent); PanCanadian Petroleum Limited (4.0 percent) (T-60) Located near Ft. McMurray, the plant has an allowable production of 138,600 barrels per calendar day; 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 $1.5 billion debottlenecking and capacity addition project (expansion) will increase synthetic crude oil production to 138,600 barrels per day. The expansion is expected to be complete by 1989. Project Cost: Total cost $2.3 billion (1978 cost) 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 wells began October 15, 1983 and the initial 192 wells were complete in early July 1984, 7.5 months ahead of schedule.

3-49 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

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 (10°API) 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. UP 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 developments. In March 1986 they awarded a contract for the front-end engineering design of the second phase of the Wolf Lake project to Bantrel Group Engineers Ltd. The design provides a cost estimate for the project and a lump-sum bid package. A decision on whether to proceed with construction of the second phase will be taken during the first half 1987. Phase 2 of the Wolf Lake project has a design production capacity of 2,000 cubic meters per day (13,000 barrels per day) over its 25 year life. It will require the drilling of 248 wells initially, located on 14 satellites. On average, 32 additional wells will be drilled each year following completion. The total number of wells to be drilled over the project's life will be JJfl. Wolf Lake Phase 2 would be followed by Phases 3 and 4. BP'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: Wolf Lake 1 $114 million (Canadian) initial capital (Additional $750 million over 25 years for additional drilling) Wolf Lake 2 $200 million (Canadian) initial capital

R&D

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 6 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

ASPHALT RIDGE TAR SANDS PILOT PLANT - Sam Arentz (T-120) A surface mining project, originally proposed by Sohio, located on approximately 8,550 acres in Uintah County, Utah. Process selection and development work and economic feasibility studies were on hold by Sohio, pending resolution of litigation and improvement in market. Several unpatented mining claims were patented. Application

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

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, S 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 1 injector. There are 2 observation wells inside the pattern and 4 outside the pattern.

TIn 1987, the second pattern will undergo an expansion, with 4 producers, 2 injectors, and 1 observation well being ded. Project Cost: $115 million (estimate) BATFRUM 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. ERCB 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) CANMET HYDROCRACECING 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 CANMET additive. 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

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

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 152 and R23, W3M in the Celtic Field, northeast of Lloydminster. 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 have now been drilled and tested by steam cycling. Production from the first well was very encouraginp hnwp vr rp ci,ltc frn,n thnennnnd wall a..a

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. (1-230) 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 wells in 1985. Various zones are being tested in the Upper and Lower Grand Rapids formation. The tests are scattered throughout Mobil's leases in Townships 63 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 PROCESSIs - Gulf Canada Limited, the Alberta Oil Sands Technology and Research Authority, and L'Association pour 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 (DRB) process for upgrading heavy oil or bitumen.

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

About 12,000 barrels of Athabasca bitumen from the Syncrude plant were shipped to the ASVAHL facilities near Lyon, Prance. Beginning in October 1986 tests will be conducted in a 450 barrel per day pilot plant through 1996 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 DEB 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 off-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 (IITRI) 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 thy, 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 farmout 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 thy were achieved. Tar sales were approximately 150 to 200 barrels per day. 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. (T-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

3-53 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

Sections 5 through 8-65-3W4. 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 thy—i.e., about 19,500 barrels per day of bitumen. 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: Not disclosed 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 wells, 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— Suncor, Inc. and Worldwide Energy Corporation (T-290) Canadian Worldwide Energy Ltd. and Suneor, 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 12.50API, and a sulfur content of 3.5 percent. The project utilizes huff and puff, with stearndrive 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 steamdrive. 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 due to low oil prices. Approximately 69 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 delayed. Ultimate recoveries are anticipated to be greater than 21 percent with recoveries in the 26 percent range in the steamflood areas expected. 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 srru 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 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 (0.68 acres). Observation wells will also be drilled. The

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

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 be 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 was 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 otthe 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 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. A steam drive from the center well was tested from 1980 to 1983 but has been terminated. Huff-and-puff continues. 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 11 0API and has a viscosity of 30,000 Cp at 70°F. Porosity is 33 percent and permeability is 2500 md. (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 (T-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.

3_55 SYNTHETIC FUELS REPORT, DECEMBER 1996 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

Air was injected into one pattern to facilitate sufficient burn volume around the welibore prior to switching over to enriched air injection in July 1982. Oxygen breakthrough to the producing wells resulted in the shut down of oxygen injection. A concerted plan of steam stimulating the producers and injecting straight air into this pattern was undertaken during the next several years. Enriched air injection was reinitiated in this pattern in August 1985. The blend-up process has been completed with present injection rate at 110 million cubic feet per thy of 100 percent pure oxygen. The burning in this pattern is proceeding without any oxygen breakthrough. 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; 31' Resources - 20 percent, Dome Petroleum Ltd. (formerly Hudson's Bay Oil and Gas) - 17.5 percent; PanCanadian Petroleum Ltd. -12.5 percent (T-390) OP 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 450 meters. The pilot initially consisted of four 5-spot well patterns with 5-acres per well spacing, plus four "out-of-pattern" test wells. Five infill wells were drilled in 1981 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 810 sand of the Lower Grand Rapids Formation (B Unit), 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. 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 1914, and has allowed the

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

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 steamdrive 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 steamdrive. Located 35 kilometers northwest of North Battleford near the community of Meota, the heavy oil pilot project tested a cyclic steam stimulation process followed by conversion to steam 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 provide for production enhancements and prior to the initiation of burning with air as the injection medium. To date, six of the nine patterns have been ignited and are on continual air injection. 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, is now underway. This phase includes a multi- cycle single well steam simulation test at 13-27-84-11 W4 now in its third production cycle and a second multi- cycle single well steam stimulation test at 16-27-84-11 W4 in its fourth 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. Initial water and steam injection to recover bitumen started October 31, 1979.

3-57 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

The well pattern is a 7-7 spot with each pattern covering an area of 2.8 hetares. 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 meters per day. An application to the ERCB 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. The pilot has now been fully integrated into the expansion project. The entire project is now known as the Peace River Complex. (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 April 1986, the fireflood operation was shut down and the project converted to steam stimulation. Sixteen pilot wells were cyclic steamed. One pattern was converted to a steam drive, another pattern converted to a water drive. Remaining wells retained on production. 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 5 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 Solv-Ex Corporation (the operator) and Enercor, 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.

3-58 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1985)

In August 1985 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, 1985 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 catalytic hydrotreating. A pilot plant of the series of hydroprocessing, i.e., visbreaking-demetallation-cracking, was completed in 1984. Its capacity is 5 barrels per thy, 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 lies 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 #0980090001 (formerly BSL #30) consists of 15,086 hectares (37,715 acres), situated 43 kilometers (26 miles) north of Fort McMurray on the east side of the Athabasca River.

359 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 1986)

Under terms of the farmout agreement, Gulf, through expenditures totalling some $42 million, can earn up to an 83.75 percent interest in the lease with Home retaining 10 percent and 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-10 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 commerciability of the project. Project Cost: Not disclosed SOUTH KINSELLA (I{lNSELtA 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- 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. 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. 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)

3-60 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 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. A ecologic field study was com pleted in Se ptember 1986: additional field work is alarmed for 1987. In res ponse to

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 kiln 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 (UWRC) 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).

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

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. • 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. operated an experimental in situ recovery project located within Section 15-88-8 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 I). 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 ID, 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 Ill). During 1984 and 1985, equipment was installed in both of the outside horizontal wells. The pilot was terminated September 1986. 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 day of 80 percent quality steam are injected into each well. Two portable natural gas-fired 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 60°F. 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

3-62 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF OIL SANDS PROJECTS (Underline denotes changes since September 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 with reserves on the lease estimated at 325 million barrels. Exploratory drilling was done 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, with the additional work done by J. S. Redpath, approximately 1 kilometer of tunnel is in place. An innovative underground drilling machine has been fabricated for the project and is currently undergoing surface testing at Exshaw, Alberta. 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 (T-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 permeability is 3.17 mKm 2. Temperature ranges from 279° to 281°K; porosity is 26 0; oil saturation is 87 percent of the pore volume or 10 percent by weight. Viscosity of oil varies from 15,000 to 20,000 mPa 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 wells 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

3-63 SYNTHETIC FUELS REPORT, DECEMBER 1986 COMPLETED AND SUSPENDED PROJECTS

Project Sponsor Last Appearance in SVR 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 Ladd Petroleum Corporation June 1985; page 3-51 Development Project Kentucky Tar Sands Project Texas Gas Development June 1985; page 3-52 Lloydminster Fireflood 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.

3-64 SYNTHETIC FUELS REPORT, DECEMBER 1986 Last Appearance in SFR

Primrose-Kirby Project Petro-Canada June 1986; page 3-56 Resdeln Project Gulf Canada Resources Inc. March 1983; page 3-43 R. F. Heating Project LIT Research Institute March 1983; page 3-43 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. September1980; page 3-61 Whiterocks Oil Sand Project Enercor December 1983; page 3-55 Hinge-line Overthrust Oil & Gas Corp. Rocky Mountain Exploration Company "200" Sand Steamflood Demon- Santa Fe Energy Company June 1986; page 3-62 stration Project United States Department of Energy

3-65 SYNTHETIC FUELS REPORT, DECEMBER 1986 S.TATUS OF OIL SANDS PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

Alberta Energy Company Ipiatik Lake Project 3-55 Suffield Heavy Oil Pilot 3-60 Syncrude Canada Ltd. 3-49 Alberta Oil Sands Equity Syncrude Canada Ltd. 3-49 Altex Oil Corporation Santa Fe Tar Sand Triangle Project 3-60 Amoco Canada Ltd. Elk Point Project 3-45 GLISP Project 3-54 Peace River In Situ Pilot Project 3-57 Alberta Oil Sands Technology ABC Cold Lake Pilot 3-50 and Research Authority (AOSTRA) Athabasca In Situ Pilot Plant 3-51 Donor Refined Bitumen Process 3-52 CUSP Project 3-54 Marguerite Lake Phase A Project 3-56 Marguerite Lake "B" Unit Experimental Test 3-56 Peace River In Situ Pilot Project 3-57 Suffield Heavy Oil Pilot 3-60 Taciuk Process Pilot 3-61 Underground Test Facility Project 3-83 Arentz, Sam Asphalt Ridge tar Sands Pilot Plant 3-50 Bow Valley Industries, Inc. ABC Cold Lake Pilot 3-50 UP Resources Canada Ltd. Marguerite Lake Phase A Pilot Plant 3-56 Marguerite Lake "B" Unit Experimental Test 3-56 Wolf Lake Project 3-49 California Tar Sands Development Corp. California Tar Sands Development Project 3-44 Canada Centre for Mineral & Energy CAN MET Hydroeracking Process 3-51 Technology

Canada Cities Service, Ltd. Eyehill In Situ Steam Project 3-54 PCEJ Project 3-57 Canadian Occidental Petroleum, Ltd. Syncrude Canada Ltd. 3-49 Canadian Reserve Oil & Gas Ltd. Eyehill In Situ Steam Project 3-54 Canadian Worldwide Energy Ltd. Charlotte Lake Project 3-52 Muriel Lake Project 3-57 Canterra Energy Ltd. Athabasca In Situ Pilot Project 3-51 Meota Steam Drive Project 3-56 Chevron Canada Resources Ltd. Beaver Crossing Thermal Recovery Pilot 3-51 Cold Lake Heavy Oil Ltd. ABC Cold Lake Pilot 3-50 Conoco Inc. Conoco South Texas Tar Sands Project 3-60 Consumers Co-Operative Refineries Ltd. NewGrade Heavy Oil Upgrader 3-46 Devran Petroleum Ltd. Sarnia-London Road Field Mining Assisted Project 3-47

3-66 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Dome Petroleum Canada Ltd. Lindbergh Commercial Project 3-46 Lindbergh Thermal Project 3-55 Marguerite Lake Phase A Project 3-56 Morgan Combination Thermal Drive Project 3-57 Primrose Lake Commercial Project 3-47 South Kinsella (Kinsella 8) 3-60 Suffield Heavy Oil Pilot 3-60 Syncrude Canada Ltd. 3-49 Enercor Cedar Camp Tar Sand Project 3-52 PR Springs Project 3-58 Enpex Corporation Enpex Syntaro Project 3-53 Esso Resources Canada Ltd. Cold Lake Project 3-44 Esso Cold Lake Pilot Projects 3-53 PCEJ Project 3-57 Syncrude Canada Ltd. 3-49 General Petroleum Company of Egypt Ras Gharib Thermal Pilot 3-59 Getty Oil Company Enpex Syntaro Project 3-53 GNC Tar Sands Corporation Sunnyside Project 3-49 Greenwich Oil Corporation Forest Hill Project 3-45 Gulf Canada Resources Ltd. Donor Refined Bitumen Process 3-52 Pelican-Wabasca Project 3-58 Sandalta 3_59 Syncrude Canada Ltd. 3_49 Home Oil Company Sandalta 3-59 Husky Oil, Ltd. Bi-ProvincialProject-Upgrader Facility 3-43 Lloydminster Regional Upgrader 3-43 Tucker Lake Pilot Project 3-62 Japanese Ministry of International RAPAD Bitumen Upgrading Project 3-59 Trade and Industry Japan Canada Oil Sands, Ltd. PCEJ Project 3-57 Kenoco Corporation Kenoco Project 3-55 Kirkwood Oil and Gas Company Circle Cliffs Project 3-52 Tar Sand Triangle 3-61 L'Association pour Is Valorization Donor Refined Bitumen Process 3-52 des Huiles Lourdes (ASVAHL)

Mobil Oil Canada Ltd. Battrum In Situ Wet Combustion Project 3-51 Celtic Heavy Oil Wet Combustion 3-52 Cold Lake Steam Stimultation Program 3-52 Fosterton N.W. In Situ Wet Combustion 3-54 Sandalta 3-59 Mono Power Cedar Camp Tar Sand Project 3-52 Murphy Oil Canada Ltd. Eyehill In Situ Steam Project 3-54 Lindbergh Commercial Thermal Recovery Project 3-46 Lindbergh Steam Project 3-55

3-67 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

NewGrade Energy Inc. NewGrade Heavy Oil Upgrader 3-46

Noreen Energy Resources Ltd. Provost Upper Mannville Heavy Oil Steam Pilot Project 3-58

Nova, An Alberta Corporation Canstar 3-44

Ontario Energy Resources Ltd. Suncor, Inc. 3-48

ORS Corporation Electromagnetic Well Stimulation Process 3-53

PanCanadian Petroleum Frog Lake Project 3-45 Marguerite Lake Phase A Pilot Plant 3-56 South Kinsella (Kinsella 8) 3-60 Syncrude Canada Ltd. 3-49

Partee Lavalin Inc. CANMET Hydrocracking Process 3-51

Petro-Canada CAN MET Hydrocracking Process 3-51 Canstar 3-44 Daphne Project 344 GLISP Project 3-54 Ipiatik Lake Project 3-55 Marguerite Lake "B" Unit Experimental Test 3-56 PCEJ Project 3-57 South Kinsella (Kinsella B) 3-60 Syncrude Canada Ltd. 3-49 Wolf Lake Project 3-49

Research Association for RAPAD Bitumen Upgrading Project 3-59 Petroleum Alternatives

RTR Oil Sands Alberta, Ltd. RTR Pilot Project 3-59

Santa Fe Energy Company Santa Fe Tar Sand Project 3-60

Saskatchewan Government NewGrade Heavy Oil Upgrader 3-46

Saskatchewan Oil and Gas Corporation Meets. Steam Drive Project 3-56

Shell Canada Resources, Ltd. Athabasca Project 3-43 Peace River Commercial Expansion 3-47 Peace River In Situ Pilot Project 3-57 Sarnia-London Road Field Mining Assisted Project 3-47 Scotford Synthetic Crude Refinery 3-48

Shell Explorer, Ltd. Peace River In Situ Pilot Project 3-57

Solv-Ex Corporation Athabasca Project 3-43 PR Springs Project 3-58

Southworth, Ray M. Enpex Syntaro Project 3-53

Suncor, Inc. Burnt Lake Project 3-49 Fort Kent Thermal Project 3-54 Suncor 3-48

Sun Oil Company Suncor, Inc. 3-48

Superior Oil Company Enpex Syntaro Project 3-53

Tenneco Oil of Canada, Ltd. Athabasca In Situ Pilot Project 3-51

Texaco Canada Resources Ltd. Texaco Athabasca Pilot 3-62

Texaco Inc. Diatomaceous Earth Project 3-44

3-68 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Texas Tar Sands, Ltd. Enpex Syntaro Project 3-53 Total Petroleum Canada, Ltd. Meota Steam Drive Project 356 Triad Engineering Services Ltd. PR Spring Project 3-58 Uentech Corporation Electromagnetic Well Stimulation Process 3-53 Underwood McLellan & Associates Taciuk Processor Pilot 3-61 (UMA Group) Union Oil of Canada, Ltd. Grosmont Thermal Recovery Project 3-55 Union of Soviet Socialist Republics Yarega Mine-Assisted Project 3-63 U.S. Department of Energy Tar Sand Research Program 3-61 Westcoast Petroleum, Ltd. Suffield Heavy Oil Pilot 3-60 Western Tar Sands, Inc. Ultra Sonic Wave Extraction 3-62 Whittier, M. H. Expex Syntaro Project 3-53 Worldwide Energy Fort Kent Thermal Project 3-54

3-69 SYNTHETIC FUELS REPORT, DECEMBER 1986 Pr, ______PROJECT ACTIVITIES

The overall RAM program objective is to operate SECOND PHASE OF KILNGAS RAM PROGRAM TO the KILnGAS Commercial Module, as necessary, to BE COMPLETED IN DECEMBER 86 obtain sufficient data and experience to verify per- formance expectations and to provide a basis for Construction of the KILnGAS Commercial Module commercial offering. (l{CM), located on the site of the Illinois Power Company Wood River Generating Station at East The KILnGAS gasifier (Figure 1) is a ported and Alton, Illinois, was completed in 1983. Operational pressurized rotary kiln. As the coal moves through testing was begun in mid-83, and initial demonstra- the gasifier, it is successively dried, heated, tion of the technology, using Illinois No. 6 coal, devolatilized, and gasified. Ports in the gasifier was completed in 1984. Currently, a multi-phased shell allow controlled injection of steam and air Reliability, Availability, Maintainability (RAM) under the tumbling bed of coal and char. The ash program is being conducted at the FCCM. The first remaining after gasification is discharged through a phase of the RAM program (referred to as RAM I) lock hopper pressure letdown system. was initiated in 1985 and was completed in spring of 1986. As reported at the 6th EP RI Coal The gas generated in the gasification zone, which Gasification Contractor's Conference, the second operates at about 19000 F, is withdrawn from both phase of the RAM program, RAM hA, began in ends of the gasifier. Roughly two-thirds of the April 1986 and will be completed at the end of the product gas flows from the feed end of the current operating program in December 1986. A gasifier, countercurrent to the flow of coal; one- third phase (RAM IIB) is planned for 1987. Each third of the gas exits at the discharge end. The successive phase of the RAM program provides for counterflowing feed-end gas dries and preheats the plant improvements, followed by test operation. incoming coal.

FIGURE 1 KILNGAS SCHEMATIC COAL FROM I? CONVEYOR TOGAS QUENCH ANDTAR DAY rCYCLONE REMOVAL TO HEAT OIN RECOVERY

CYCLONE COALFEED D IF 5O.O LB.'UR

COAL —6 ZONES AiR/STEAM FEED 5D PORTS LOCKS CYCLONE ASH LOCKS

RECYCLE TAR TO ASH POND POWER I AIR COMMUNICATION SUP RINGS StEAM 9 ASH LOCKS GASIFIER (iT SHELL 10 x 135 LONG) 60 PSIG OPERATION TO ASH POND

4-1 SYNTHETIC FUELS REPORT, DECEMBER 1986 Commercial focus of the RILnGAS program is on Capacity constraints appeared in both product gas integrated gasification combined cycle power gener- cooling and gasifier porting, requiring further test- ation. Recently, studies were conducted with ing. Utility Power Corporation and Kraftwcrk Union to evaluate both the first commercial KILnGAS 16CC Operation of the plant near the end of 1984 il- plant and the mature KILnGAS 16CC offerings. lustrated a need for greater winter protection. In Study results with Kraftwerk Union gas turbines preparation for the RAM I operating program, a show potential 10CC plants in the late 1990's will considerable amount of new insulation and heat use one gasifier and two gas turbines, and will tracing was added to the plant. produce about 400 MW of electric power. These plants could have heat rates in the low 8000 BTU RAM I Findings (HIIV)/kwh. Further work has shown that the first h'ILnGAS ICCC plant could approach 400 MW. Test operations for RAM I showed marked im- Again this plant would use one gasifier and two gas provements in ash discharge system operation, but turbines, and would have a heat rate under 9000 further refinements are needed. Sustained opera- BTU (HHV)/kwh. tion at design carbon conversion levels and sig- nificantly reduced levels of ash agglomerate forma- tion were achieved using port air:steam ratio con- RAM I Objectives trol. Operation was routinely carried out at 60 RAM I preparations focused on objectives in four percent of plant design capacity, compared to the areas: previous norm of 45 to 50 percent capacity. 1. Improve ash discharge system operation. Gasifier porting was the apparent gas production 2. Operate at design carbon conversion levels. capacity constraint. Operation through the winter 3. Increase gas production capacity toward of 1986 was successfully achieved and final winter design levels. protection details were Identified. 4. Upgrade plant operating capabilities. Some of the test results are summarized in Table The original ash discharge system would not 1. routinely handle the agglomerated ash (ash balls) The next phase of operation, RAM hA, was under- produced by the process. Therefore, the grinding way in the fall of 1986. Priorities for this phase system was upgraded and the pressure letdown and focus on: discharge functions were modified. - Operating time at high carbon conversion. Earlier operating experience showed that formation - Operating at increased gas production of ash agglomerates, which resulted in ash dis- capacity. charge problems, was worse at high carbon conver- - Quantifying miscellaneous carbon losses. sion levels. The ash agglomeration (ball formation) phenomenon was studied in the Laboratory and im- provements were made in gasifier porting and air and steam injection control.

TABLE 1 KILNOAS HIGH CONVERSION PERFORMANCE

Start Carbon %Carbon Net Air:Gas Product Gas Product Gas Period Date Cony. % In Ash Lbs/MMBtu MMBtu/Hr BTU/SCF Direct Indirect Design Goal: -- 93 -- 30 280 406 158 RAM I: 2/07/86 89 92 31 267 208 133 3/10/86 92 93 29 247 246 154 3/16/86 88 92 28 259 236 151 3/27/86 95 91 32 142

4-2 SYNTHETIC FUELS REPORT, DECEMBER 1986 DOW SYNGAS PROJECT ON SCHEDULE FOR 1987 At full capacity, the Project will produce 30 billion STARTUP BTU per day of synthetic gas and 2467 tons per day of steam. The feed for the Project will ini- The status of the Dow Syngas Project was tially be subbituminous coal from the Powder River described at the 6th Annual EPRI conference on Basin, Wyoming, transported by unit trains consist- Coal Gasification held in October. Dow Chemical ing of 70 to 110 rail cars per unit. The Project is Company's coal gasification research and develop- designed to utilize other coal, including Gulf Coast ment effort included construction of a 36 TPD lignite, if supply or economic conditions dictate. Pilot Plant in 1979 and a 1600 TPD Preto Plant in 1982. The 2400 TPD Dow Syngas Project is the Procs Dcription first commercial scale demonstration of that tech- nology. Coal will be received in railroad hopper cars, un- loaded and then ground and slurried with water The Dow Syngas Project is owned by Louisiana recycled from the synthetic gas cleanup process. Gasification Technology, Inc. (LCTI), a wholly The slurry is then transferred to a slurry storage owned subsidiary of Dow. It is located near tank to provide hold-up for transfer to the Plaquemine, Louisiana, within the existing Dow gasification area (Figure 1). Louisiana Division. The Project will utilize Dow's coal gasification technology to convert Western The slurry is next pumped to the slurry preheaters, sub-bituminous coal, or other suitable coal, includ- where it is heated to within 50 to 100 degrees F ing lignite, into medium BTU synthetic gas. The of the boiling point of the slurry at the reactor synthetic gas will be purchased by Dow and will be pressure. Positive displacement pumps are used. utilized as fuel in combined cycle gas turbines co- After preheating, the slurry is fed to the reactor generating electricity and steam. where it is mixed with oxygen in the burner

FIGURE 1 DOW SYNGAS PROJECT BLOCK DIAGRAM

r - NO E,PROCESSES IN I DAWO BOX Aft I I NOT INCLUDED POWER STERN I IN PROJECT. - TURBINE i I

STEAMf1CONDENSATE I POWER STACK I TURBINE CASES I L - - AND TEAM -' WASTE HEAT RECOVERY

CONDENSATE CONDENSATE __ 30.000 PDQIWOAV (14W) SwEET Th0R8 I RAW ICLEANUP AN D SOU R H25 . iLOWTEMP.]_ _s REMOVAL SYNCAS HEAT SYNGAS RECOVERYON ______RECOVERY CO ALA I_SLAG J 'ACID SLURRY S CRS • ISTACK COAL AIR 1-129 CASES ____COA Lj ______i GRINDING I I ____ CONVERSION I I AND I ______TO SULFUR I t J AND SLURRYING SLURRY WATER RECYCLE 1INCINERATION I

4-3 SYNTHETIC FUELS REPORT, DECEMBER 1986 nozzles. Ash is fused in the flame, and the molten scrubber. The wet scrubber is operated at the ash is drained from the bottom of the gasifier into boiling point of the recirculating water, and the a water quench. The slag is withdrawn con- dilute slurry produced is concentrated and blended tinuously as a slurry through grinders and a pres- with the reactor feed stream. The scrubber syn- sure letdown system. thetic gas Is then cooled to about 120 degrees F prior to 11 2 S removal. The hot synthetic gas is cooled in an integral heat recovery system to about 1800 degrees F. This Combined Cycle Plant 2nd stage is unique to the Dow Coal Gasification After sulfur removal, the sweetened syngas is Process. The hot gases leaving the tat stage are pipelined approximately 2000 feet to Dow's existing cooled by additional slurry being introduced into gas turbines which are being modified to accept the 2nd stage (see Figure 2). The benefit Is that the medium BTU synthetic gas. Two Westinghouse more of the energy available in the coal is con- 501DS 110 MW gas turbines are being modified to verted to chemical energy to be released In the accept 100% syngas. gas turbine rather than recovered by radiant boilers from the hot has. The raw gas is then passed Project Plan through a cyclone separator for entrained particles. The Project includes a spare gasifier, cyclone and Process design is complete, procurement of long- slag crusher in order to insure the projected 85% lead equipment items and detail engineering on availability. major systems is 100% complete, and site construc- tion work over 57% complete in October. Plant A high temperature heat recovery train consisting start-up is currently scheduled for April, 1987. of steam boilers and a steam superheater generates steam for use in the Dow steam system. The Dow Syngas Project will be the largest Gasification Combined Cycle power plant in opera- Gas Cleanup tion. Capital costs of a generic power plant constructed on the Gulf Coast are given in After the synthetic gas is cooled to near its con- Table 1. densation point, it is fed to a wet particulate

FIGURE 2 DOW COAL GASIFICATION PROCESS

tAo

4-4 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 Process Description

1392 MW 10CC PLANT UTILIZING Figure 1 is a flow diagram of the Shell Coal THE DOW COAL GASIFICATION PROCESS Gasification Process as applied to SCGP1. The TYPICAL LIGNITE CAPITAL COST heart of the Shell Coal Gasification Process is the pressurized, entrained-flow gasifier. As-received coal is pulverized and dried prior to being fed from Capacity the coal lockhopper system to the gasifier. Oxygen 6 Gas Turbine 145 MW 870 MW 361.5 MW 722 MW is mixed with the coal as it enters the gasifier. 2 and CO along Total Generation 1592 MW Raw synthesis gas, essentially H 2 2 and other residual Gasification Use - 23 MW with a small amount of CO gases (excluding the transport gas), leaves the Oxygen Use -162 MW gasifier for removal of entrained fly ash and con- Auxiliary Use - 15 MW Net Power Generated 1392 MW taminant gases. Energy is recovered by the gener- ation of superheated steam. Molten slag and fly slag are recovered as non-toxic solids. The process Capital MM 86$ 86$/KW has successfully handled coals with high ash levels, Gasification Units 341 245 high moisture levels, and high sulfur levels. All Oxygen Units 147 106 coal particle sizes are usable, making run-of-mine Combined Cycle Units 482 346 coal an acceptable raw material. The process has Facilities 140 101 Site Approximately 80% of TOTAL 1110 798 a high thermal efficiency. the energy present in the coal is recovered as Net System Heat Rate (mV): 9418 BTU/kWh product synthesis gas. An additional 17% is recovered as high-pressure steam. In addition, the process offers exceptional environmental perfor- mance. The clean product gas can readily meet sulfur and nitrogen species emissions requirements in commercial boilers or combustion turbines (Table 1). Slag and fly slag solids are nonreactive and SHELL COAL GASIFICATION PROCESS TO START nonleachable. The small amount of process water UP IN 1987 effluent is readily cleaned to dischargeable quality standards. The status of Shell Oil Company's coal gasification process was reviewed at the Sixth Annual EPRI Contractor's Conference on Coal Gasification held in Palo Alto, California, on October 15-16, 1986. FIGURE 1 Process Background SHELL COAL The current Shell Coal Gasification Process (SCGP) GASIFICATION PROCESS has grown out of many years of intensive coal gasification research and development. Shell Inter- nationale Petroleum and Shell Internationale Re- search, both based in Holland, and Deutsche Shell, A.RO..d C.,I based in West Germany, began joint efforts in 'SO 1972. A 6-ton/day pilot unit located at Shell's Amsterdam research laboratory was started up in 1976, and a 150-metric ton/day demonstration unit was started up within Shell's refinery near Ham- burg, Germany, in 1978. The Shell Companies are now building a new demonstration unit, called SCGP-1, at Shell's Deer Park Manufacturing Com- plex in Houston, Texas. The site is adjacent to the complex's central power station, and both the Effi.M clean, medium-Btu product gas and the high- w.,,. pressure steam generated by SCGP-1 will be util- Itt: ized within the complex's energy distribution sys- tem.

Project Deseriptia. The high unit capacity of the equipment will allow substantial economies of scale. It is expected that SCGP-1 has been designed to process a wide range commercial-scale gasification trains as large as of feedstocks, with coal feed rate varying from 2500 tons/day will still be small enough to allow 250 tons/day for as-received bituminous, high-sulfur shop fabrication of major equipment, with rail and coal to 400 tons/day for as-received high-ash lig- truck transport to the construction site. nite.

4_5 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 Project Schedule

Shell developed the process design and significant SCGP-1 TYPICAL TREATED PRODUCT aspects of the detailed engineering design. Lum- GAS COMPOSITION mus carried out remaining detailed engineering design and procurement. Various contractors are Component % Volume (N, Free) carrying out the construction work. Shell is provid- ing overall project management. Hydrogen 30 Carbon Monoxide 69 With the exception of a coal feed bin and a water Carbon Dioxide <0.1 tank, all vessels were shop fabricated, including the Hydrogen Sulfide <0.01 gasifier, syngas cooler, and lockhopper systems, Carbonyl Sulfide <0.01 delivered by rail or truck to the SCOP-1 site, and Hydrogen Cyanide <0.001 lowered into place. Ammonia <0.001 Hydrogen Chloride <0.001 Project mechanical completion is expected by year- Hydrogen Fluoride <0.001 end 1986, with plant startup occurring in the first Methane 0.03 half of 1987. All major equipment items were in Water 0.6 place by August 1986. All other components, both Argon 0.2 special and commodity items, were on site by Oc- tober. The complete project schedule is given in Table 2.

Demonstration Unit TABLE 2

In addition to the utilization of the Deer Park Manufacturing Complex facilities for treating and SCGP-1 SCHEDULE disposition of SCGP-1 effluent gas and water, gas and water treatment will be studied in slip-stream units attached to SCCP-1, as illustrated in Figures Issue Major Purchase Orders June 1984-September 1985 1 and 2. These slip-stream units will process small fractions of total gas and water flows and thus are Major Equipment Delivery October 1985-June 1986 efficient, low-cost means of testing treating op- tions. The water-treating unit, pictured in Figure Field Work

2, will house different types of biological treating Warehouse/Shop May 1985-September 1985 systems. Site Preparation May 1985-March 1986 Civil May 1985-March 1986 Mechanical December 1985-December 1986

Mechanical Completion December 1986

Commissioning November 1986-March 1987

Coal To Gasifier First Half 1987

COOL WATER PROGRAM PASSES HALF-WAY POINT

The Cool Water demonstration plant is now ap- proximately halfway through its five-year commer- cial demonstration (June 1984-June 1989). Thus far, Cool Water has already proved that integrated gasification combined-cycle (16CC) technology can reliably produce economical electrical power while limiting emissions of 502, NO' and to a rate only one-tenth of the and New Source Performance Standards for coal-fired plants. The 120 megawatt nominal Cool Water plant began commercial production on June 24, 1984.

The Cool Water sponsors now feel that 16CC rep- resents a shelf-available technology for amelioration

4-6 SYNTHETIC FUELS REPORT, DECEMBER 1986 of acid rain concerns associated with the burning were caused by plugging in coal slurry lines and fly of coal. Preliminary economics indicate that IGCC ash slurry lines. The vast majority of the shut- technology is capable of producing power for 10% downs occurred in the early days of operation. less cost than conventional coal-fired power plants equipped with flue gas desulfurization units. During the high sulfur coal tests, high corrosion rates were evident in certain sections of the syngas The major components of the power plant are a coolers. These rates presented no surprise in that gas turbine with electric generator (65 MW gross), the coolers were designed for the lower sulfur a heat recovery steam generator (HRSC), and a program coal. Since the vast majority of operation steam turbine with electric generator (55 MW time was planned for that coal, front-end capital gross). The waste heat exhaust from the gas tur- costs were reduced by utilizing a readily available bine is used in the H RSG to produce additional metallurgy. steam. This steam (25%) combined with the steam from the syngas coolers (75%) is superheated in the Gasifier performance has been better than HRSC and used to drive the 55 MW steam turbine originally expected on a commercial scale. Actual generator. The design net electrical generation is performance on the three coals tested to date are 111 MW at 13.8 kV before deducting the power given in Table 1. requirements for the air separation plant. Provi- sions have also been included to pipe the clean TABLE 1 syngas to an existing oil- and gas-fired boiler (65 MW gross) of all adjacent conventional plant owned COOL WATER PLANT PERFORMANCE/ALTERNATE FEEDSTOCKS by Southern California Edison in order to tat 1,000 TPD Througbput) demonstrate the suitability of the medium BTU syngas as a replacement fuel for conventional Design Actual Performance boilers. La!l. suFco surco Ill. #6 Pitts. #8 Operating Experience Sulfur Content 96) 3.1 In October the plant was operating at full produc- (at. 0.48 0.4 2.9 tion rates, with over 11,000 hours of cumulative Oxygen Consumption operation. The plant has, during several months, (Tons/Day) 962 908 885 1,004 achieved capacity factors greater than 70%. The is the power produced as a percent Cross Power Production (MW) 114 116 120 129 of design. In September, 1985, the plant had its best production month with a capacity factor of By-Product Sulfur Produced 86%. Quarterly capacity factor statistics are (Tons/Day) 4.6 3.8 30.0 27.0 shown in Figure 1. Carbon Conversion (96) 98.3 98.3 97.2 97.8

Cagier Refractory Life (Yin. Projected) 1 4 2 2 Overall Heat Rate (BTU/kWh) 11,510 119550 11,700 119460 I.

Carbon conversions for the three coals have averaged approximately 98 weight percent. Single pass carbon conversions have been high enough that the slag screen classifier, intended to separate fine, high carbon content slag for recycle to the gasifier, has not been utilized. The high carbon conversions are also being attained at lower reaction temperatures than originally ex- pected. The lower gasification temperatures have lowered oxygen costs and extended refractory life. Plant heat rates have been in line with original projections. Overall plant heat rates have been I!;IIP1tII1t approximately 11,500 BTU/kWh. The program projects that the heat rate can be lowered to 10,000 BTU/kWh with minor plant im- The primary cause of shutdowns has been equip- provements. EPRI has estimated a mature second ment failures. Only 16% of the shutdowns have generation IGCC plant would have a heat rate of been process related and all but three of those 9,200 BTU/kWh.

4-7 SYNTHETIC FUELS REPORT, DECEMBER 1986 Dynamic load following tests have gone well. Load recovery unit, the greater part of the entrained changes of 20% at a ramp rate of 4%/minute have dust Is separated in cyclones and recirculated into been achieved. Utility daily load following the fluidized bed. Following waste heat recovery, requirements are usually 10% to 50% load changes the small dust portion remaining Is removed in a at 1% to 3% per minute. Test results are within water scrubber. Subsequently, the ratio of these ranges and have demonstrated the IGCC's hydrogen to carbon monoxide required for methanol capability of serving the electric utility industry. synthesis is obtained in a CO-shift conversion unit.

Recent studies by EPRI indicate the capital in- Plant Status vestment required for a 500 MW 10CC plant Is comparable to that for a direct coal-fired plant of Construction of the demonstration plant was started the same size with flue gas cleanup and that in 1983, and was completed on October 25, 1985. phased construction of the 10CC plant would result Capital expenditure for the plant amounted to ap- in a cost approximately 10% less than the direct proximately DM220 million, including preparatory coal-fired unit. Phased construction of an 16CC work for a future plant extension. About 20% of plant would consist of initially Installing a gas tur- the construction costs was accounted for by pollu- bine to be fired with natural gas or oil while these tion control measures. fuels were available at a low cost. Heat recovery steam generators and a steam turbine would be In late 1985, the gasifier was heated up and ignited added as load growth continues and then the for the first time. In the first six months of 1986, gasifier plant would be added to convert the plant the plant units from gasification up to and includ- to 16CC operation. ing gas treatment were started up in several runs and interconnected to constitute the system. In early June, 1986, synthesis gas was for the first time fed to the methanol synthesis plant.

RHEINURAUN HIGH-TEMPERATURE WINKLER In August, the plant was started up again after a PLANT STARTS UP six weeks' standstill and four weeks later was still in continuous gasifying operation. The High-Temperature Winkler (HTW) demonstration plant constructed by Rheinische Braunkohlenwerke Test Results AG started up in 1986. Based on experience Test operation of the plant so far has shown that gained with the operation of two atmospheric- the target data can be or have already been pressure Winkler gasifiers up to the 1960s, the reached (Table 1). Gasification pressure was about Winkler process was further studied in a process 10 bar and the temperature was 1,0000 C in the development unit at Aachen technical university entrained-gasification zone. (0.5 ton/hr throughput) and in a pilot plant which was operated until 1985 (3 ton/hr throughput). With the operating conditions realized so far, the design figure of 91% for carbon conversion was Construction of the demonstration plant was com- clearly exceeded with an actual value of 96%. The pleted in late 1985. It has a design throughput of design specific oxygen consumption of 430 m3 per 30.5 ton/hr of dry brown coal, eqiivalent to a syn- ton of dry brown coal (maf) compares with an ac- thesis gas production of 37,000 m /hr. tual 400 m 3 per ton, accompanied by a lower CO2 content in the raw gas. The expected synthesi A 20 km pipeline conveys the synthesis gas gas yield was more than attained with 1,510 m produced to the site of Union Rheinische per metric ton of dry brown coal (maf). Braunkohien Kraftstoff AG, a Rheinbraun subsidiary, where it is fed into an existing methanol synthesis At 75%, the syngas content (CO * 11 2) in the raw plant. gas was 496 higher than expected. So far, the CH4 content amounted to 3.6% under the given operat- Preparation and supply of dry brown coal as well ing condition, which is slightly higher than ex- as provision of utilities, such as steam, cooling pected. water, and boiler feed water, take place via an in- terconnection with the neighboring Berrenrath The design of the demonstration plant features an briquetting plant and the associated power plant, appreciably longer entrained-gasification zone than which also burns the gasification residue and the that of the pilot plant in order to improve gas residual dust from gas cleaning. quality through longer gas residence times. This has resulted in a redistribution of the solids Process Description streams, i.e. the ratio of dust discharged overhead to ash discharged at the gasifier bottom. Whereas The demonstration plant comprises a gasifier and planning assumed an ash-to-dust discharge ratio of subsequent gas treatment systems. For synthesis 40 to 60, the operation performed so far showed a gas production, dry brown coal (12% moisture clear reduction in the quantity of dust separated in content) is supplied from the neighboring plant via the second cyclone. Grain size distribution of the a conveyor and bunker system to the fluidized bed ash in the discharge unit at the gasifier bottom is of the gasifier, where it reacts with oxygen and as expected, but dust from the cyclones shows an steam. Before the gas enters the waste heat increase in the fines portion.

4-8 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1

COMPARISON OF DESIGN AND ACTUAL DATA

Design Data Actual Data

28 Cashier Throughput tftir as dry brown coal 30.5 46,500 Raw Gas Production m 3 /hr as dry gas 49,500 Raw Gas Composition Vol% CO + 112 70 400 Oxygen Consumption an 0 2 /t coal (maf.) 430 96 Carbon Conversion percent 91 1,420 1,510 Syngas Yield m 3 (CO + 11 2 )/t pal (maf.) 5,860 5,880 Gasifier Capacity m 3 (CO + 11 2 )/m . hr

Problems Encountered Another application of the HTW process under study for the Department of Mines and Energy, During the first operational periods, problems oc- Adelaide, South Australia, is the possibility of curred mainly with conventional components. For processing salt-rich Bowmanns coal with combined- example, damage to the drives of the ash discharge cycle technology. Gasification tests are to be per- screws and breakdown of the start-up formed in the HTW pilot plant until the end of of the process gas compressor led to the plant's 1986, serving as the basis for a study on a 300 MW shutdown. Further trouble was caused by the combined-cycle power plant. mechanical failure of two turbo -compressors. #L## A During some operational periods, excessive tempera- tures in the entrained-gasification zone probably were the reason for deposits occurring on the inlet PRKNFLO GASIFIER STARTS UP IN AUGUST side of the raw gas cooler. Operation of the PRENFLO coal gasification test Initially, the formation of trace components (higher unit at Fuerstenhausen, West Germany was started hydrocarbons, especially naphthalene) in the raw gas on August 12, 1986. The PRENFLO process has caused clogging in various Items of the gas treat- been developed by GKT (Gesellschaft fur Kohle- ment steps. By raising the temperature above the Technologie mbll), of Essen, Federal Republic of fluidized bed and appropriate modifications to the Germany. It was recently described at the 6th equipment of the gas treatment steps, it was pos- Annual EPRI Coal Gasification Contractor's Con- sible to solve the problem. ference.

Trouble in the waste water pretreatment unit GKT is a wholly-owned subsidiary of Krupp Koppers caused excessive NH 3 in the raw gas, resulting in GmbH, Essen, Federal Republic of Germany, and is the formation of ammonium carbonate at the com- used by the parent company for the purpose of pressor blades and shutdown of the turbo- conducting business in the United States. GKT and compressor. A modification in waste water strip- Krupp Koppers are affiliated with Krupp Wilputte ping and the installation of additional steam trace Corporation, Murray Hill, New Jersey. The basic heaters solved this problem. design features incorporated in the PRENFLO process include: Outlook - Pressurized entrained-flow coal gasification Completion of the first start-up phase with a per- - Dry coal dust feeding formance test at 100% load and the acceptance run - Operating pressure range between 20 and 60 were scheduled for late 1986. The 117W process bar also offers the possibility of gasifying different - Standardized capacity of 1,000 metric tons carbonaceous materials. The Kemira Oy company, of coal per day, with a potential increase of Finland, has decided to convert an existing am- up to 2,500 metric tons per day monia production plant at Oulu from heavy oil to peat gasification using the HTW process. The Figure i is a simplified flow sheet of the projected plant is designed to gasify 650 tons/day PRENFLO installation at Fuerstenhausen. Product of peat at 13.5 bar and process it to 280 tons/day gas desulfurization is not currently part of this in- of ammonia. Startup is scheduled for the spring of stallation. Presently, the product gas is sent to an 1988. adjacent coke oven plant where it is mixed with the coke oven gas, desutfurized and used to under- ire the coke ovens.

4-9 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 2 TIME SCHEDULE FOR PRENFLO DEVELOPMENT - an 1975 1980 1985 1990 1 FEASIBILITY -

2 DEMO PLANT 150 MIlD - ENGINEERING. ERECTION — - OPERATION — I

3 COMPONENTS - C

4 PRNRO48MT/D I - ENGINEERING. ERECTION 1111111111111113 -OPERATION X REflA9flS) — - OPERATION (SYNGAS REOLEMENTS)

5 PRENFLO1,000 MIlD - SCALE UP INVESTIGATIONS - ENGINEERING STANDARD MODULE —

In order to validate the PI1ENFLO process 6 DEMONSTRATION R.M4T reliability, GKT plans to run the test unit for a to- -ENGINEERING — tal of 8,000 operating hours within the next two - ERECEtt OPERATION and one-half years. This program will provide the basis for design and cost estimates for the detailed engineering of a 1,000 metric ton per day PRENFLO module, specially designed for IGCC ap- plication. FIGURE 3 The time frame for the development program is shown in Figure 2. The test work is expected to TEMPERATURE AND be finalized by mid-1988. PRESSURE RANGES FOR Operational Results VARIOUS PROCESSES

The start-up of the PRENFLO test unit at CC Fuerstenhausen was stated to be quite satisfactory. The coal gasification process route itself performed ac® as expected and confirmed previous operating data I which was collected during the Shell-Koppers PRENFLO (SHELL) Project.

A comparison of several coal gasification processes with respect to their ranges of operating pressure and temperature is shown in Figure 3.

Table 1 gives the compositions of the first raw 1.000- HTW [LJ4WRG gas. The CO content is related to the mass flow U ii SLAGGER n p—Icu4.as of coal/gas in relation to the reactor's inner sur- R I RIJHR100 face area. A commercial size plant should give WNIQER rA better, more predictable figures. The N 2 content N is governed by the choice of conveying and flushing gas. In the GKT concept for 10CC integration, the gas turbine fuel gas must have a defined N 2 con- tent. Part of the test program at Furstenhausen includes the varying of oxygen purity between 100% 0 I I . — BAR and 21% 02. 0 10 20 30 40 50 60 70 80 90 100

For synthesis purposes, the nitrogen would be PROVEN PROCESSES removed from the raw gas. In such a case, PROCESSES UNDER DEVELOPMENT product gas (or CO 2 ) will be used as a conveying gas.

4-10 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 SCOTIA SYNFUELS TO BUY NOVA SCOTIA REFINERY

PRENFLO RAW GAS COMPOSITIONS (VOL%, DRY) Scotia Synfuels Limited and Canadian Ultramar Ltd. AND OPERATING CONDITIONS have announced an agreement in principle for the purchase and sale of Ultrarnar refinery site and assets at Point Tupper, Nova Scotia. Run No. 6 7/8 Pressure/Bar 19.4 19.0 Scotia Synfuels plans a syniuels plant to convert CO 2 1.98 2.87 Nova Scotian coals to low sulphur high value CO 65.90 68.19 refinery feedstocks. The product would displace 26.53 24.44 imported oil. It would employ 500 persons directly + COS 0.27 at Point Tupper and 500 persons in the Sydney in- H2 0.25 dustrial region. At least two years of engineering 4.23 N2*+ All 5.34 work still needs to be done before construction 99.3% Carbon-Conversion 99.0% could start. Conveying Gas N2 Purity of 02 99.5%

Table 2 lists some preliminary characteristic data, such as carbon conversion figures and carbon con- tents of fly ash and slag. The cold gas efficiency of a commercially-sized gasifier should be 4% bet- ter than the figures given, or 83.2% and 81.4% for runs 6 and 7/8, respectively.

TABLE 2

PRENFLO CHARACTERISTIC DATA

Run No. 6 7/8 Pressure/Bar 19.4 19.0 Density of Feed Flow kg/m3 480.0 480.0 Coal Consumption kmf)/h 1094.0 1075.0 Spec. Gas Prod. m a/kg (mail 2.274 2.204 Spec. (C0+112) Prod. m3Ag(maf) 2.102 2.042 Carbon- Conversion % 99.0 99.3 Slag/Slag+Fly Dust 0.479 0.40 Carbon in Slag % 0.0 0.0 Carbon in Fly Dust % 14.5 8.8 Cold Gas Efficiency (lil y ) % 79.2 77.4

The test program at Fuerstenhausen is sub-divided into two phases. The first phase involves clarifica- tion of IGCC related questions. This program in- cludes the operation of the waste heat recovery steam boilers. Phase I will continue until the early part of 1988. The second phase will include opera- tion of the system with direct quench to demonstrate the production of gas for subsequent CO-conversion.

4-11 SYNTHETIC FUELS REPORT, DECEMBER 1986 CORPORATIONS

SASOL REPORTS INCREASE IN PROFIT FOR design capacity despite the fact that the program 1985-86 for debottlenecking to 106% of design capacity had not yet been completed. With the commissioning Sasoi Limited's 1986 annual report for the year of the seventh oxygen plant at Sasol Two the ended June 30, 1986 reported an increase in profit debottienecking project was completed and the fu- el 14.8% for the year. lure output of these two factories can be expected to show a further moderate increase. The chairman's review noted that it is now 31 years since oil was first produced at Sasolburg, six Sasol One once again increased its production. years since production commenced at Seconds and Also, a comprehensive inspection of the larger seven years since the privatization of the Sasol un- types of equipment at Sasol One, indicated a longer dertaking. residual life than had been previously expected. Production of hard waxes increased considerably Sasoi is the industrial company with the biggest after the introduction of an improved catalyst market capitalization on the Johannesburg Stock developed through Sasol's research, Exchange. Volumetric sales of liquid fuels increased by 3.9% Unstable petroleum prices and exchange rate uncer- compared with the previous year. Sales of in- tainties in 1986, especially in the area of oil dustrial gas increased by 1.5%. Despite a prices, made exceptional financial demands on countrywide decrease of 3% in petrol consumption, Sasol. The prices received for petroleum products soles increased by 2.1%. decreased by more than 40% during this period. The value of chemical sales Is also sensitive to These developments were not unexpected and Sasol movements in the exchange rate of the rand be- had already prepared itself on various fronts for cause the chemical division mainly competes with such occurrences. Financial measures taken in or- international chemical companies in both the local der to counteract the effect of the lower oil prices market and export markets. However, the recent include: decrease in crude oil prices had only a minor in- fluence on the selling prices of the most important All loans which originated in 1983 with the chemical products such as waxes, solvents and take-over of Sasol Two were redeemed to al- ethylene. The net value of chemical sales in- leviate the company's interest burden. creased by R80 million to R440 million.

Since the first indications of lower oil prices a Future Prospects few years ago, a conservative policy was fol- lowed in respect of dividend payments by Sasol The rand prices of imported petroleum products Three. The cash reserves thus created, of will depress the prices of Sasol fuel products to a which half are due to Sasol, could be paid out level considerably lower than the average for the as dividends should lower oil prices make ex- previous financial year. cessive inroads on Sasol's income. In the short term there are two compensating An equalization reserve was established in order factors: firstly, interest will be saved on the loans to conteract future fluctuations in oil prices which were repaid at the beginning of the year, and exchange rates. If low oil prices continue and secondly, the reintroduction on July 1, 1986 of for a few years, this reserve could also be the levy rebate of 3.6 cents per liter for all utilised in order to protect shareholders' manufacturers of liquid fuels from indigenous raw dividends. materials.

Fluctuations in international oil prices are even- Sasol believes that crude oil prices will remain tually reflected in the South African pump prices volatile for some time and will fluctuate between of gasoline. The chairman remarked that each $10 and $18 per barrel. A steady increase in time the petrol price increases, questions are posed crude oil prices will then occur in the 1990's. as to why the price of Sasol petrol, produced from indigenous raw materials, should increase along with As a result of the conservative financial policy of the crude-oil based petrol prices. When prices the past few years, Sasol is well equipped to cope decrease no one questions why Sasol's prices also with low fuel prices in the short and medium term. decrease. Exchange Rates Operating Results The lower international value of the rand had a favorable effect on the results of the oil-from-coal The highlight of the year's operating results was division. The exchange rate weakened from an the further increase in production at Sasol Two and average of 57 US cents per rand during the pre- Sasol Three. Both factories achieved 105% of vious financial year to an average of 44 cents in

4-12 SYNTHETIC FUELS REPORT, DECEMBER 1986 the past financial year. However, the collapse of Two major projects to improve the factory's energy the oil price during the second half of the financial balance were launched during the past year. The year counteracted the effect of the lower exchange first of these was the installation of improved coal rate. screening equipment in order to enhance the quality of the gasification feedstock. The second is the The lower international value of the rand was installation of a ninth boiler. This plant will util- mostly responsible for the chemicals division show- ize excess fine coal to produce steam for gasifica- ing increased revenue of R80 million. tion and for electricity generation. Sasol One Technology Despite extensive statutory inspections which were During the year a study was undertaken to deter- carried out during the year under review, Sasol One mine the technical and economic limitations on the achieved its highest production levels yet. Due to throughput of all the individual plants at Seconds. higher yields of hydrocarbon products per unit of The results of this study will allow future produc- feed gas, the production of both the Arge and Syn- tion and debottlenecking programs to be optimized. thol Fischer-Tropsch synthesis plants increased during the year. In view of the growing demand for Sasol's specialised waxes and the potential for increased A plant for the production of porous ammonium synthesis gas production at Sasol One, it was nitrate prills was successfully completed on decided to expand the fixed-bed Fischer-Tropsch schedule in late 1985. Development work on a synthesis complex with an additional high-pressure project to double the output of refined phenols has reactor. The project is scheduled for completion been completed. Construction was scheduled to during September 1987. commence in late 1986. The Synthol fluidized-bed demonstration plant was A project to upgrade aqueous effluent from Sasol in operation throughout the year. As this reactor One was launched. The project is to be completed system promises significant capital and operational during the 1990's and the total project cost will be cost savings, a commercial scale reactor is being in excess of R100 million. designed and evaluated for possible installation at Sasol One. Sasol Two The joint research program on the removal of sul- Smaller debottlenecking projects, improved operat- phur from off-gases, undertaken several years ago ing techniques in the Synthol plant and overall by Sastech and a German engineering firm, has plant optimization resulted in a marked improve- culminated in the commercialization of a new ment in general plant stability, output and yields. process. The process employs a unique wash solu- During the year a 9.1% increase in synthesis gas tion for removal of hydrogen sulphide and its con- production was recorded, while the overall product version to sulphur. volume increased by 12.5% to 105% of design capacity. Due to the dramatic fall in international crude oil prices, several projects aimed at demonstrating the Overall cost increases were kept to below the in- commercial viability of coal-based flation rate. The debottlenecking program begun plants have been cancelled. two years ago will be completed by the end of 1986 and will enable both the Secunda plants to further increase production levels. Sasol Three 861 MONTANA PROJECT DELAYED, OTHERS The higher production targets established by Sasol PLANNED Three for the 1985/86 financial year were met and synthesis gas production increased by 7% to reach the equivalent of 108% of design capacity. In ad- SW International and Dravo Corporation have filed dition, the efficiency of gas conversion Was sig- plans to develop a dozen or more 50 to 100 nificantly improved. Oil production increased by megawatt cogeneration projects involving partial 11% compared to the previous year. This was liquefaction by coal pyrolysis. made possible by higher processing efficiency in the fuel synthesis and oil recovery plants as well as in- SGI has developed the LFC (Liquid From Coal) creased overall plant stability. process, that is a combination of computer control technology and low-temperature pyrolysis. The The optimization of electronic control systems LFC process selectively produces high quality oils resulted in a marked improvement in the overall by tailoring the heating rates so that the tars and stability of the factory, thereby reducing production pitch remain in the coal. The process employs losses. Improved control systems also enhanced the proven pyrolysis equipment operated at atmospheric performance of the high-pressure unit converting pressure and at moderate temperatures. Low grade to diesel. or waste coals can be upgraded to higher quality

4-13 SYNTHETIC FUELS REPORT, DECEMBER 1986 fuels. See article in the Technology section of this issue foi a more detailed description of the A 100-MW facility in Las Vegas, Nev., with process. power sales to Nevada Power Company beginning in 1990 (No. QF86-814-000), The first planned application of the LFC process is a $50 million, 30 megawatt facility planned at - A 100-MW facility in Miles City, Mont., with Colstrip, Montana. This project was originally set power sales to Montana-Dakota Utilities up under the name AEM Corporation. Along with Company beginning in 1991 (No. QF86-813- 30 MW of electricity, the facility would produce 000), 300,000 barrels of coal liquids and 200,000 tons of char annually. Feedstock would be 350,000 tons - A 100-MW facility in Emory, Utah, with of refuse coal from Western Energy's surface mines power sales to Utah Power & Light beginning that supply the Colstrip power plant. Char in 1091 (No. Q F86-810-000), produced by the process could then be sold to the power plant or burned in a fluidized bed boiler. - A 100-MW facility in Elmira, N.Y., with power sales to New York State Electric & AEM negotiated a 35-year agreement with Montana Gas Corporation beginning in 1991 (No. Power to buy the electricity at a partially level- QF86-816-000), ized rate which would begin at 6.41 cents/kWh in the first year. - A 100-MW facility in St. Cloud, Minn., with power sales to Northern States Power Com- As originally proposed, start of construction on the pany beginning in 1991 (No. QF86-815-000), project was planned for late 1985, later changed to 1086. In November of this year AEM filed an - A 100-MW facility in Hartford, Conn., with amendment to its permit with the Montana power sales to Connecticut. Power and Light Department of Health & Environmental Sciences. (No. Q F80-1023-000), It requested that the starting date of construction be changed from November 1986 to November - A 50-MW facility in Savage, Mont., with 1987. Also the deadline for completion is now ex- power sales to Montana-Dakota Utilities pected to be November 1989. Included in the Company (No. QF86-1035-000). request is a name change from AEM Corporation to Montana One Partners. In all of these applications it is stated that the facility will process coal into liquids and a waste 561 has filed with the Federal Energy Regulatory product. The waste product will be fed into a Commission for qualifying facility status for a boiler to produce steam to drive a steam turbine number of other plants, including: and the facility therefore will be a cogeneration facility. A 100-MW facility in Pleasantville, N.Y., with power sales to Consolidated Edison Company of New York beginning in 1991 (No. Q F 86-817-000), COAL EXTRACTION RESEARCH CENTER REPORTS SUCCESSFUL YEAR - A 100-MW facility in Rochester, N.Y., with power to be sold to Rochester Gas & The Coal Extraction and Utilization Research Cen- Electric Corporation (No. QF86-819-000), ter, located at Southern Illinois University at Car- - A 50-MW facility in Detroit, Mich., with bondale, reported a 30% increase in funded re- power to be sold to Detroit Edison Co. (No. search for fiscal year 1986. Q F86-803-000), New contract awards in FY 86 totaled $4,7000,000. - A 100-MW facility in Platteville, Cob., with A large increase in federal funding more than com- power sales to Colorado Public Service Com- pensated for a decrease in sponsorhip of research pany beginning in 1991 (No. QF86-820-000), by the private sector (Table 1). Research on the removal of sulfur from coal continued to be the - A 50-MW facility in Jackson, Mich., with largest single area of activity. power sales to Consumers Power Company beginning in 1991 (No. QF86-821000), Results from a project in the Coal Technology Laboratory Program sponsored by the U.S. Depart- - A 100-MW facility in Framinghanm, Mass., ment of Energy showed that pyrite and other coal with power to be sold to Boston Edison (No. constituents can be liberated through treatment Q F86-800-000), with quaternary salts. In other projects, a methodology was developed to relate density A 100-MW facility in Kingston, N.Y., with measurements to coal maceral composition, and power sales to Central Hudson Gas & technical and environmental feasibility was Electric Corporation beginning in 1991 (No. demonstrated for disposal of scrubber sludge in QF86-818-000), abandoned underground coal mines.

4-14 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 1 The Mineral Institutes Program continued to em- phasize mining technology and mined land reclama- EXTERNALLY FUNDED tion. A technique was developed to measure the COAL-RELATED RESEARCH concentrations of quartz and other minerals in FY 65-FY 86 respirable dust released during coal mining. In a study of wet-land development on reclaimed mined Funding Funding land, it was demonstrated that metal ion toxicity Received Received to plants and wildlife is not a problem. Sources FY 85 FY 86 Funding Another major effort in FY 86 was an analysis of opportunities for fluidized bed combustion of coal Private 850,416 503,724 1,086,640 1,148,174 in small-user applications. The possibilities iden- State tified were space heating of large and small build- Federal 1,626,018 3,054,740 ings and coal drying. $3,563,074 $4,706,638 Totals The Small Operator Assistance Program at SIUC is now broadly defined to include projects commis- sioned by the Illinois Department of Mines and Minerals, as well as studies funded directly by small operators. A project in each category was completed in FY 86. One of these involved coal seams in southeastern Illinois with very high pyritic sulfur contents. The hydrologic consequences of The research program sponsored by the Illinois Coal mining were not judged to be severe. Development Board (formerly the Illinois Coal Re- search Board) continued to emphasize coal cleaning. In the Dragline Training Program, a lull in the A project designed to remove sulfur from coal by training schedule allowed time for upgrading of reaction with ethanol and carbon monoxide con- training materials, including manuals, videotapes, tinues to attract favorable attention. In other and equipment. The instructors are now in a bet- projects, methodology to characterize and remove ter position to market the program. chlorine from coal was developed, and considerable progress was made in defining a process to produce ultraclean (low-ash), ultrafine coal. Ultraclean, ultrafine coal is viewed as a potential replacement for liquid fuels.

4-15 SYNTHETIC FUELS REPORT, DECEMBER 1986

GOVERNMENT

DOE SOLICITS INTEREST IN COAL R&D Coal-Derived Fuels ACTIVITIES - A study examining industry's need for low- On November 20, the U.S. Department of Energy's cost fuels, and how research and develop- Morgantown Energy Technology Center released a ment could best develop the most promising list of research areas that it is considering funding. substitute fuels DOE wanted to get comments from industry con- cerning industry's interest in these areas. Coal- - Development of a simple, mild coal gasifica- related projects on the list Include: tion process and an integrated system of fuel production and upgrading. Hot Gas Cleanup Underground Coal Gasification - Studies on hot gas cleanup systems, and measurement of major contaminants for coal - Sampling of water wells near two under- conversion processes ground coal gasification test sites in Wyom- ing - Testing gas streams in hot gas cleanup sys- tems and molten carbonate fuel cell - A study examining the technology and processes economics of underground gasification of mildly swelling Eastern coal seams - Determine the optimum hot gas cleanup con- figurations for use with a coal-powered - Research on an existing subsidence model for diesel. underground coal gasification Coal Combustion - A study to find ways of altering the com- position of coal gas in situ. - Testing materials and components for par- ticle control systems in pressurized fluidized- Fuel Cells bed combustion (PFBC) - Design and engineering analysis of a molten - Determine if conventional P FBC sorbents can carbonate fuel cell be used in advanced PFBC systems - Studies on basic understanding of fuel cells - Developing designs for second-generation, and associated materials; low-cost manufac- advanced-cycle PFBC turing processes; and systems using coal or coal-derived fuels in the transportation, - Analyze the interactions between aluminosili- residential and electric utility markets. cates in coal and vapor-phase alkalis, and study the correlation between sulfur in a process stream and alkali sulfate-induced corrosion. Surface Coal Gasification - Fabrication and testing of two particle- control devices for a bench-scale gasifier - Test materials and components for particle control devices in gasification systems - Study of new ways the "gasifier island" con- cept would be used outside the utility sector, and outlining the economic and technical ad- vantages of the concepts - Determine whether solid-state electrolyte membranes would work for gas separation in coal gasification processes.

4-16 SYNTHETIC FUELS REPORT, DECEMBER 1986 ENERGY POLICY & FORECASTS

expected range of capital costs for these three ICCC TO BE FAVORED OPTION FOR UTILITY plant types, with perhaps a small captial advantage POWER PLANTS to AFBC and PC plants. D.F. Spencer, of the Electric Power Research In- stitute, believes that utilities will favor integrated Figure 1 compares the 30 year levelized, constant gasification combined cycle systems over fluidized 1985 dollar energy costs. All 500 MWe beds or pulverized coal combustion units, His plants are projected to produce power costs of ap- presentation to the Coal Technology '86 conference proximately 4 to 5.5 cents/kWh. There is no sig- in November noted that the U.S. electric utility in- nificant advantage for any of the technologies, con- dustry has depended on coal to produce ap- sidering the present uncertainties in these cost es- proximately 50% of its electrical energy since the timates. Phased construction of 10CC plants does First World War. With the advent of concerns over show promise of producing some reduction in power air emissions, particularly sulphur dioxide, and the costs (a few mills). expected major commitment of the to nuclear energy, it appeared in the 1960's and 1970's that "coal may have had its day.' FIGURE 1 However, with the present problems associated with nuclear powerplants, the electric power industry is COST OF ELECTRICITY most likely going to utilize ever increasing amounts of coal in order to meet future generation needs. EPRI's analyses indicate that the expected increase in generating capacity between now and 2010 is Casio! E$tci,àoty (30 )ISr !nkzd) In Ccn,irt 1985 insInAw!, 300,000 megawatts, with an uncertainty band of as 80 low as 95,000 megawatts and a high of nearly 500,000 megawatts. It is likely that 75-85 percent of these new capacity additions will be coal based so powerplants. r r I If this projection is correct, we will have ap- 10 proximately 500,000 MWe of coal fired capacity by 2010 and it is likely that coal will produce 65-75% 30 of our electrical energy. The role of advanced, clean coal technology will be a key in this ex- panded coal use. 20 Advanced Coal Technologies 10 The three major candidates for advanced coal utilization in the 1990's are integrated coal gasification combined cycle (10CC or CCC) 000 PC MOC PnaC powerplants, atmospheric fluidized bed combustion Oct (AFBC) systems, and improved pulverized coal (PC) power plants. There are many other advanced coal technologies under development such as pressurized fluidized bed combustion (PFBC), coal gasification- fuel cell (COFC) powerplants, open cycle mag- It is in the area of environmental control that coal netohydrodynamic (OCMHD) systems, and others. gasification combined cycle has a large advantage. However, in Spencer's judgment, these latter tech- Table 1 shows typical effluent streams from the nologies are not advanced far enough for significant three coal-based technologies, using a 3.5% sulphur commercial power production in the 1990's. Illinois coal. The 0CC plant emits approximately one tenth of the add rain precursors (502 and In order to assess the relative benefits of 10CC, NO X ) of a pulverized coal plant and produces 40 AFBC, and PC plants, EPRI has estimated the ex- percent of the solid wastes from a PC plant. In pected range of busbar power costs for such plants comparison, the AFBC plant emits about 50 percent using 3.5% sulphur Illinois bituminous coal. The es- of the add rain precursors from a PC plant, but timates shown in Figure 1 are low and high es- produces 60 percent more solid was te for disposal. timates, as well as those given in EPRI's Technical Assessment Guide (TAG) for the three competing For these reasons, Spencer believes that coal technologies. Also shown for the 10CC plant is gasification combined cycle powerplants show the the benefit of utilizing phased construction of the greatest potential for meeting stringent emis sion plant rather than committing all plant capital at control requirements, yet remaining economically once. In general, there is little difference in the competitive with alternative coal technologies.

4-17 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1 TYPICAL EFFLUENT STREAMS FROM COAL BASED POWER PLANT TYPES (Using 3.5% Sulfur Illinois Coal)

502 Emissions NO Emissions Solid Wastes Plan, Type (Tons/MWe Yr) (Tons/MWe Yr) (Tons/MWeYr) Pulverized Coal Plant 140 25 240 (Precipitators Only) Pulverized Coal Plant 14 8 750 With FGD (90% Removal) Integrated Gasification 0.14-4 3 300 Combined Cycle Plant Atmospheric Fluidized 4 1200 Bed Combustion

Emerging Coal Gasification Technologies prices in the range of $1.50 to $2.00/10' BTU, the simple-cycle combustion turbine is the economic Over the last 10 years, EPRI has evaluated and choice for up to 3,000 hours per year of operation. assessed a broad range of coal gasification tech- Thus the addition of combustion turbines will be nologies. At least four second generation coal the preferred choice by most utilities, followed by gasification technologies will be available for com- subsequent addition of the combined-cycle system, mercial use by 1990, with at least 2 available and then the coal gasification plant as baseload today. These second generation technologies are, power demands increase. in order of development/commercial status, 1) Texaco Partial Oxidation, 2) the Dow Syngas Another very important conclusion is that the cost Process, 3) British Gas/Lurgi Slagging Gasifier, and of electricity curve shown in Figure 2 for the 4) Shell Coal Gasification Process. 16CC plant could be considered essentially identical to a pulverized coal (PC) plant with scrubbers or There are other emerging systems with less operat- an atmospheric fluidized bed combustion (AFBC) ing experience or experience at smaller scale in- plant, since all three plants have comparable capi- cluding the Allis Chalmers KilNgas Process and the tal costs, and capital charges dictate the cost of Kellogg Rust Westinghouse (KRW) gasifier. electricity at capacity factors up to 0.5. Phased Implementation of 16CC Powerplants The important point is that both the PC and AFBC plants are uneconomic in other than baseload serv- EPRI is working with PEPCO and 11 other Utility ice, and neither can be "phased in" at a combined Coal Gasification Association (UCGA) member cycle plant site. In Spencer's view, 1) the im- electric utilities to determine their individual sys- mediate need for peaking and midrange capacity in tem requirements. The primary immediate new the industry, 2) the present low price of premium generation needs of nearly all of these utilities are fuels, and 3) the ability to phase in the 16CC plant for peaking (500 to 1,000 hours per year of almost guarantees the 16CC option a large market operation) and midrange (1,000 to 3,000 hours per share beginning in the mid 1990's. year of operation) capacity additions. These needs are best met with combustion turbines and combus- Of course, all utilities will not choose a single tion turbine combined cycles. technology for their future; thus all important op- tions need to be supported through full scale In the longer term —post 1995--there will continue demonstration systems. However, the utility in- to be a need for peaking and midrange units, but dustry will emphasize the more environmentally at- new baseload generation will also be required. This tractive options in the future. led to the concept of phased introduction of 16CC powerplants and the extraordinary flexibility this concept provides the utility industry. For a fixed coal price of 1.55/10 6 BTU, the crossover fuel price, (Figure 2), to add the coal gasification plant is approximately $4.50/106 BTU (0.7 capacity factor). With today's natural gas

4-18 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 2 IGCC PLANTS VERSUS COMBINED CYCLES AND SIMPLE—CYCLE COMBUSTION TURBINES

Crossover Capacity Factois to . Coat price . $t55,1tii I. No real tt Pike 0.S tistimid IGCC Plantsn 0.7 combined 0.6 05 cc 0.4 Combined cycles vs 0.3 0.2 0.1 1 2 3 4 6 6 7 Fuel Price $/106Btu (Excl. Coal) (Constant 1985 1)

#0 4 If

4-19 SYNTHETIC FUELS REPORT, DECEMBER 1986 ECONOMICS

USES FOUND FOR GASIFICATION SLAG TABLE 1 A study carried out for the Electric Power Re- SLAG CHARACTERISTICS search Institute by Praxis Engineers, Inc. has ex- amined possible uses for the gasifier slag produced during coal gasification. Generalized applications Specific Gravity 2.08 were studied by using the slag produced at the Moisture on As-Received Basis 14.0% Cool Water project as the model material. Maximum Dry Density attained at 23% moisture 89.5 pcI The Cool Water Coal Gasification Program gasifies Hardness 5.5 mohs about 1,000 tons of coal per day to produce 100 Expansion Index 0 MW of power. About 110 tons of slag per day are fl-value 72 produced by the operation. The slag is currently Size Distribution: stored at the site, and will continue to accumulate at the rate of 26,000 tons per year at the present Size % Passing rate of operation. This means that the storage facilities will eventually be filled up and alternate 3/8" 100 disposal methods for the slag will have to be 4 M 99 found. A number of projects in the planning stage 16 M 51 at this time should benefit from the development 100 M 19 of slag utilization concepts. 200 M 12 Market Development General: Glassy material containing some carbon, particularly in the finer sizes Praxis points out that the conventional materials used in construction have been accepted over long periods and now form the basis of standards for the industry. New materials such as slag will not always fit into the framework of existing specifica- 1. AGRICULTURE tions, even though better performance and greater —Soil conditioner economy could be achieved. Some of the problems --Lime substitute foreseen include: --Low analysis fertilizer — Carrier for insecticides - Only limited information is available on the 2. INDUSTRIAL MATERIAL slag characteristics; — Abrasive grit — Catalyst and adsorbent - Prevalent standards and codes evolved from — Roofing granules conventional materials; --Industrial filler — Mineral (slag) wool production - Psychological problems of acceptance; — Fitter media 3. CEMENT AND CONCRETE - No credit given for costs which would --Concrete aggregate otherwise be incurred for disposal of the --Mortar/grouting material slag; --Pozzolanic admixture —Raw materials for Portland cement - Offering the slag in an "as-is" form, whereas production conventional materials are prepared or --Masonry unit production graded to specifications; 4. ROAD CONSTRUCTION AND MAINTENANCE - Location of the Cool Water facility in a --De-icing grit non-urban area. --Fine aggregate for bituminous pavement The known characteristics of the slag are given in —Base aggregate Table 1. --Sub-base aggregate --Seal-coat aggregate Identified Uses Foir Slag 5. SYNTHETIC AGGREGATE --Lightweight construction aggregate A number of conventional and some innovative con- --Landscaping material cepts for slag utilization were identified in the —Sand substitute Praxis study. These range over a broad area from 6. LAND FILL AND SOIL STABILIZATION highly practical, low lead-time concepts to those --Soil conditioner for improving requiring extensive research and development. On stability the basis of the general end uses, the concepts —Structural fill were divided into seven broad categories: --Embankment material

4-20 SYNTHETIC FUELS REPORT, DECEMBER 1986 7. RESOURCE RECOVERY sively by abrasion. However, its use as sub-base —Source of carbon and base material in road construction is quite --Source of magnetite feasible. --Source of iron, aluminum, and other metals Synthetic Aggregate Agriculture The presence of carbon and the fusibility of the slag suggest the possibility of increasing the ag- The use of slag for agricultural purposes is sug- gregate size. The slag could be formed into pel- gested by its loose, granular structure, its lets, and the pellets could then be sintered, produc- alkalinity, and its relative chemical stability and ing a lightweight aggregate for use in concrete and non-toxicity. Agricultural applications have already other applications. been demonstrated for fly ash. The slag can be used to loosen clay-type soils and improve their Landfill Applications drainage characteristics. The use of slag as a structural fill material has a Industrial Materials parallel in the widespread use of fly ash and bot- tom ash for embankments, structural fills, and The slag could conceivably be used for a variety of backfills. Considerable experience has been gained industrial purposes, ranging from such low in this regard with highway and building construc- technology uses as sandblasting grit to its possible tion. use as a catalyst. Other uses in this category would include the manufacture of for insulation, and use as a filler in plastics and other products. The slag can also be used in the manufacture of TABLE 2 asphalt roofing products such as roll roofing, strip shingles, and individual shingles. Generally, the COMPARATIVE granules required for this application need to be in COMPOSITION OF TYPICAL BLAST-FURNACE the 6 x 70 M size range, and the slag can easily SLAG, COAL ASH, AND COOL WATER SLAG meet this requirement by a simple screening step. (Percent)

The slag has approximately the same composition Cool as fly ash and blast-furnace slags, as indicated in Mineral Blast Furnace Slag Utah Coal Ash Water Slag Table 2. Both of these materials have been used for the manufacture of mineral wool for use as in- SiO 2 32-42 40.0 40-55 sulation. Al2 0 3 7-16 11.5 10-15 CaO 32-45 25.0 10-15 Construction Materials Mgo 5-15 4.0 2-5 Fe2 0 3 0.1-1.5 7.0 5-10 The slag can he used as mortar, as fine aggregate MnO 0.2-1.0 NA NA in concrete, and as raw material for the manufac- S 1.0-2.0 NA Cl ture of Portland cement. The slag can also be used as replacement for fine aggregate or sand in concrete and mortar. In both cases, its pozzolanic tendency is useful and appears to add to the strength of the concrete or mortar. The Cool Water slag also meets the general size specifica- tions for these applications. Resource Recovery The carbon content of the slag is much higher than the 1% allowable Unfit placed on aggregate. The The slag produced by coal gasification contains a tests carried out to determine the suitability of the number of potentially recoverable elements. Its Cool Water slag for concrete making showed its exact mineralogy and composition depend on the sulfate soundness to be acceptable. However, its specific nature of the coal, the gasification process alkali reactivity is somewhat high and may limit its and conditions, and the quenching or cooling use to cements containing less than 0.6% alkalies. methods used. Many constituents in the slag ap- pear to be readily recoverable. However, resource Road Maintenance and Construction recovery from coal wastes, even when shown to be technically feasible, has not found widespread The use of slag in the construction of roads was commercial application. For most elements, com- studied by testing slag asphalt mix designs. By it- peting richer ores are available, the technologies self, the slag was not found to be a suitable for their reduction are well understood, and the in- material for surface pavements due to the lack of frastructure for their use exists and is well coarse particles and the tendency to degrade exces- entrenched.

4-21 SYNTHETIC FUELS REPORT, DECEMBER 1986 Outlook Background The major conclusion of the Praxis study Is that a According to Ebasco's presentation at the 21st In- number of uses can be found for the Cool Water tersociety Energy Conversion Engineering Con- slag. Its application in road building and concrete ference in August, the Army wanted to determine making could easily be advanced with only minimal the feasibility of using cogeneration systems based further work. Similarly, its use as a soil amend- on coal-gas-fed fuel cells to replace oil and gas ment Is relatively straightforward. The only work fired heating and power plants at Army installa- that needs to be performed for this purpose is a tions. The four sites and the fuel cells considered study of the long-term leaching behavior of the were as follows: slag in the presence of various kinds of soils. All other uses of the slag discussed in the study will Washington, D.C. - UTC require further development effort. Scranton, PA - Westinghouse and UTC Fort Hood, TX - UTC Fort Creely, AK - Westinghouse and UTC System Design Design of the gasification/fuel cell cogeneration (GFC) system is shown schematically in Figure 1. ARMY STUDIES ECONOMICS OF COAL Coal is fed to air blown atmospheric single-stage GASIFICATION/FUEL CELL COGENERATION Wellman-Calusha gasifiers which are commercially available in sizes needed. This type of gasifier can A study by Ebasco Services, and supported by the handle a large range of coals with relatively high United States Department of the Army investigated conversion efficiencies. Coal feed rates are fixed cogeneration systems consisting of coal gasifiers, by the requirement to provide sufficient hydrogen gas processing, a fuel cell and supporting heat flow to the fuel cell anode. recovery systems for four different sites. Each plant was sized to accommodate either one 11.6 Coal reacts with air and water in the gasifier to MW United Technologies or one 7.5 MW Westin- produce hot gas (480F to 770F) containing from ghouse fuel cell with design and performance vary- 15% to 19% hydrogen. Tars and oils are cooled ing according to coal properties and the proportions and condensed in a spray tower and the entrained of electric and thermal energy output. droplets separated electrostatically. The cooled gas

FIGURE 1 COAL GASIFICATION FUEL CELL SYSTEM

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4-22 SYNTHETIC FUELS REPORT, DECEMBER 1986 is then compressed before entering a CO shift sec- FORT HOOD, TEXAS - This site requires a Central tion where carbon monoxide reacts with steam over Cooling and Heating Plant receiving steam and a catalyst to produce carbon dioxide and additional electricity from the GFC and supplying a section hydrogen. Sulfur impurities must be reduced to of Fort Hood with chilled water and high tempera- less than S ppm to inhibit degradation of the fuel ture water through an underground pipe distribution. cell electrodes. FORT GREELY, ALASKA - This plant is located The cleaned gas is fed to phosphoric acid fuel cells ninety miles southeast of Fairbanks. Because of which electrochemically convert hydrogen and winter severity (design temperature is minus 48°F oxygen to DC current with an efficiency of about and 13,698 average annual degree days) and 55 percent. remoteness, features for this site include total enclosure of the plant, extensive heat tracing and The Thermal Management System (IllS) receives GFC process cooling based on ethylene glycol solu- and manages heat from the fuel cell electrochemi- tion and dry cooling towers. cal reaction, from the catalytic combustion of fuel cell vent gases and from any process heat source To eliminate Fort Greely dependence on oil, it is including by-product tars and oils. "Managing" necessary to supplement GFC capacity with addi- these thermal sources means converting their out- tional gasifiers that supply raw gas for firing in an flows into steam or hot water for direct use in a existing but modified oil fired boiler. process or in space heating and cooling, and into shaft energy for driving an electric generator or a Performance compressor. Performance of the systems studied is summarized Major components of the TMS are the fuel cell in Table 1. cooling water system, heat recovery steam gener- ator (H RSG), steam/eondensate/feedwater system, The tars and oils are an important energy source steam turbine and condenser. for the system when fired as a supplementary fuel. For the Scranton UTC system, this source was 21% The fuel cell cooling water system circulates con- of coal input energy. Because the Wellman-Galusha densate quality water through the fuel cell stacks, gasifier can accept up to 15% of the coal feed as generating 29,000 pph of saturated steam at 240 fines (less than 1/4 inch mean diameter), all fines psia. Energy in the fuel cell anode and cathode up to that percentage are assumed usefully con- vent gases is recovered by catalytic combustion of sumed. With 25% fines, Fort Greely is the only the mixture, raising its temperature from 405°F to site requiring disposal of excess fines. about 1200°F. It is then let down through a gas expander which drives a generator (2300 to 2500 At all sites, air, water, solid and hazardous wastes kW) and the cathode air compressor. from the GFC would represent small additions to those produced by the existing facility. Criteria Firing the tars and oils produced during gasification pollutants ( NO x S021 CO, particulates and H25) in a burner located upstream of the HRSG raises are below limits which would classify the GFC as a the expander exhaust gas temperature to 1200F, "major source" or as a "major modification". approximately doubling the heat recovery. Ebasco concluded that special environmental control However, depending on the available market for measures would not be required at any of the sites. tars and oils, this by-product may be sold rather than burned. Econumics Study Sites A feasibility fbi criterion (after-tax return' on to- tal private investment) of 10 percent was used to The four selected sites differ in thermal and test each site for initial economic feasibility. With electric load characteristics, climate, geography and this measure, no private debt was assumed, but setting -- from inner-city to remote and unpopu- rather the entire private investment was treated as lated. equity. Under these conditions a 10-15 percent 1101 will usually translate into an ROE (Return on WASHINGTON, D.C. - This urban site is on the Equity) of about 25 percent under a debt service main campus of Georgetown University. The exist- structure with a debt coverage ratio of at least ing heating plant consists of a 625 psig coal fired 1.5. fluidized bed boiler and two 275 psig gas fired boilers feeding steam turbine driven centrifugal On July 12, 1982, Congress enacted Public Law PL chillers and the campus heating system. 97-214, Section 2394 of which permits the military to accommodate long-term contracts (up to 30 SCRANTON, PENNSYLVANIA - This facility is lo- years) with third-party eogenerators or other energy cated in downtown Scranton. The Army Ammuni- projects. The Department of Army provided funds tion Plant process and space heating loads are sup- to Ebasco for the Facility planning study. The ob- plied with 75 psig steam from gas fired boilers. jective was to determine if the system would lead The TMS designed for this site is identical to that to increases in energy efficiency, greater conserva- of the Washington, D.C. site except that the firing tion, and economic benefits sufficient to attract of tars and oils produces an additional 41,000 pph third-party equity investment, of 240 psia steam.

4-23 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1

PERFORMANCE SUMMARY

Wash. DC Scranton, PA Ft. Hood, TX Ft. Greely, AK

Fuel Cell* UTC W IJTC W Coal Type Eastern Sub Bituminous Anthracite Lignite bituminous-C Coal Input, tpd 172.2 91.5 286.3 175.6 Gross Power, MW ac 14.4 8.8 14.6 9.9 Auxiliary Power, MW 3.6 4.1 3.5 4.8 Net Power, MW 10.8 4.7 11.1 5.1 Gross Steam Output, PPH 38,100 36,400 66,800 46,300 Steam for Internal Use, PPH 21,500 33,500 25,500 32,600 Net Available Steam, PPH 16,600 2,900 41,300 13,7000 Tars and Oils, PPH 2,163 0 1,434 878 Thermal Efficiency, % 23.8 19.0 36.9 28.9 E/T Ratio, kW/mmBtuih 5400 1600 540 370

* UTC: United Technologies, Inc. W: Westinghouse

** Available either for export or power generation

Some of the plant characteristics, operating parameters and economic assumptions used in the - Base Case assumptions were 0 percent near analyses included the following: term fuel price escalation rate for 1985-1990 and a 5 percent long-term escalation rate - The plant capacity factor was 81 percent. for 1990-2009.

- The government would fund 70 percent of The capital costs were expressed in 1985 dollars the capital cost and the private third party and were estimated by Ebasco based on site- owner would fund the remaining 30 percent. specific facility designs and information obtained from major equipment suppliers. Table 2 Is a - The plant start-up was scheduled for January breakdown of the cost estimates. 1990.

TABLE 2 CAPITAL COST ESTIMATES (In Thousands of 1985 Dollars) Item Scranton, PA Ft Greely, AK Ft Hood, TX Wash., D.C.

C FC Plant Building & Site Development 3,900 12,700 3,500 14,300 Coal Handling & Storage 1,700 3,900 1,700 1,700 Coal Gasification 3,600 6,400 5,000 3,600 Gas Cooling, Cleaning & Compression 1,400 1,900 1,400 1,400 CO Shift 600 800 600 600 Sulfur Removal & Recovery 5,600 7,500 5,400 5,600 Process Condensate Treatment 1,700 2,400 1,660 1,700 UTC 11 MW Fuel Cells & Power Conditioning 15,400 18,400 15,400 15,400 Thermal Management 1,900 4,200 2,400 1,900 Cooling Water 900 2,700 800 900 Water Treatment 400 500 400 400 Balance of Plant 2,800 a GFC Plant 39,100 64,200 39,700 49,500 Preproduction Costs 940 1,740 1,000 940 Inventory Capital 280 420 270 280 Initial Catalysts & Chemicals 720 350 450 720 Total Plant Investment 41,040 66,710 41,420 51,440

4-24 SYNTHETIC FUELS REPORT, DECEMBER 1986 The Scranton, Pennsylvania site was used to il- - Debt/equity ratio of 2/1 lustrate the results of the economic study. Costs and benefits were evaluated for both the Army and - Debt repaid over 15 years with a constant the a Fe plant third-party owner. principal repayment

Under the commercialization cost sharing concept - Average Interest rate of 13 percent over the of the program, the government would fund 70 per- life of the loan. cent of the capital cost of the GFC plant, and the private party would fund 30 percent. Under this - 10 percent investment tax credit, 5 year arrangement, the government capital contribution depreciation would be $35.7 million and the private contribution would be $15.3 millidn. Using the base scenario for energy prices the ROE for Scranton was estimated at 24 percent, increas- These estimates are based on a C FC plant con- ing to 51 percent when including the syngas tax struction cost of $39.1 million and the preproduc- credit through 1999. tion cost of $0.9 million, a total of $40 million (1985$), as shown in Table 1. Assuming a 5 per- The last section of Table 3 summarizes these cent construction cost escalation until equipment is results. The operating cash flow (revenues minus delivered, and that construction costs are allocated costs) is the same as the ROI analysis. However, at a rate of about 20 -- 40 -- 40 percent for the because the equity invested is only one-third of the three construction years, 1987-1989, the total in- private capital, the return of the net cash flow on stalled cost would be $51 million. the equity is 24 percent.

The total GFC plant revenues for Scranton in 1990 The Scranton Site was found to be marginally are estimated at $8.0 million, and total costs are feasible. The Fort Greely Site was found to be a $5.8 million, resulting in an operating cash flow of slightly stronger candidate for C FC plant applica- $2.2 million. This operating margin increases tion. Economic and financing characteristics steadily, with a 10-year total operating cash flow provided the G Fe third party owner with a 31 per- of approximately $29 million. cent return on equity.

The resulting ROl under the base scenario is ap- The key to achieving a suitable return on total in- proximately 9 percent. The results under Scenario vestment or on the private equity required for a 2 (flat near-term fossil prices and high, sustained CFC project is, of course a sufficient operating long-term prices) is approximately 7 percent. Un- cash flow available for debt service and for the der Scenario 3 (5 percent annual increase in near- plant equity investors. Analysis of the revenues term fossil energy prices, and high, sustained tong- shows that the electric power revenues dominate term inflation), the net cash flow would decrease the cash flow, comprising 80-95 percent of the to- significantly during the first ten years of operating tal, depending on the site. Revenues from steam to 2/3 that of the first two scenarios and an ROl and the sale of tars/oils or coal fines make limited of about 0 percent. impact. Two reasons for the low steam revenues are; (1) low steam sales price to provide An ownership and financing analysis was also savings/incentive for the site, and (2) poor thermal carried out for the two sites that showed accept- . able economic results, Scranton and Fort Creely. The following assumptions were made for the In terms of absolute rates, a C FC plant would Scranton financing analysis; make economic sense in utility areas where the purchased power or avoided cost rate is at least 6 - Private capital contribution of 30 percent of cents/kWh with escalation expected to be the same total as or more than inflation over the medium to long term.

4-25 SYNTHETIC FUELS REPORT, DECEMBER 1986 TABLE 3

SCRANTON SITE GFC PLANT ECONOMICS AND FINANCING ANALYSIS SUMMARY ($Millions)

10-Year Total Economic Variable 1990 1995 (1990-1999)

Base Scenario (Flat near-term fuel prices, 5 percent/year long-term)

Revenues: Electric 7.7 11.1 100.5 Other 0.3 0.5 4.2 Subtotal 870 11.6 104.7

Costs: Fuel 3.0 3.8 37.1 O&M & Other 2.8 4.2 38.8 Subtotal 5.8 8.0 75.9

Operating Cash Flow 2.2 3.6 28.8 Tax Saving (Payment) 0.3 -1.8 -7.7 Net Cash Flow 2.5 1.8 21.1 ROI 8.9%

Scenario 2 (Flat near-term fuel prices, 10 percent/year long-term)

Net Cash Flow 2.5 1.3 19.6 ROI 7.2%

Scenario 3 (Fuel price escalation 5 percent/year near-term, 10 percent/year long-term)

Net Cash Flow 21. 0.7 13.1 ROI 0%

ROE Analysis: Base Scenario

Operating Cash Flow 2.2 3.0 28.8 Total Debt Service -2.0 -1.6 -16.3 Tax Saving (Payment) 0.9 -1.3 -3.1 Net Cash Flow 1.1 0.7 9.4

Debt coverage ratio 1.1 2.3 1.8 ROE (2/1 debt/equity ratio): 24 percent (Average)

4-26 SYNTHETIC FUELS REPORT, DECEMBER 1986 TECHNOLOGY

sGTh LFC PROCESS PLANNED FOR SCALEUPS Development History SC! International developed the LFC Process using SC! International has developed a process using low a program of laboratory tests, process tests in temperature pyrolysis for extracting liquids from retorts of increasing size, and development of com- coat (LFC) and producing an improved solid fuel puter process models. The scaleup involved four (PDC, process derived coal). development units whose processing capacity ranged from four He in a batch mode to continuous opera- The LFC Process is a low-temperature, ambient tion at an input rate of 1,200 lbs/day. The test pressure pyrolysis process that predominantly in- unit capacities have been: volves phase changes and single reactions, rather than complex chemical reactions that are inherent 1. Bench-scale Test Equipment 4 lbs in high-temperature, high-pressure liquefaction 2. Process Test Unit 44 Ills processes. 3, Process Development Unit 120 lbs 4. Continuous Process According to SC!, the LFC process is based on two Demonstration Unit 1200 lbs/day observations: A summary of the SQl development history includ- 1. When the coal is pyrolyzed at low tempera- ing throughput and calendar dates is presented in ture, the hydrogen in the early evolving Figure 2. volatile components of the coal is sufficient to produce high grade petroleum distillate Process Equipment type liquids. A major advantage of the LFC process is that 2. When the conversion to liquids is carefully there is virtually no new equipment technology controlled and only the distillate quality required in scaling up the process from smaller fractions are removed, a processed dry coal tests to the initial Commercial Demonstration (PDC) can be produced. The PDC is a bet- Plant, designed to process coal throughput in the ter fuel (more reactive and cleaner burning) range of 1,000-2,6000 ton/day. This is because the than the raw coal or the conventional LFC Process is using standard mechanical equip- chars. ment already handling these tonnages on a con- tinous basis. SGI's LFC Process is said to incorporate significant improvements in coal pyrolysis methods: LFC Process plants include the following conven- tional components: - First, new systems of sensors are included that analyze the composition of the incoming Coal Receipt and Handlin coal and outgoing product streams. Appropriate equipment and procedures ap- plicable to the specific type and quantity of - Second, the operating conditions of the plant coal are used to transport, weigh, crush, size, are continuously adjusted, by a system of and store the raw coal. Coal fines are nor- hierarchical computer controls, that optimize mally stored and used on site for drying and the qualities of LFC liquid and solid products process heat. within specified limits. Coal Drying The resulting product mix includes gas, light oils The LFC process is designed to accept coal and mid-range distillate liquids and a highly- with moisture contents up to 40%. In the case reactive solid char. Any one of these products or of higher moisture content coals, for example a specified combination can be used for the Loy Yang Brown Coal with 62% moisture, addi- primary control setting in the optimization of the tional drying capacity is provided. This extra process. A wide variety of coals can be used as drying has an economic impact on the whole the raw material for LFC processing, including low- process but has no scaling implications. grade and waste coal. The basic LFC Process can be implemented in a number of applications: (1) as Pyrolysis Unit LFC-CoGcn plants primarily for electric cogenera- The first commercial pyrolysis unit is a 26' tion with oils and liquids as a by-product, (2) as circular-grate retort designed, manufactured, in- stand-alone LFC plants operated primarily for oil stalled, and warranted by Salem Furnace Com- production with process derived coal (PDC) as the pany. There is extensive experience with these second product, and (3) as an emission control units as Salem has already designed, built, and component in front of a utility boiler, operated as installed over 20 similar units ranging in size a "Best Available Control Technology" (LFCBACT). from 16' to 50' in diameter, operating for a variety of pyrolysis applications. A schematic of the LFC-CoGen plant configuration is shown in Figure 1.

4-27 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE I

C1.L '14 _ r_hI1ip _SI

LK

-

pa,

PYROLYZIER fl

I

Liquid Recovery and Storage Char Treatment and Storage The liquid recovery section of the LFC process The processed dry coal (PDC) in an LFC-CoGen is derived from the oil quench and separation System is fed directly to a boiler. For other systems commonly employed in catalytic crack- end-users, the PDC is treated to prevent spon- ing units in the petroleum industry. The LFC taneous combustion in transport and storage. liquids are typically lighter than catalytic Existing systems for handling and cooling metal- cracked effluents and have much less tendency lurgical coke, petroleum coke, and inorganic to form gums and tars. Conventional tank solids can be used. storage facilities and suitable transfer equip- ment can be used. SGI claimes that the key to the simultaneous con- trol of the liquid grade and the PDC quality is a Gas Cleanup System computerized process control system. With new The gas cleanup system used is chosen to suit sensors and controls, the central computer utilizes the actual product characteristics and could in- the coal itself to determine the optimum operating clude existing Lo-Cat or other proprietary sul- conditions for the coal as it enters into the phur removal processes that are available in process. the range of sizes required for LFC process plants.

4-28 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 2 SUMMARY OF L F C PROCESS DEVELOPMENT PROGRAM

Continuous ic-Cen Plant I Bench-scale Process Process Process 33 P8JCrn,ercial S taxis-alone I 'rest Test Develcprent Dc,onstration Electric plant Ut I Ut unit Unit Unit ogenerating with )etnnstfltl4 catrercial uip'cnt Plant Plant Sole (alt) (Flu) (PW) (auJ) tic plant 1388 1990 tate 1983 1984 1986 1986 1387 675 820 7,000- Liquid 0.02-0.1 0.5-1.0 3-5 30-50 fl. 000 tbild pro&rtia, gui/d guild gai/d guild tbild 2600 9000 CoalThra4vst 4 44 200 1 1000 lbs lbs Ths/d wwd toWd tnwd 33 1st coal ut coal Scsia ractor from 1.0 11 4.5 Ii) 4 Previous size l000 1.0 1.2 2.6 5 Qnilative sole 1.0 11 50 500 - 500,000 600,000 5,400,000 facter from Process bench test $30 million $200 minion Capital Cast $0.2 million $0.4 million $0.5 million $0. 6 million $11 million for LPc Component States Complete Complete In Progress In Progress construction Plaited Planned in 1986 Contractor Da'y Iticee Midland Sales Sales Craw Corp. Not Not las 2\rnaee co. Furnace Co selected selected juistralia Various Ltion Chio ado pennsylvania Pereylvania Montana j

shows that the liquids from the L FC process are At temperatures below 800°F, 10% to 20% of the within the range of accepted values with the ex- volatile componenets of coal emerge as gases. ception of oxygen. Depending on the parent coat, Using the appropriate heating rate, an additional the sulfur and nitrogen contents satisfy No. 4 fuel 25% to 50% of the volatile matter is removed be- oil requirements, but the oxygen content generally 10 the form of light and tween 800°F and 1000°F remains above the acceptance level. However, middle range oil distillates, with the undesirable oxygen is less detrimental to liquid quality than the toxic chemicals remaining in the processed PDC. other heteroatoms since oxygen can be removed The process is operated at near-atmospheric pres- without sacrificing hydrogen in subsequent cleaning sures. For this less demanding environment, the steps. investment in the plant and the operating costs are substantially less than for hydrogenation-liquefaction The combined liquid fractions have properties processes. similar to that of crude oils. The distillation data for LFC liquids obtained from Alaska (Usibelli) and The LFC process also alters the processed coal Australian brown Roy Yang) coals show that the (PDC) to became a cleaner and improved fuel be- liquids are comparable to Texas and Saudi light cause some of the sulfur is removed with the gas crudes and much lighter than Kuwait crude. For and all the moisture is removed. comparison with coal conversion products, the dis- tillation curves for H-Coal, SEC and COED oils are LFC Liquids shown in Figure 3. The LFC liquids fall in a band of boiling point temperature range that is much A comparison of LFC liquid characteristics with lower than the curves for these other synthetic the heteroatom content ranges specified for fuel oil oils, thus LFC liquids should be of premium value.

4-29 SYNTHETIC FUELS REPORT, DECEMBER 1986 In the ICT process concept, a coal gasification process with an Inherent thermal gradient (e.g., FIGURE 3 Lurid, staged fluidized-bed processes, etc.) and a catalyst that is sernivolatile under gasification con- DISTILLATION DATA FOR L F C ditions are used. The semivolatile catalyst is suf- ficiently volatile at the highest temperature en- LIQUIDS COMPARED TO OTHERS countered In the lower section of the gasifier, that It Is completely vaporized from the char before the ...... Alaska char Is discharged. The catalyst, however, is non- volatile at the lowest temperature encountered in Montana the upper section of the gasifier so that It precipitates on the cold feed coal. The catalyst, — 1 Mid—distillates I.- l — GaaoUne — 1 1-Heavy fuel oils - therefore, is automatically recycled from the -80 product char to the fresh coal and the need for - /Texas crude H—Coal catalyst recovery is eliminated. Syncrude mode Three different materials have been undergoing i -Range of ,e' j /COED testing by IGT as semivolatile catalysts. These LEC Liquid materials were selected based on an examination of their vapor pressures and the following process as- 80 - sumptions. It was assumed that a catalyst loading aa of approximately 5% wt is sufficient for catalyzing H—CoaI the gasification reactions, that the temperatures in .j 50 ,' Fuel oil - mode the gasifier vary from 6000 to 1600 0 F, that the S gasifier operates at 1000 psig with a product S gas/coal feed ratio of 15 SCF/Ib, and that a rate 40- of loss of catalyst in the product gas of less than 0 1% of the circulation rate of the catalyst in the C gasifier is acceptable. With these assumptions, the 80 - requisite vapor pressure of the 'semivolatile' E catalyst in the hottest section and the coldest sec- tion of the gasifier was calculated to be greater than 1.0 atmosphere at 1600°F (870 0 C) but less than 10 mmllg at 600°F (3150C). SRC The materials identified to have the proper physical properties are shown in Table 1. Arsenic in its elemental form is relatively stable under reducing conditions. Some arsine, As11 3 , formation is 100 200 expected; but at high total arsenic partial pressures Temperature •C and moderate temperatures, more than 99% of the gas phase arsenic is expected to be present as As2 and As4 . Although less is known about the be- havior of cadmium, studies have shown that fines generated in coal gasification are highly enriched in cadmium, indicating semivolatile' behavior in the gasifier. Cesium hydroxide, on the other hand, is IGT TESTS INTERNALLY RECIRCULATED known to enhance the reactivity of carbon towards GASIFICATION CATALYST steam. Studies have also presented evidence for the volatility of cesium hydroxide under gasification The U.S. Department of Energy has provided funds conditions. to the Institute of Gas Technology to investigate the concept of an internally recirculated catalyst TABLE 1 for coal gasification. Some preliminary results of this work were reported to the American Chemical CANDIDATE MATERIALS FOR A "SEMIVOLATILE" Society Division of Fuel Chemistry in Anaheim, CATALYTIC COAL GASIFICATION PROCESS California in September. Temperature (°F) One of the primary economic penalties of many for a catalytic coal gasification processes is the cost of Vapor Pressure of: recovery of the added catalysts from the spent Element 10 mm Hg 1 arm char. For example, the Exxon catalytic coal gasification process requires several stages of di- Arsenic 819 1130 gestion with calcium hydroxide to recover potas- Cadmium 903 1403 sium from the converted char and then the digest- Cesium Hydroxide 1160 1790 ion only recovers between 65 and 85% of the potassium.

4-30 SYNTHETIC FUELS REPORT, DECEMBER 1986 Laboratory-scale batch reactor screening tests Were conducted to evaluate the performance of arsenic, FIGURE 1 cadmium and cesium hydroxide as catalysts for coal gasification. A second phase involved continuous bench-scale tests with cesium hydroxide, the most EFFECT OF ARSENIC, CADMIUM effective catalyst tested in the initial screening AND CESIUM HYDROXIDE ON THE tests, to determine the volatility of cesium hydroxide, i.e., its release from the char before REACTIVITY OF BITUMINOUS CHAR discharge, under continuous gasification conditions. 2.0 REACTIaI CATALYST TIrE. I, A Screening Tests 0 "W C S ARSOIIC S During the catalyst screening portion of the I.e A CADtIILtI C >. cESILII project, 49 char gasification tests were conducted I{YOROXIC€ in a laboratory-scale batch catalyst testing unit. 1.7 0 NOW 3 Figure 1 compares the measured effects of arsenic, cadmium and cesium hydroxide on the rate of gasification of bituminous char. The relative rate of gasification of the uncatalyzed and catalyzed chars is expressed in Figure 1 as the ratio of LYST carbon conversions (Xc) obtained in the catalyzed !;.I.4. tests and the average of all the carbon conversions (Xe) in the uncatalyzed tests at each temperature. A reactivity ratio value of one (shown by the horizontal line in each figure) indicates no effect of the catalyst on the char reactivity. A.

Although a great deal of scatter remains in the NO CATALYST data, it is apparent that cesium hydroxide is more 1.0- R 0 effective than arsenic or cadmium for char gasification. Increasing the reaction temperature strongly increases the catalytic effect of cesium 1200 1300 $400 hydroxide on the bituminous char reactivity, but TEMPERATURE, F had little effect on lignite char reactivity.

Bench-Scale Tests Cesium hydroxide catalyzed and uncatalyzed char FIGURE 2 gasification tests were conducted in a 2-inch I.D. bench-scale unit (BSU). Nine tests were conducted GASIFICATION RATES FOR in the IISU with North Dakota lignite and Illinois UNCATALYZED AND CATALYZED No. 6 bituminous chars. The chars used in the BSU gasification tests were prepared in an KIT BITUMINOUS CHAR fluidized-bed reactor. In this unit char is fed to the top of the reactor by a calibrated screw feeder from a pressurized feed hopper, while the residue 0.10 char is discharged from the bottom of the reactor 0 .ma. into a pressurized residue receiver by a discharge 0• screw. 0:1411 At A number of operational problems prevented all but Tests 2 and 3 from being conducted under con- 0.10 tinuous moving-bed conditions. In Tests 4 and 5 0 the formation of a clinker-like moss blocked the downward movement of the bed and prevented £ residue discharge. In Tests 0, 7 and 9, moving-bed £ conditions could not be attained because the 30.04 catalyzed char adhered to the reactor walls and prevented residue discharge.

Im The dry gas production rates for the tests with un- 1114 TIlE, 1n catalyzed and catalyzed bituminous char during the reactor heat-up and the fixed-bad operating periods are shown in Figure 2. The addition of catalyst to the bituminous char increased the gas production rate by as much as 72%.

4-31 SYNTHETIC FUELS REPORT, DECEMBER 1986

The tests with catalyzed lignite char also showed power generation is the ability to easily remove consistently higher gas production rate than the and recover sulfur. The sulfur In the coal is con- tests without catalyst. Although the lignite char verted by gasification principally to H 2 S and par- showed higher overall gasification reactivity, the tially to COS. Desulfurization of coal gas involves catalyst is 3396 more effective in catalyzing the three process steps: acid gas removal, sulfur gasification of the less reactive bituminous as com- recovery, and tail gas treating. All of these pared to the lignite char. processes are commonly used throughout the oil, chemical and natural gas industries. Figure 3 compares the cumulative carbon gasified as a function of time during the fixed-bed operat- During the last several yearn, a number of new, ing period. A significant increase in the total improved sulfur removal and recovery processes amount of carbon gasified is shown in the have been commercialized. SFA Pacific recently catalyzed char tests. The extent of the increase is assisted Electric Power Research Institute in assess- highly dependent on where the catalyzed char was ing alternative sulfur removal processes for 10CC initially placed in the reactor before heating. based on the Texaco coal gasifier.

EPRi has sponsored numerous detailed designs and economic analysis of Texaco-based 10CC. The FIGURE 3 most recent design utilizes the 'selective" Selexol acid gas removal system, Claus sulfur recovery and SCOT tail gas treating. These are the same EFFECT OF CATALYST ON THE processes that are being utilized very successfully CUMULATIVE CARBON GASIFIED at Cool Water. However, there are a variety of FOR THE BITUMINOUS CHAR new alternatives which can also be considered for this application.

Gas Treating

For the SPA Pacific study, two raw gas composi- tions containing significantly different amounts of 11 2 5 were considered for n system feed rate of 150 million standard cubic feet per day (Table 1).

3. TABLE 1

RAW GAS COMPOSITIONS Volume Percent

From Low Sulfur From High Sulfur Tilt. ala Coal Coal

CO 41.34 47.70 11 2 36.33 33.26 CO 2 21.42 17.19 Results thus far have indicated minimal movement 11 2 S 0.15 1,12 of the cesium from its initial position. This sug- COS 0.01 0.10 gests that either higher temperatures or lower C11 4 0.10 0.09 pressures might be required to effect cesium N 2-Ar 0.60 0.54 volatilization from the char. Total 100.00 100.00

Plans are to conduct larger-scale BSU tests, so that the operating problems encountered in the 2- inch BSU might be avoided, to answer this ques- The raw gas is available at 500 psig and 100F. tion. The treated gas is used either as fuel gas for com- bined cycle power generation, or as synthesis gas for the coproduction of methanol and electric power. For both applications, it is desirable to leave as much CO 2 in the purified fuel gas as IMPROVED SULFUR REMOVAL PROCESSES practical. The two applications require different EVALUATED FOR IGCC levels of sulfur removal,

An inherent advantage of Integrated Goal 1. For the fuel gas application, the H 2 S con- Gasification Combined Cycle (10CC) electric tent should be less than 0.25 grain/100 sef

4-32 SYNTHETIC FUELS REPORT, DECEMBER 1986 (4 ppm by volume) and the COS content A summary of the information on several of the should be as specified by the licensor based acid gas removal processes is shown in Table 2. on the capabilities of the process (incidental to the requested H 2S removal). Principal conclusions from the SFA study were as follows: 2. For the Once-Through Methanol Application, the combined H 2S and COS content should - The Purisol, Sulfinol-M and Selefining acid be less than 0.1 ppmv. gas removal processes have advantages over Selexol for Texaco-based 1(1CC. Sulfur Recovery - None of the aqueous MD EA processes could The sulfur plant and the associated tail gas treat- meet the low 4 ppmv H 2 level specified by ing unit was considered with two different sulfur EPRI and maintain good H 2 S selectively rela- recovery factors so that, when combined with the tive to CO 2. However, at a slightly higher acid gas removal factor, two overall sulfur removal specification of 50 ppmv, an aqueous MDEA and recovery factors will result: process looks attractive.

1. 90%, to satisfy the power plant emission - The basic Claus process is the preferred sul- regulations, and fur recovery technique. Modified Claus plants or acid gas removal processes which 2. 95 plus 96, to satisfy the most stringent concentrate acid gas for Claus feed can be applications that might be required to used when processing low sulfur coal in the satisfy special local conditions or emissions Texaco gasifier, where the H 2 S/CO 2 ratio in offsets. the coal gas is very low.

Conclusions on Sulfur Removal and Recovery - Tail gas treating is not technically needed unless more than 96% recovery of sulfur For most acid gas removal processes, the low sul- overall is required. If tail gas treating is fur specification for the once-through methanol ap- required, cold bed extended Claus and plication requires the consideration of COS Suiften processes have advantages over the hydrolysis to 1125 and a disposable zinc oxide guard SCOT process. bed. Only the complex, expensive liectisol process can meet these severe specifications on a stand- alone basis.

TABLE 2

COMPARISON OF SYSTEMS FOR SULFUR REMOVAL USING HIGH SULFUR COAL

Selexol Purisol Sulfinol-M Selefining 509614 DEA

Product Gas - ppmv 11 2 S 2 4 4 4 50 COS 736 40 (1) 5 3 750 Total 738 44 1) 7 000

Total S Removed 94.41 99.57 99.92 99.94 93.44

CO., Loss, % 7 (3) tO 15 17 15 Sulfur in Acid Gas, 96 40 40 32 30 30

Utilities for 150 MM scfd Fuel Gas --Power: kW 2090 1150 180 (2) 120 --Steam: 14 lb/hr 23.8 5.5 31.7 (2) 21.0

Notes:

(1) Including Lurgi's liquid phase COS hydrolysis; without hydrolysis COS would be 600 ppmv. (2) Seicfining did not provide utilities: judged to be the same as Sulfinol-M. (3) Selexol used flash gas recompression to get low CO 2 loss. Other cases did not.

4-33 SYNTHETIC FUELS REPORT, DECEMBER 1986 - The LO-CAT process, a wet oxidation slightly subatmospheric by venting it through a process, can be used to remove and recover second passage in the feed tube to a vacuum dust the sulfur by direct scrubbing of the raw collector. As the pulverized coal enters the rotor, high pressure coal gas. For IGCC with it is accelerated tangentally and centrifugal forces Texaco gasification this would greatly cause it to flow into radial channels, termed simplify the overall sulfur processing and sprucs, where it forms moderately compacted, leave most of the CO 2 in the high pressure moving, porous plugs of material. These con- coal gas. tinuously renewing porous plugs form the pressure seal. The material is only very mildly stressed in passing through the rotor channels. No agglomera- tion or other significant physical change in the material takes place.

MPG INTERNATIONAL TO MARKET KINETIC The current model of the machine has a 0.71 or EXTRUDER diameter rotor which contains 12 radial sprues. It can be rotated at speeds up to 3,600 rpm. The One of the primary areas needing technical solu- rate of coal flow through the sprues is stabilized tion, according to the U.S. Department of Energy, and controlled by structures, termed control is improved coal feeding into pressurized reactors. nozzles, located at the outboard end of each sprue. Under DOE funding, Lockheed Missiles and Space These nozzles serve to decouple the pressure seal- Company developed the Kinetic Extruder. MPG In- ing function performed by the sprue from the ternational, Inc. has licensed this technology and is flowrate control function. This decoupling is essen- making the Kinetic Extruder available with perfor- tial to the success of this machine. The control mance warranties. nozzle configuration is illustrated by Figure 2. The nozzle orifice forms the choke point in the Performance Characteristics material flow. Flow-rate throttlability is achieved by varying the gas pressure difference across the The Kinetic Extruder High Pressure Powder Feeder control nozzle orifice. is designed to continuously feed dry powder into receivers pressurized to as much as 1,500 psi. A The individual Kinetic Extruder sprues function es- prototype has been built and demonstrated using sentially as short centrifugal-force-driven coal at pressures from 50 psi to 400 psi, with feed standpipes. The flow of material through the rates accurate to plus or minus 0.5%. sprues is a low velocity (order 1 m/s) packed bed type of flow. The Kinetic Extruder High Pressure Powder Feeder employs the centrifugal force of a high-speed rotor The rate of coal discharge from the control nozzles to compact the powder feed in wedge-shaped, is governed by physics similar to that of gravity spoke-like, internal passages called sprues. The flow of particulate materials from bin and hopper resulting continuously replenishing powder plug is apertures. then "thrown out or extruded" through nozzles in the rim of the rotor. The feeder accepts a Wear Rates metered, fluidized powder which is pneumatically transported to the sprue. The powder feed must Establishing wear rates was the principle aim of have the appropriate permeability properties to the most recent DOE sponsored test program. The form a plug capable of sealing against the process internal passages of the rotor are subject to back pressure. The Kinetic Extruder High Pressure abrasive wear and the external surfaces and casing Powder Feeder does not represent a typical ex- are subject to erosive wear. The rotor channels truder because powder characteristics are not al- were fabricated as replaceable parts consisting of a tered by the feeder. The plugging process is funnel section, a sprue body, and the control similar to that of powder in a standpipe, with the nozzle. Sprue parts were fabricated from a range high rotational speed providing a much higher g of materials. The materials denoted by Alloy 12 force. and Alloy 711 were different Haynes Stellite alloys. Previous experience with softer materials has shown Units of 1 to 2 tons-per-hour size have accumu- that the control nozzle is the critical wear point, lated approximately 500 hours of test time in a so these were made of hard carbide materials. closed loop test facility. All of the parts were weighed and measured before The Kinetic Extruder testing, and again after 217 hours of test time pumping coal (Table 1). There was significant wear A cross section drawing of the Kinetic Extruder is of the softer materials; the aluminum funnels lost shown in Figure 1. The device has the main ele- 1096 of their weight, but were still functional. On ments of: a rotor, a stationary feed tube through the other hand, the hard parts wore very little. which material is fed to the eye of the rotor, and Eased on a linear extrapolation of weight loss a pressure housing enclosing the rotor. In opera- rates, and estimates of tolerable weight loss, life tion, a dense phase coal stream is continuously expectancy of the funnels and sprue bodies made drawn into the rotor from a fluidized atmospheric from the hard materials will be in the thousands of hopper. The pressure in the rotor eye is kept hours. No weight change of the nozzles could be

4-34 SYNTHETIC FUELS REPORT, DECEMBER 1986 I' ;tuJI]I;

raiwAaHrfA "16' late *liuft4a fl.1*14K.

1LC _____ p_ i*::.

•

—• ______(•7j1tl!* .. •. I! tXVf!ff9ft14

• ld•lUO*1I

measured and no change in the nozzle flow charac- hour unit presently in existance. Unites of 50 to teristics was found over the course of the tests. 200 tons-per-hour would be required in a commer- cial coal processing plant. To a first approxima- Generally speaking, the surface erosion appeared tion, the total sprue outlet mass flux is held con- quite minor and self limiting. stant in scaling to higher flowrates for a given material and pressure level. That is, the total Scale-Up to Industrial Size Machines sprue area must be increased linearly in proportion to flovrate. This is typically accomplished by use Most applications of the Kinetic Extruder would of a combination of both larger and more numerous require larger sizes than the nominal 2-tons-per- sprues in the rotor.

4-35 SYNTHETIC FUELS REPORT, DECEMBER 1986 FIGURE 2 NOZZLE CONFIGURATION IN KINETIC EXTRUDER

MOWlO PLUG OF GO.M SOLiDS

SPRtJE OWINEL

GAS PRESSURE WiTHIN NOZZLE

cc REPOSE

\ Of SLiPSTREAM •.• • S • x5ftsJ. GAS PRESSURE P,

TABLE 1

SPRItE PARTS WEAR SUMMARY

Avg. Wt. Before Avg. Wt. Change in Part Testing (g) Loss (g) Outlet Diameter

Nozzles:

Tungsten Carbide 204.0 0.0 No change Silicon Carbide 42.4 0.0 No change

Spnse Bodies:

Titanium Carbide 167.2 0.2 No change Stainless Steel 200.9 4.9 0.1 mm

Funnels;

Alloy 12 327.3 0.3 Not determined Alloy 711 310.6 0.6 Not determined Aluminum 94.6 9.8 Not determined

4$ 4$ 4t

4-36 SYNTHETIC FUELS REPORT, DECEMBER 1986 INTERNATIONAL

NIP-PROCESS TESTS COAL GASIFICATION IN LIQUID IRON BATH FIGURE 1 KHD Humboldt Wedag AG (KHD) of West Germany and Sumitomo Metal Industries Ltd. (SM!) of Japan M I P PILOT PLANT SCHEMATIC are jointly developing the MIP (Molten Iron Puregas)-Process for the gasification of coal with oxygen in a Squid iron bath. It was stated at the 6th Annual ErR! coal Gasification Contractor's Conference in October that new runs were planned nihisis for November, 1986. Advantages of the NIP - gas Process include very pure gas quality (70% CO, 30% 11 2 ) and a very low sulfur content. Mnq,zS Ftb Cool go. W gs-,o,,co The KIID procedure has coal, oxygen and slag- 25-10-K NI I1-1V.CQ forming substances injected into the liquid iron Hoc' 'K., s1 bath through tuyeres arranged in the bottom of the -Il! pom reactor. The SM! procedure uses the top-blowing bat st Wall, principle where the substances are blown onto the iron melt through lances. Both methods are being Ind tested in a 10 ton/hr pilot plant. tyslaW J

The conversion ratio is about 0.5 ton/hr of coal per l:oa.xeItg - Slog ton of liquid iron. Typical converters used for the - n production of steel have capacities of 200-300 tons " of iron.

big" WS1 tfOjlcl,ng.lei One of the requirements is to minimize the ac- Slew, cumulation of dust. Therefore the reactor con- figuration should have a surface area of liquid iron related to the specific gas volume produced. For this reason, a horizontal cylindrical vessel has been chosen for the reactor instead of an upright steel Test Results converter (Figure 1). Ground coal dried to a residual moisture of 1.0% The process is being developed to operate at a was mixed with lime of identical grain size and in- pressure of 5-10 bar. jected pneumatically into the iron bath with nitrogen through tuyeres. For protecting the Pilot Plant tuyeres, protective gas is injected through an outer annular space. The pilot plant shown schematically in Figure 1 was set up at MEFOS (Lulea/Sweden) between 1983 The carbon content in the liquid iron bath was ad- and 1985. The reactor is a cylindrical vessel lined justed to 3-4% and kept constant. The bath tem- with a special refractory. perature was 1400-1500 °C.

Ground coal is blown into the iron bath by means The carbon conversion rate exceeded 98%with of an inert transporting gas, and oxygen is blown produced gas composition of 65-70% CO and 25 into the bath as well. Simultaneously, other 30% 112• The content of less than 1% CO 2 and materials required for the reaction can be Intro- approximately 20 ppm 5, and 0.1% C11 4 suggest duced, such as lime for adjusting the slag basicity easy and reasonable gas cleaning. T4 dust con- and steam for tuyere- and bath-cooling. The slag tents have been between 10 and 30 g/m accumulated on the melt surface is discharged in- termittently using standard blast furnace devices. Table 1 shows some of the test results. The hot coal gas is dedusted after having passed a waste-heat system providing for heat recovery.

The gasification rate of the MIP pilot plant is 10 tons of coal per hour. The outside dimensions of the reactor are 7.5 meters long by 4.4 meters diameter.

After completion of erection in July 1985, the first test campaign began in September 1985. Additional test campaigns followed in November 1985 and March/April 1986.

4-37 SYNTHETIC FUELS REPORT, DECEMBER 1986

TABLE 1 A coal gasification process using a fluidized bed under pressure, with high-temperature scrubbing of dust and sulfurous compounds is being developed at MIP PILOT TEST RESULTS the Institute of Mineral Fuels ([Gil. The process has also been tested with a steam-oxygen blast for producing process gases. A test installation has Molten Iron 30.9-40.7 tons, 4.3% C been built at the Moscow Coke-Oven Gas Plant with a capacity of 1,000 cubic meters of gas per Input hour. Calculations at IGI confirmed an economic Coal/Lime 3.4-4.3 toss/hr advantage for fluidized-bed coal gasification com- Oxygen 1600.-1900. m /hr pared to Steam 350.-400. kg/hr Lurgi gas generators.

Output Relative costs for the production of gas from Coal Gas 7500.-9000. m3/hr Kansk-Aehinsk coal, based on one ton of standard CO 57.8-60.0 % fuel are given in Table 1. 112 28.0-32.0 %

02 0.12-0.18 % H 2 5,COS 20.-100. ppm TABLE 1

Operation figure COMPARATIVE COSTS OF COAL GASIFICATION Basicity B 1 = CaO/Si0 2 8.8-1.9 Iron Temperature 1350.-1400. °C Carbon Content 3.6-4.1 % Gas Generator Lurgi Fluidized-Bed

Capital investment, rubles 22.2 15.6 Cost, rubles 9.4 8.2 Recurring expenditures, rubles 12.1 10.1 A total of 3 different coal qualities have been used Correlation of expenditures, percent 100.0 84.1 for the tests.

The MIP coal gas is said to be especially suitable for producing synthesis gas as feedstock for the production of ammonia, methanol, etc. However, when compared with the steam reforming process for natural gas, the use of MIP coal gas is not now Underground Coal Gasification profitable. However, the MIP process is expected to be quite promising in the long run. Practical work on underground coal gasification began in the USSR in the 1930s and has continued until today. Several stations were built that processed in excess of 35 billion cubic meters of USSR SEES ADVANTAGES FOR FLUID BED AND gas over the period of their operation. UNDERGROUND COAL GASIFIERS Two underground coal gasification stations using an As reported in Moscow UGOL, the draft of the air blast are currently in operation--at the Fundamental Areas of Economic and Social Angrenskoye Field and in the Kuznetsk Field. Gas Development of the USSR for 1986-90 projects the produced at the Yuzhno-Abinskaya Station has a development of efficient methods for the replace- heat of combustion of 840-970 kilocalories per ment of natural materials with synthetic ones. cubic meter of gas and is used in boilers in the Highlighted is the development of efficient cities of Kiselevsk and Prokopyevsk. The produc- processes for producing synthetic gaseous fuels tion from a station is 60 million cubic meters of from coal. gas in the winter months and 20 million cubic meters in the summer. The Angrenskaya Station Fluidized Bed Gasification has supplied the Angrenskaya Thermal Electric Power Station since 1961. Work is being conducted in the USSR on the Crea- tion of steam-gas power installations integrated The operating UCG stations are small and cor- with solid-fuel gasification under pressure in a respond (in quantity of heat production) to mines of steam-air blast. The most progressive area is the 100,000-400,000 tons of coal a year. The small combination of fluidized beds with high pressure. capacity of these stations and other factors (low The solution of this problem will make possible the heat of combustion, high cost of electrical energy, efficient utilization of sulfurous solid fuel in instal- gas leakage) are causing relatively high production lations that are more efficient than steam-turbine costs. Currently the recovery of coal by tradi- power plants. tional methods is less expensive than the production

4-38 SYNTHETIC FUELS REPORT, DECEMBER 1986 of the same quantity (heat equivalent) of fuel by coal dust which is being injected directly into the underground gasification. However, it is believed jet. No inert gases are formed (carbon dioxide, that improving underground gasification technology water vapor), and the synthesis-gas obtained (carbon and increasing the capacity of the stations can lead monoxide, hydrogen) appears to be very pure. Liq- to a significant reduction in costs. The Yuzhno- uid methanol or gasoline can also be obtained with Abinskaya and Angrenskaya stations could become the aid of catalysts. profitable if their productive capacities were in- creased to 450-500 million cubic meters and to 1.5 The method of converting coals with the aid of billion cubic meters of gas a year respectively. will introduce revolutionary changes into power engineering techniques. The The major use of underground coal gasification is USSR Energy Program is focused on processing in- to produce gases for electric power generation. expensive Siberian coals. Now a third of the coal Economic calculations at 101 compared the produc- in the country is extracted by the open method and tion of 1,000 kilowatt-hours of electricity using gas in 20-30 years this proportion will double. The in- produced by underground gasification, to the com- expensive surface mined coals are very moist and bustion of ordinary coal, as seen in Table 2. with low calorific value, it is not expedient to transport them for a great distance by rail. TABLE 2 Therefore it is planned to burn some of the coal at electric power stations and to convert some into COSTS OF ELECTRICITY FROM UCC AND FROM ORDINARY gaseous and liquid fuel, suitable for transport along COAL COMBUSTION pipelines for long distances.

Gas Produced at Combustion of The Power Engineering Institute is working on the a UCG Station Ordinary Coal problem of using plasma techniques at coal- pulverizing electric power stations. At electric Capital investment, rubles 43.9 43.0 power stations the boilers are quite complicated to Operating costs, rubles 8.4 9.8 Recurring expenditures, rubles 15.0 15.8 operate because the heated surfaces are subjected Correlation of expenditures, percent 95.0 100.0 to slagging and erosion by ash. Harmful sulfuric oxides and nitrogen, as well as ash residues, are expelled into the air along with the stack gases. With plasma gasification of coals all these problems are simplified. For example, the sulfur is con- verted into hydrogen sulfide which can be removed These data suggest that using gas from underground from the gas easily. If the coal is oxidized not by coal gasification to produce electricity is the more air but by oxygen then the gas volume (and cor- economical. The economic efficiency of UCG can respondingly the heated surface in the boiler be raised by enriching the air blast with oxygen. furnaces) is reduced five-fold. Finally, instead of low-grade coal fuel, gas with a higher heat- In the process of scrubbing 13CC gas of harmful producing capacity, obtained from the coal, can be impurities, valuable products such as sulfur, phenol, burned. carbonic acid, ammonia fertilizers and others are obtained, which substantially improves the economy The plasmatron uses direct current and has been of the 13CC stations. developed at the Institute of Thermophysics of the Siberian Department of the USSR Academy of The article suggests that the current underground Sciences. The plasma gasification of coal has ob- coal gasification process could be improved con- tained broad recognition, and in particular, has siderably by further scientific research and testing been approved by the technical council of the to raise the "power efficiency factor." USSR Ministry of Power and Electrification. The Slavyanskiy Hydroelectric Power Station is begin- ning to use plasmatrons to improve the combustion of coal dust in the furnace of the steam boiler. Analogous work in the combustion of local coals USSR STUDIES PLASMATRON COAL has been begun by specialists at Alma-Ata and in GASIFICATION PROCESS Frunze. An article in lzvestiya states that large facilities to process inexpensive local coals into gaseous and liquid fuels are to be constructed in Siberia by the end of the century. Although there are many NYNAES GASIFICATION COMPLEX HIT WITH methods for converting coal into liquid fuel, one of SETBACKS the most promising is thought to be plasmatron technology. The Nynaes energy-chemicals complex, which was meant to make Sweden self-sufficient in ammonia A plasmatron is an apparatus in which an are dis- production as well as supplying half of Stockholm's charge burns constantly and heats a stream of gas annual heating requirements, has been told to being passed through it to a temperature of 10- change its original plans in order to obtain permis- 20,000 degrees. The incandescent gas ignites the sion to operate.

4-39 SYNTHETIC FUELS REPORT, DECEMBER 1986 The Swedish Franchising Board will give Nynaes ap- ISRAELI CO-RETORTING OF COAL AND OIL proval only if it introduces measures to generate SHALE WOULD BREAK EVEN AT $22/11ARREL electricity for the urban grid and cuts sulphur emissions to less than 3 mg per megajoule, which is well below the existing limits. Work is being carried out at the Hebrew University of Jerusalem on co-retorting of coal and oil shale. Under the original plan, the project sponsors were The work is funded under a cooperative agreement Nynaes Petroleum, Afia (the Swedish industrial gas with the United States Department of Energy. The group, parent of Nynaes), A. Johnson (the privately project is exploring the conversion of U.S. eastern owned Swedish trading and industrial group), Inves- high-sulfur bituminous coal in a split-stage, teringsbanken (the state-owned Swedish investment fluidized-bed reactor. Pyrolysis occurs in the first bank), and Superfos (the Danish fertilizers, chemi- stage and char combustion in the second stage. cals and construction materials group). These data for coal will be compared with similar data from the same reactor fueled by high-sulfur Initially, the complex, Nynaes Energy Chemicals, eastern U.S. oil shale and Israeli oil shales. was to produce about 500,000 metric tons/year of ammonia, which Superfos was to market. however, The project includes research at three major levels: Superfos has now dropped out of the consortium. The complex is now scheduled to produce 250,000 - Pyrolysis in lab-scale fluidized-bed reactor mt/year of ammonia. A 250-megawatt electrical generator to provide energy for both the plant and - Retorting in split-stage, fluidized-bed bench- Stockholm's electric utility will be added to the scale process (1/4 tpd) complex; integration of the electrical production unit into the plans will delay the award of con- - Scale-up, preparation of full-size flowchart, struction contracts for the complex until early next and economic evaluation. year. The remaining members of the consortium are looking for a partner or partners to replace In the past year's research, a preliminary economic Superfos for the US$425 million project. evaluation was completed for a scaled-up process using a feed of high-sulfur coal and carbonate- containing Israeli oil shale. Product yields for the un-optimized bench-scale process are of the order of those from Fischer Assay. SOUTH AUSTRALIA TO BUILD HIGH TEMPERA- TURE WINKLER GASIFIER Based upon the projected distribution of liquid products (different from crude oil), a full-scale The government of South Australia has selected the plant in Israel was estimated to break even at an Rheinbraun High Temperature Winkler (HTW) equivalent crude oil price of $150/ton ($22/barrel). process for the gasification stage of a combined cycle power station fueled by Australian coal. A group led by Uhde GmbH, Dortmund, West Ger- many, is designing the plant. Rheinbraun (Rheinisehe Braunkohlenwerke AG) has started operating a 720 metric ton/day HTW gasification plant at Berrenrath, West Germany. Uhde Gmbll brought the unit on stream. The plant is the final development phase of a commer- cial scale project to produce methanol synthesis gas from Rhenish lignite via the HTW process. The second generation IITW process features high gasifier efficiency gained from greater pressure, reduced energy requirements for gas compression, an improved carbon reaction rate, compact design, and better environmental waste treatment processes. Promising results were reported from the early stages of tests in Germany to establish the suitability of the HTW process in gasifying South Australian lignite. South Australia and West Germany agreed on a A$3.6 million pilot program to evaluate the feasibility of using South Australian lignites for liq- uid fuels production, petrochemical raw materials and power generation.

4-40 SYNTHETIC FUELS REPORT, DECEMBER 1986 ENVIRONMENT

EPA QUESTIONS WHETHER CLEAN COAL Although the Ohio Ontario Clean Fuels coal-oil co- AWARDS MEET ACID RAIN CRITERIA processing project could achieve high removal ef- ficiencies, the technology has no retrofit applica- tion. The U.S. Environmental Protection Agency (EPA) has questioned whether the first round of awards EPA considered Coal Tech Corporation's slagging under the Department of Energy's Clean Coal combustor project to be more in line with the Technology program will provide any help in solving Lewis-Davis report, even though it would be dif- the acid rain problem. EPA evaluated the nine ficult to retrofit and may have questionable proposals selected for funding and compared the reduction capabilities. Energy and Environmental project characteristics to the criteria set forth in Research Corporation's gas reburning and sorbent the United States/Canada Special Envoys report on injection retrofit is also judged to be partially acid rain (Lewis-Davis Criteria). compatible with the special envoys' report on the basis of emissions reductions. The three basic criteria are: M. W. Kellogg Company's 10CC plant using 1. Is the technology suitable for retrofit on fluidized-bed combustion is considered to be more existing utility or industrial boilers? costly than wet scrubbing and impossible to retrofit. 2. Is the removal efficiency greater than 70% [based on %S0 2 + 1/4 (%NOx)] Neither Weirton Steel Corporation's nor Energy In- ternational Inc.'s projects were considered to be 3. Does it cost less than flue gas applicable to the utility sector. desulfurization? Babcock & Wilcox's limestone injection multistage According to the EPA evaluation only one project burner is viewed as coming closest to meeting the meets all three criteria; the eight remaining Lewis-Davis recommendations. EPA, which is a projects are only partially applicable to the Lewis- partner in the project, claims the technology is Davis report (see Table 1). easy to retrofit and provides substantial NO emis- sions reductions at costs of $50-$80/kw. American Electric Power's pressurized fluidized-bed combustion combined cycle retrofit project was The first round of projects has been criticized for cited as being difficult and costly to retrofit. not putting adequate emphasis on low-cost retrofit General Electric's integrated gasification steam in- technologies. jection gas turbine demonstrations would be capable of high removal efficiencies, but EPA says the project is not applicable to retrofit and the cost would approach that of conventional wet scrubbers.

TABLE 1

EPA ANALYSIS OF DOE CLEAN COAL TECHNOLOGY SELECTIONS

Applicability To Lewis-David Criteria High Removal Cost Less Retrofit Technology Efficency Than rOD Ease Overall

LIMB Plus Duct Injection Yes Yes High Yes Gas Reburning With Sorbent Injection Possible Yes High Possible Slagging Combustor With Sorbent Injection Possible Yes Possible Possible PFBC Combined Cycle Retrofit Yes No Low No Underground Coal Gasification - - No No Coal C asification/fiat5tbine Yes Possible No No Coal Liquefaction - - No No Gasification/Combined Cycle Yes No Low No Direct Iron Ore Reduction - - No No

4-41 SYNTHETIC FUELS REPORT, DECEMBER 1986 being set for the DuPont waiver blend other than EPA RELAXES WAIVER ON METHANOL/GASOLINE BLENDS the ASTM specification.

By notice in the Federal Register on October 31, Corrosion Inhibitor the U.S. Environmental Protection Agency removed a restrictive evaporative index requirement on the Two other conditions placed on the DuPont waiver Clean Air Act waiver which had been granted to E. were challenged by OFA. The first was the limita- I. DuPont de Nemours & Company. On January 17, tion that only DuPont's DGOI-100 corrosion in- 1985, EPA granted DuPont a waiver to produce an hibitor he used in the final fuel, with no allowance unleaded gasoline/methanol blend, which contains 5 for an equivalent corrosion inhibitor. The second percent methanol and 2.5 percent cosolvent al- was the requirement that the methanol used in the cohols, provided producers did not exceed an blend meet a 99.85 percent purity level. evaporative index designed to limit the release of vapors to the atmosphere. The Agency also approved the use of an additional corrosion inhibitor, TOLAD MFA-10. This corrosion The reconsideration came after a petition by the inhibitor formulation from Petrolite was tested by Oxygenated Fuels Association (OFA) and after EPA Celanese, and had very similar results to that of reexamined the relevant data. Originally EPA said DuPont's DGOI-100. Other corrosion inhibitor it did not think the American Society for Testing manufacturers are invited to submit test data to and Materials (ASTM) Standard D439 was accept- the Agency to establish, on a case-by-case basis, able for controlling the volatility of the methanol whether their formulations are environmentally ac- blend, because most gasoline being sold actually ceptable. had a lower volatility. EPA's more recent informa- tion, however, shows that volatility levels in com- Methanol Purity mercial gasoline have been rising and are near ASTM's D439 standard. In the original waiver decision, EPA included a requirement of 99.85 percent purity for methanol. Therefore, applying the ASTM standard to the DuPont blend will mean that evaporative emissions In its request for reconsideration, 0 FA argued that from vehicles using the DuPont blend will be no a 90 to 95 percent purity for methanol was the higher than those from vehicles using other normal methanol specification for use as an gasolines. automotive fuel.

Volatility Considerations EPA decided to allow OFA's proposed fuel grade methanol specifications but to retain the limitation DuPont's original application requested a waiver for on methanol water content (0.0596 maximum by the introduction into commerce of a gasoline- weight), as well as the limitation on acidity alcohol fuel consisting of a maximum of 3.7 weight (0.002% maximum by weight). percent fuel oxygen with a maximum of 5.0 per- cent by volume methanol and a minimum of 2.5 The OFA-proposed limits on ketones, esters and a1 percent by volume cosolvent(s), with a proprietary dehydes, also were incorporated by EPA (see Table corrosion inhibitor (DOOl-100). 1), to provide protection against adverse vehicle ef- fects. The EPA decided to grant the waiver on the condi- tion that the finished fuel be blended to meet TABLE 1 volatility specifications for an evaporative index (El) to ensure that the fuel would be no more METHANOL PURITY SPECIFICATIONS volatile than the commercial gasoline it would dis- place from the market. Weight The OFA claimed that the El was unfair and dis- Percent criminatory, since no other automotive fuel had to (Maximum) meet this stringent volatility control. Methanol 90.001 At the time EPA granted the DuPont waiver, the Nonvolatiles 0.005 average volatility of summer grade gasoline was Acetone 0.002 about 0.8 psi RYP less than the ASTM volatility Acidity (as acetic acid) 0.002 specifications for Class C cities. Alkalinity (as amonia) 0.003 Ketones 2 Since that time EPA has obtained data showing Esters 2 that the average flY? of gasoline has increased to Aldehydes 2 Water 0.05 about the level of the ASTM standards. For ex- (2) ample, the average level was about 11.3 psi RVP Appearance for Class C areas with an ASTM limit of 11.5 psi. Minimum For this reason the El restriction was rescinded and 2 Clear and free of suspended matter. no other specific limit for mid-range volatility is

4-42 SYNTHETIC FUELS REPORT, DECEMBER 1986 EPA PROPOSES EMISSION STANDARDS FOR The proposed carbon monoxide, nitrogen oxide and METHANOL VEHICLES particulate standards are identical to those for cur- rent vehicles. Particulate and smoke standards, The U.S. Environmental Protection Agency has which currently apply only to diesel-fueled engines proposed pollution control measures for future and vehicles, are proposed for methanol engines and motor vehicles designed to use pure methanol as a vehicles which are non-throttled in normal opera- fuel. tion (diesel-fueled engines do not typically use a throttle). A carbon monoxide standard for vehicles The proposed rules cover low and high altitude at idle is also proposed. emission standards for methanol-fueled passenger cars, light and heavy trucks and motorcycles begin- The major difference between the proposed stand- ning with the 1988 model year. ards for methanol vehicles and those currently ap- plicable to gasoline and diesel vehicles is in the In general, the proposals specify standards for hydrocarbon emission regulations. Methanol engines methanol-fueled vehicles which correspond with cur- emit higher levels of methanol and formaldehyde rent standards for gasoline and diesel fueled than current engines, and these chemicals are not vehicles. Methanol-fueled vehicles are expected to measured under existing test procedures. Therefore be able to comply with the proposed standards the proposals would require new procedures to be using very similar technology to that now used for used to measure methanol and formaldehyde. gasoline and diesel vehicles. These pollutants would then be included with other

TABLE

PROPOSED EMISSION STANDARD FOR 1988 AND LATER METHANOL VEHICLES AND ENGINES (1]

Exhaust Standards 12] Evaporative Organics Partic- Idle CO Organics [3] Vehicle Class [3] CO NOx ulate % cone) (g/test)

LDV[41 Throttled 0.41 3.4 1.0 N/A1151 0.50 2.0 LDV[4] Non-Throttled 0.41 3.4 1.0 0.20 0.50 2.0 LDT 1(6] Throttled 0.80 10 1.2 N/A 0.50 2.0 (1.0) (14) (1.2) (0.50) (2.6) LDT 1[6J Non-Throttled 0.8 10 1.2 0.26 0.50 2.0 (1.0) (14) (1.2) (0.50) (2.6) LDT 2(7] Throttled 0.80 10 1.7 N/A 0.50 2.0 (1.0) (14) (1.7) (0.50) (2.6) LOT 2(7] Non-Throttled .80 10 1.7 0.26 0.50 2.0 (1.0) (14) (1.7) (0.50) (2.6) IIDE(8] Throttled 1.1 14.4 6.0(10] N/A 0.50 3.0 IIDE[91 Throttled 1.9 37.9 6.0 N/A 0.50 4.0 MD E[8] Non-Throttled 1.3 15.5 6.0(10] 0.60[11] 0.50 3.0 UDE[9) Non-Throttled 1.3 15.5 6.0 0.60 0.50 4.0 MC 5.0 12 N/A N/A N/A N/A

[1] Standards in parentheses apply to vehicles sold in specified high-altitude counties. For all classes of vehicles except MC, no crankcase emissions are allowed. (2] LDV and LDT standards are in g/mi, [IDE standards are in g/BHP-hr, and MC standards are in g/km, unless otherwise noted. (3) Organics standards are expressed in gasoline-fueled vehicle hydrocarbon equivalents, as determined on a carbon mass basis. [4] Standards apply at all altitudes. 151 Not applicable. 161 LDTs up to and including 3,750 lbs loaded vehicle weight (LVW). [7] LDTs 3,751 lbs or greater LVW. 181 HDEs up to and including 14,000 lbs gross vehicle weight rating (GVWF1). (9] HUEs 14,001 lbs or greater CVWR. (101 Beginning in 1991 model year, standard becomes 5.0 g/BHP-hr for all [IDEs. (11] Beginning in 1991 model year, standard becomes .25 g/BHPhr for all non-throttled HOEs except ur- ban bus engines, which are subject to a 0.10 g/BH P-hr standard. In 1994, the standard becomes 0.10 g/BHP-hr for all non-throttled methanol HDEs.

4-43 SYNTHETIC FUELS REPORT, DECEMBER 1986 hydrocarbons in a total organic carbon standard The low-BID gasification industry is defined as air equal to the amount of organic carbon currently al- blown gasifiers using coal as the primary feedstock lowd to be emitted from existing vehicles. and producing a gas with a heating value of ap- proximately 150 BTU/SCF. The low-BTU gas in- The existing standards limit gasoline and diesel pas- dustry over the period from 1975 to 1985 has con- senger cars to 0.41 grams per mile (gpm) hydrocar- sisted of 32 facilities: 16 commercial and 16 pilot bons, 3.4 gpm carbon monoxide, 1.0 gpm nitrogen plants or process development units. Many of the oxides. Diesel cars are also limited to 0.2 gpm commercial facilities employ fixed bed, atmospheric particulates beginning with the 1987 model year. pressure gasifiers. Table 1 summarizes the proposed methanol stand- ards. Wastewater chareterization data were primarily ob- tained from seven sampling visits at four operating low-BTU gasifiers (one plant was sampled twice, and another three times). Individual wastewater streams produced at these facilities were sampled in order to determine raw wastewater pollutant loadings. EPA DEVELOPS LOW-BTU GASIFICATION WASTEWATER DOCUMENT Following wastewater characterization, methods to treat the wastewater were investigated. This The U.S. Environmental Protection Agency an- primarily involved a one-year, on-site pilot scale nounced in the Federal Register on October 28 the wastewater treatability study at a commercially availability of the Low-BTU Gasification Was- operating low-BTU gasifier. tewater Technical Support Document. This was developed by the Industrial Technology Division of The document is available from EPA or from NTIS. EPA as a technical support for the low-BTU coal gasification point source category.

It presents the process and wastewater effluent data that were collected and analyzed by the EPA from 1979 to 1981 on the low-BTU gasification in- dustry. This information is intended to be used in determining wastewater pollution control systems for the low-BTU gasification industry. Information is provided on wastewater characterization, produc- tion process descriptions, and wastewater treatment technologies.

4-44 SYNTHETIC FUELS REPORT, DECEMBER 1986 RESOURCE '1

TEN YEAR DEADLINE ON FEDERAL COAL On December 5, 1986, the U.S. Bureau of Land LEASES EXPIRES DECEMBER 31, 1986 Management (BLM) published rules to aid in deter- mining the qualifications of lease applicants for Section 3 of the Federal Coal Leasing Act Amend- coal, and other onshore Federal mineral leases. ments of 1976 (FCLAA) says that anyone who has Applicants in violation of Section 3 would not be held a Federal coal lease for 10 years that is not eligable for any such leases. producing in commercial quantities will be prohibited from obtaining any further coal, oil and Under the guidelines published in the December 5 gas, or other mineral leases granted under the Federal Register by the BLM, there are some in- Mineral Leasing Act of 1920. stances where a holder of a federal coal tease can satisfy the requirements of Section 3. A lease Congress failed to extend the deadline, and as a that has produced coal in commercial quantities result there may be as many as 140 leases covering (defined as production of one percent of the more than 160,000 acres and more than 1.5 billion reserves) and is still producing would satisfy the tons of federal coal that will be in noncompliance requirements. Also, a lease that is part of a logi- with Section 3 requirements on December 31, 1986. cal mining unit that is producing satisfies the This could affect as many as 100 companies, in- requirements. Guidelines regarding logical mining cluding affiliates, that would be potential bidders units, as they pertain to Section 3, were published on leases for cool, oil and gas, phosphate, potash, in the August 29, 1985, Federal Register. There sodium, sulphur and giisonite. Thus far, 26 leases are other circumstances which satisfy the require- already have been relinquished, and it is estimated ments of section 3, including approved "arm's- that another 72 leases will be relinquished soon. length" transfers (e.g., assignments); approved relin- Relinquishment of leases will satisfy long-standing quishments of leases; approved suspensions for criticism by some groups that too much coal has reasons such as strikes or stoppages not at- been held for speculative purposes. tributable to and beyond the control of the lessee; payment of advance royalty in lieu of continued Table 1 lists the acreage, by state, of Federal operation; and suspension of operations and produc- leases which will be in noncompliance with Section tion in the interest of conservation. Because the 3 on December 31, 1986. law applies to subsidiaries and affiliates as well as primary entities, the new regulation prescribes a three-tiered test to establish the existence of ownership control. The term "producing" is defined to mean actually mining coal deposits or an ongo- TABLE 1 ing mining operation except on those days when mining temporarily is interrupted for certain STATES WITH POTENTIAL LEASES FAILING reasons under standard industry operating practices, SECTION 3 or when coal is being processed, loaded or transported from the mine site to a point of sale.

State Number of Leases Acres Assistant Interior Secretary Steven Griles said the Administration, having failed to alter the Section 3 Alabama 1 2,388.13 deadline, now will concentrate its efforts on obtain- California 1 80.00 ing amendments to Section 7 of the Mineral Leas- Colorado 49 36,804.61 ing Act. That section terminates any lease ac- Kentucky 1 1,282.00 quired after FCLAA that has not entered into Montana 7 6,539.00 production by ten years from the time the lease New Mexico 6 3,690.18 was issued. Lower than expected coal demand and North Dakota 7 5,398.24 prices, along with the amount of time it takes to Oklahoma 21 35,163.47 bring a lease into production because of permitting Oregon 3 5,411.28 requirements, have made it economically and tech- Pennsylvania 2 80.29 nically unrealistic to bring leases into production in Utah 77 95,889.73 10 years. Washington 1 280.00 Wyoming 16 51,497.25 Griles supports giving the lessee the option of relinquishing the lease or paying a holding fee. TOTALS 192 244,505.12

4-45 SYNTHETIC FUELS REPORT, DECEMBER 1986

RECENT COAL PUBLICATIONS/PATENTS

The following papers were presented at the American Institute Of Chemical Engineers Annual Meeting, Miami Beach, Florida, November 2-7, 1986:

Fuerstcnau, D.W,, et al, "The Role of Coal Properties In Controlling Flota- tion Response."

QI, Z.M., et al, "An Improved Flotation Method for Preparing Ultra-Clean- Coal Water Mixture."

Parekh, 8.1<., "A Parametric Study of Fine Coal Cleaning Using Column Flotation".

Ayat, M.G. , et a!, "Micronized Coal Beneficiation by Froth Flotation Process."

Maronde, C.P.,"Heavy-Liquid Cycloning of Fine-Size Coal."

Nankee, R.J., "Chlorinated Solvents for Coal Beneficiation."

Bukur, 9.8., et al, "Comparison of Iron Based Catalysts for Fischer-Tropseh Synthesis in a Slurry Reactor."

Chung, G.S., eta!, "Anthracite Coal Cleaning by Oil Agglomeration."

Trass, 0., et al, "Fine Grinding and Beneficiation of Coal by Improved Oil Agglomeration Process."

Antonni, G., et a!, "Optimization and Selectivity of an Oil Agglomeration Technique for Clean Coal Slurry Production."

Ozturk, S . S . , et a!, "Modeling of Methanol Synthesis Reactors: A Com- parison of Gas and Liquid Phase Processes."

McCormick, R.L., et al, "Activity Maintenance of Chromia/Alumina in Coal Liquefaction Applications."

Jordan, 0.5., et al, "Studies of Secondary Processes Involving Low- Molecular Weight Olefins Occurring During Fischer-Tropseh Synthesis."

Gab, J.M., et al, "A Jet-Stirred Reactor for Transient Studies of Char Gasification.

Kwon, K.C., "Thermal Effects on Catalytic Activities in Coal Liquefaction."

Guin, J . A . , et al, "Production of Coal -Based Asphalt by Catalytic Hydrotreatment

Baker, J.R., et a!, "Effect of Sodium Impregnation on Activity and Selec- tivity in Coal Liquids Hydrotreating."

Soong, Y., et al, "Transient -Kinetic Study of Nickel -Catalyzed Methane - ion."

Lund, C.R.F., et al, "Catalytic Gasification of Carbon Using Iron."

Anthony, R.G., et a!, "Tubing Bomb Reactors Used in Liquefaction of Lig- nite.

The following papers were presented at the 6th EPRI Coal Gasification Contractors Conference, Palo Alto, California, October 15-16, 1986:

Womeldorff, P.J .,"Coal Gasification: From Pilot Plant to Utility Plans

4-46 SYNTHETIC FUELS REPORT, DECEMBER 1986 Smith, W.11., et at, "10CC: The Decisions are as Complex as the Technol- ogy. "

Long, J . , at al, "Small Bites Avoid Indigestion, - A Capacity Planning Strategy."

Clark, W.N .,"Cool Water: Mid Term Performance Assessment."

Nager, M, at al, "Status of the Shell Coal Gasification Process."

Sundstrom, D., "The Dow Syngas Project - Project Overview and Status Report.

Gorside, P., "KILnGAS Status Report."

Davies, II., et al, "The British Gas/Lurgi Gasifier - Status and Applica- tions."

Engelhard, J., et al, "The Rheinbraun High Temperature Winkler (111W) Demonstration Plant for Synthesis Gas Production: Construction and Start Up.

Pook, 11, "MIP (Molten Iron Puregas) Process - First Test Results."

Butcher, T., "Slurryability as a Function of Coal Properties."

Davis, L.B., at al, "NO , Emissions from Advanced Gas Turbines Fired on MBTU Gases."

Page, G.C., at al, 'Preliminary Environmental Monitoring Results - Cool Water Coal Gasification Program."

The following papers were presented at the Joint Conference On The Introduction And Development Of Methanol As An Alternate Fuel,held in Columbus, Ohio, June 26-27, 1986;

Crocco, J.R .,"The Realities of Methanol Fuels Uses."

Wagner, 1.0., et al, "Economics of Methanol as a Motor Fuel."

Belgen, M.H.,'t The Role of Methanol as an Alternative Motor Vehicle Fuel.'

Othmer, D.F. , "Alcohols--Fuels for Automobiles." Zagrodnik, A.A., et al, "Overcoming Technical and Economic Obstacles in the Introduction of Coal-Water Fuels."

Schehl, R.R., "High Quality Transportation Fuels From Synthesis Gas and Methanol."

Othmer, D.F., et al, 'Methanol Production From High-Sulfur Ohio Coal."

Koppel, P.E., at al, "Conversion of Offshore and Remote Natural Gas to Methanol With Power Reforming."

O'Hare, T.E., at al, 'Methanol for Transportation of Natural Gas Values."

Henderson, J,L., at al, "Operating Experience at the LaPorte Liquid Phase Methanol PDU,

Huber, D.A., at al, "Methanol Utilization and Production in a Utility Sys- tem.

Kilmartin, W. J., et al, "Pipeline Movements and Handling of Gasoline/Oxygenate Blends and Neat Oxygenates."

Kesavan, S.K.K., et al, 'Stabilization of Methanol Slurry Fuels Using Coal Oils."

4-47 SYNTHETIC FUELS REPORT, DECEMBER 1986 Adams, 1.0., "Fuel Economy Improvements Through the Use of Dissociated Methanol."

Varde, K.S., "Mixture Temperature of Air-Atomized Methanol and Its Effects and Combustion in aD! Diesel Engine."

Gutman, M., et al, "Vehicle Engine Fuel System Compatibility Test for Gasoline-Methanol Mixture."

Heavenrich , R.M. , et al, "Evaluation of Catalysts for Methanol-Fueled Vehicles Using a Volkswagen Rabbit Test Vehicle,"

The following papers were presented at the 36th Canadian Chemical Engineering Con- ference in Sarnia, Ontario, Canada, October 5-8, 1986:

Anthony, E,J., et al, "Fluidized Bed Combustion of Syncrude Coke."

Zhang, J., et at, "Devolatilization Rate Process of Large Coal Particles in a Fluidized Bed,"

Berg, D.A. , et al, "Hydrodynamic Study of Ultra-Rapid Fluidized (UHF) Pyrolysis Reactor."

Ohuchi, 1., et al, "Measuring the ?1an in Efficiency of Coal Liquifiea- tion at Different Temperatures by C IC Mass Balance."

Shaw, J. M., et a!, "Towards Optimal Reactor Designs for Direct Coal Liquefaction Processes."

Hastaoglu, M.A., et a!, "Modeling of Catalytic Carbon Gasification."

Electric Power Research Institute, "Gas ification-Combined-Cycic Plant: Part-Load Per- formance," AP-4653, Final Report, July 1986.

Electric Power Research Institute, "Use of Lignite in Texaco Gasification -Based - Combined-Cycle Power Plants," AP4509, Final Report, April 1986.

Stephens, H.P., "Two-Stage Coal Liquefaction Without Gas Phase Hydrogen," 191st Na- tional American Chemical Society meeting in Anaheim, California, September 7-12, 1986.

The following papers were presented at the 21st Intersociety Energy Conversion En- gineering Conference held in San Diego, California, August 25-29, 1986:

Puawani, D.V., at al, "Gasification Characteristics of De-ashed Desul- fur ized Coals."

Nanda, A.K., "Depolymerization of Pennsylvania Bituminous Coal."

Halow, J . S . , "An Overview of the United States Department of Energy Coal Gasification Program."

Lee, B.S .,"Coal Gasification Activities in Europe."

Pate!, J.G., et al, "High Pressured Operation of a Fluidized-Bed Ash- Agglomerating Gasifier.

Corman, J.C., et al, "Performance Characteristics of a Simplified IGCC Sys- em."

The following papers were presented at the Coal Technology '86 Conference held in Pittsburgh, Pennsylvania, November 18-20, 1986:

Bauer, F.W., et at, "Combustion of Coal Slurry Fuels and Pulverized Coal".

Carbone, D.J., "Coal Gasification/Combined Cycle -- A Technology for the 1990S."

4-48 SYNTHETIC FUELS REPORT, DECEMBER 1986

Verne, G.A., et a!, "Component Assessment Study for a Coal Gasification Combined Cycle Power Plant."

Sundstrom, II., "An Industrial Perspective for 10CC Generation."

Schmidt, E.J., et al, "Elements of an Analysis and Training Simulator for Gasification Combined Cycle Units."

Kiosek, J,, et al, "The Role of Oxygen in Coal Gasification."

Bradshaw, D.T.,"Economics of Once-Through Coproduction of Methanol with an Integrated Gasifier Combined Cycle (10CC) Electric Power Plant."

Huddleston, 0., et al, 'Development of Coal -Fired Magnet ohydrodyaamics Technology for Mitigating Acid Deposition."

COAL - PATENTS

"Reduction of Metal Compounds", Peter W. Blom and Jan C. Do Was - Inventors, Union Steel Corporation of South Africa Ltd., United States Patent 4,606,761, August 19, 1986. A method and apparatus for reducing a metal compound particularly iron oxide, by means of a reducing agent comprising CO or H 2 or a mixture of these two gases, of which the average temperature is between 850 0 C and 1,0000 C and which has been ob- tained at this temperature by means of a plasma are heater. The CO and H 2 mixture is preferably obtained by heating a mixture comprising a selection of various reducing agents. Including so called Sasol gas, and CO 2 and steam in a plasma are heater and converting the mixture to Co and H2.

"Coal Liquefaction Process with Increased Naphtha Yields", Daniel F. Ryan - Inventor, Exxon Research and Engineering Company, United States Patent 4,605,486, August 12, 1986. An improved process for liquefying solid carbonaceous materials wherein the solid carbonaceous material is slurried with a suitable solvent and then subjected to liquefaction at elevated temperature and pressure to produce a normally gaseous product, a normally liquid product and a normally solid product. The normally liquid product is further separated into a naphtha boiling range product, a solvent boiling range product and a vacuum gas-oil boiling range product. At least a portion of the solvent boiling-range product and the vacuum gas-oil boiling range product are then combined and passed to a hydrotreater where the mixture is hydrotroated at relatively severe hydrotreating conditions and the liquid product from the hydrotreater then passed to a catalytic cracker. In the catalytic cracker, the hydrotrenter effluent is converted partially to a naphtha boiling range product and to a solvent boiling range product. The naphtha boiling range product is added to the naphtha boiling range product from coal liquefaction to thereby significantly increase the production of naphtha boiling range materials. At least a portion of the solvent boiling range product, on the other hand, is separately hydrogenated and used as solvent for the liquefaction. Use of this material as at least a portion of the solvent sig- nificantly reduces the amount of saturated materials in said solvent.

"Coal Liquefaction Process", Prabhakar Kulkarni - Inventor, United States Patent 4,602,991, July 29, 1986. A liquefaction process for coal or lignite is set forth. In the preferred and illustrated embodiment, coal or lignite is ground to a suitable particle size and placed in a reactor vessel. The reactor vessel is located within a pressure vessel. Pressure in the vessel is reduced to about 10 2 torr. Heat is ap- plied. One procedure is to convert the carbon (in the coal or lignite) at an elevated temperature (600 0 900 0 F) in the presence of hydrogen (at pressures as high as 2,000 psi) into a hydrocarbon mix; depressurization avoids making various oxides and nitrides, and also can be optionally carried out in the presence of iron or iron ore in particulate form acting as a catalyst.

"Burner for Coal Slurry", Roman Chadshay -Inventor, Combustion Engineering Inc., United States Patent 4,602,571, July 29, 1986. A burner is provided for supplying coal-liquid slurry and combustion air to a furnace. The burner housing is mounted about the burner throat opening and interconnected to a combustion air supply duct A coal slurry gun is disposed conxially within the housing for spraying the coal-

4-49 SYNTHETIC FUELS REPORT, DECEMBER 1986 liquid slurry into the furnace. A first conduit means is disposed coaxially about the coal slurry gun to define a primary air flow passage surrounding the slurry gun. Additionally, a second conduit means is disposed coaxially about the first conduit means to define a secondary air flow passage between the first and second conduit means and a tertiary air flow passage between the second conduit means and the bur- ner throat. Independently controllable dampers are provided in the air inlets to the primary, secondary and tertiary air flow passages to permit independent control of air flow velocity. A diffuser means is slidably mounted about the coal slurry gun so as to be translatable from a position adjacent the furnace at low loads ton posi- tion remote therefrom at high loads. Further, an annular sleeve is mounted about the first conduit means and translatable therealong for selective positioning rela- tive to the diffuser means for controlling the flow area of the outlet of the secondary air flow passage.

"Method of Manufacturing a Pumpable Coal/Liquid Mixture", Jorgen Cleemann - Inventor, F. L. Smith and Company, 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 dry-ground in a second grind- ing 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.

"Coking and Gasification Process", Rustom R. 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 gaseous 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 tS weight percent.

"Method of Processing Coal Gas", Albert Calderon - inventor, United States Patent 4,609,541, September 2, 1986, An improved method for the recovery of elemental sulfur(s) from a coal-gas containing hydrogen sulfide wherein hot lime (CaO) is used and then regenerated according to the following chemistry: CaO+H25 CaS +1120 CaS-'-3/2 0 2 CaO i-50 2 S0 2 i-C Si-0O 2 these chemical reactions are conducted in situ while the supply of carbon for the formation of the elemental sulfur is derived from a component of the coal-gas itself to increase the overall efficiency of desulfuriza- tion, increase the uniformity of the carbon deposit into the hot lime (CaO), and eliminate the extra and cumbersome steps of physically moving the spent lime (CaO) for regeneration and returning it after regeneration, and the step of adding coal to react with the sulfur dioxide (SO 2 ) formed as an off-gas during regeneration.

"Process for Simultaneously Removing Sulfur Oxides and Particulates", Eugene H. Hirschberg and Carl J. Horecky -Inventors, Amoco Corporation, United States Patent 4,609,539, September 2, 1986. A process is provided in which particulates and sulfur oxides are simultaneously removed from flue gases in a granular bed filter and scrub- ber with special sulfur oxide-capturing and particulate-removing material. The spent sulfur oxide-capturing and particulate-removing material can be regenerated in a lift pipe riser.

"Coal Liquefaction with Preasphaltene Recycle", Robert N. Miller and Robert F. Weimer - Inventors, International Coal Refining Company, United States Patent 4,609,455, September 2, 1986. A coal liquefaction system is disclosed with a novel preasphai- - tene recycle from a supercritical extraction unit to the slurry mix tank wherein the recycle stream contains at least 90% preasphaltenes (benzene insoluble, soluble organics) with other residual materials such as unconverted coal and ash. This subject process results in the production of asphaltene materials which can be subjected to hydrotreating to acquire a substitute for No. 6 fuel oil. The preasphaltene-predominant recycle reduces the hydrogen consumption for a process where asphaltene material is being sought.

4-50 SYNTHETIC FUELS REPORT, DECEMBER 1986

"Method and Apparatus for Total Energy Systems", Anthony J. Cirri to - Inventor, CTP Partners, United States Patent 4,609,328, September 2, 1986. Combustion jet pumps ingest waste heat gases from power plant engines and boilers to boost their pressure for the ultimate low temperature utilization of the captured heat for heating homes, full-year hot houses, sterilization purposes, recreational hot water, absorption refrigeration and the like. Jet pump energy is sustained from the incineration of solids, liquids and gases and vapors or simply from burning fuels. This is the energy needed to transport the reaction products to the point of heat utilization and to optimize the heat transfer to that point. Sequent jet pumps raise and preserve energy levels. Crypto-steady and special jet pumps increase pumping efficiency. The distribution conduit accepts fluidized solids, liquids, gases and vapors in multi- phase flow. Temperature modulation and flow augmentation takes place by water injec- tion. Macro solids such as dried sewage waste are removed by cyclone separation. Micro particles remain entrained and pass out with water condensate jet beyond each point of final heat utilization to recharge the water table. The non-condensible gases separated at this point are treated for pollution control. Further, jet pump reactions are controlled to yield fuel gas as necessary to power jet pumps or other use. In all these effects introduced sequentially, the available energy necessary to provide the flow energy, for the continuously distributed heating medium, is first extracted from fuel and fuel -like additions to the stream. As all energy, anyway, finally converts to heat, which in this case is retained or recaptured in the flow, the captured heat is practically 90% available at the point of low temperature utilization. The jet pump for coal gasification is also disclosed as are examples of coal gasification and hydrogen production.

"Medium-Load Power -Generating Plant With Integrated Coal Gasification Plant", Konrad Goebel, Rainer Muller, and Ulrich Schiffers - Inventors, l{raftwerk Union, United States Patent 4,608,818, September 2, 1986. A medium-load power generating plant with an integrated coal gasification plant, with a gas-turbine power generating plant part connected to the coal gasification plant, with a steam generating plant part connected to the raw-gas heat exchanger installation of the coal gasification plant, and with a methanol synthesis plant. The methanol synthesis plant has parallel con- nected modules and is connected to the gas-turbine power generating plant part via a central purified gas distribution system which includes a purified gas continuous- flow interim storage plant connected parallel to the pure gas supply line and is con- nected on the gas side to the raw-gas heat exchanger installation.

"Coal Liquefaction Process", Lee flilfman and Peter Urban - Inventors, UOP Inc., United States Patent 4,610,776, September 9, 1986. A coal liquefaction process com- prising reacting coal with a hydrocarbonaeeous solvent at coal liquefaction condi- - tions in the presence of an oil shale residue catalyst comprising organic and inor - ganic fractions. The oil shale residue catalyst is derived by heating an oil shale in the presence of an inert gas with respect to the oil shale at a temperature of 500°-8250F.

"Coal Liquefaction with Mn Nodules", Philip Varghese - Inventor, Mobil Corporation, United States Patent 4,610,777, September 9, 1986. A method for the liquefaction of coal under coal liquefaction conditions in the presence of manganese nodules in com- bination with an improved coal liquefaction solvent. Liquid yields are increased when the solvent, containing substantially only polycondensed aromatic systems or components that possess polarographic reduction potentials equal to or greater than about -2.4 volts, is utilized in the reaction. During the reaction the polycondensed aromatic compounds, in the presence of manganese, are selectively and rapidly hydrogenated leading to increased liquefaction of coal.

"Coal Gasification System with Product Gas Recycle to Pressure Containment Chamber", Scott L. Darling, Michael C. Tanca, Paul R. Thibeault - Inventors Combustion En- gineering Inc., United States Patent 4,610,69T, September 9, 1986. A pressurized coal gasification system having double wall containment vessels is disclosed. The gasification vessel is provided with a gas tight water seal for connecting the lower end of the inner water-cooled vessel with the bottom supported slag tank. The seal prevents gas leakage between the vessel interior and the pressurized annular volume formed between the inner and outer gasification chambers. A flow of clean, particulate-free product gas is routed into the contiguous annular volume formed between the inner water-cooled gas directing members and the outer, pressure con- taining members to prevent either leakage of raw product gas into the annular volume

4-51 SYNTHETIC FUELS REPORT, DECEMBER 1986

or dilution of the product gas by leakage of the sealing gas Into the hot product gas flowstream.

"Method and Apparatus for Cleaning Hot Gases Produced During a Coal Gasification Process", Gunter Henrich, Harold Hoffmann, Klaus-Peter May and Heinz-Dieter Waldhecker - Inventors, Klockner-Humboldt-Deutz, United States Potent 4,613,344, Sep- tember 23, 1986. A method and apparatus for cleaning hot gases produced during a coal gasification process in a reactor, wherein the hot gases leaving the reactor are cooled in a plurality of cooling stages to a relatively low temperature. In accord- ance with this invention, a particulated solid is added to the hot gases and circu- lated through at least one of the cooling stages. The particulated solid may be a material which decomposes in the hot gases to liberate carbon dioxide or it may be inert. The apparatus of the invention makes use of a heat exchanger which functions as a radiant cooler and also as a mixer for the gases and solids, the heat exchanger being connected directly to the gasification reactor at the exhaust gas side thereof. The heat exchanger is followed by at least one downstream, multistage cyclone fluidized bed heat exchanger which also is provided with an indirect heat exchange capability.

4-52 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS

ADVANCED COAL LIQUEFACTION PILOT PLANT -- Electric Power Research Institute (EPa!) 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 produce a No. 6 oil equivalent liquid fuel product as well as a very high distillate product yield. The Wilsonville Pilot Plant was subsequently used to test the Integrated Two- Stage Liquefaction (ITSL) process. In the two stage approach, coat 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 liSt results showed that 30 percent less hydrogen was 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 were demonstrated on bituminous coal. Similar operations with sub-bituminous coal demonstrated distillates yields of about 55 percent MAE. This represents substantial improvement over single stage coal liquefaction processes. More recently, tests at Wilsonville concentrated on testing 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 were achievable (no loss in catalyst activity). Lower product cost was 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 configura- tion was developed and proven out, whereby only the net vacuum bottoms are deashed, thereby reducing the equipment size substantially.

(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 ADVANCED FLASH HYDROPYROLYSIS - Rockwell International (Energy Systems Group) and United States Department of Energy (C-iso) The CS/a (Cities Service and Rockwell) process is based on flash hydropyrolysis (PUP) of finely pulverized materials (e.g., coal, peat, or oil shale) in single-stage, short-residence-time, entrained-flow reactors. The slate of synthetic fuels produced from coals depends on the severity of the FHP reactor operating conditions and the reactor residence time. Low seventies and very short times favor yielding an essentially liquid syncrude, along with modest yields of gases (e.g., CO, CU4, C2's, C31s, etc.). High seventies and long residence times favor production of all gaseous

4-53 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986

COMMERCIAL PROJECTS (Continued)

products, predominantly CH 4. At intermediate seventies and times, the heavy syncrude components are hydrocracked to light, predominantly aromatic liquids. Under certain conditions, there is a substantial yield of high- purity benzene as the sole by-product, and it can be upgraded readily to chemical-grade quality. Rockwell has studied coal hydroliquefaction and hydrogasification 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 significant work by Cities Service in characterizing FlIP 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 restructured the project into a proposed joint DOE/private industry program, with Rockwell heading a consortium of private sector participants. This program used the existing 1 ton per hour process development system and involved 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 accommodates 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 lasted through May 1985 and included 5 months of reactor performance testing. The program was successfully completed and a final report has been written. The report is currently undergoing review. 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 psia. 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.?. Braun guidelines, utility financing). Project Cost: See Above

AEC] AMMONIA/METHANOL OPERATIONS - AECI LTD. (C-li) AECI operates a 100 ton per day 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°C 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 lCPs 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. 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 AECI. "DIESANOL" has attracted worldwide interest and is currently being evaluated as a 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 develop- ment of the methanol fuel market in South Africa.

Project Cost: Not disclosed

4-54 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

APPALACHIAN PROJECT - The M. W. Kellogg Company; KRW Energy Systems Inc. (a company jointly owned by M. W. Kellogg and the Westinghouse Electric Corporation); the General Electric Company; 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 (113CC) system. The project, to be located at Cairnbrook, Pennsylvania, will feature the Kellogg-Rust-Westinghouse (KRW) 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 1,200°F 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 BOTTROP DIRECT COAL LIQUEFACTION PILOT PLANT PROJECT -- Ruhrkohle AG, VEBA Dal AG, Minister of Economics, Small Business and Technology of the State of North-Rhine Westphalia, and Federal Minister of Research and Technology of the Federal Republic of German y (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 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/Ruhrchemie gasification plant at Oberhausen-Holten to produce syngas and hydrogen. The coal oil plant Bottrop will run on coal until mid-1987 to further increase of oil yield and soecific coal throu ghout. The n

4-55 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

The project is subsidized by the Minister of Economics, Small Business and Technology of the State of North-Rhine Westphalia and since mid-1984 by the Federal Minister of Research and Development of the Federal Republic of Germany.

Project Cost: DM700 million (by mid-1986)

BRITISH COAL LIQUID SOLVENT EXTRACTION PROJECT -- British Department of Energy and British Coal (C-BOO) British Coal is building a pilot plant utilizing the Liquid Solvent Extraction Process developed in a small pilot plant capable of producing 0.1 ton 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 feed stocks. British Coal is proceeding with the design and construction of a 2.5 tons per day plant at the Point of Ayr site financed by the British Coal with support from the European Economic Community. Limited private industry and British Department of Energy support is expected. Following a design phase carried out by Babcock Woodall-Duckham Ltd., construction started at the beginning of 1986, with Simon Carves Ltd., being the Main Plant Contractor.

Project Cost: 18 million British pounds (1986 prices) construction cost plus 18 million British pounds (1986 prices) operating costs

BRITISH COAL LOW BTU GASIFICATION PROJECT - (British Coal formerly National Coal Board) (C-Vie) British Coal is developing a spouted fluidized bed gasifier to produce a low BTU gas. When operated at atmospheric pressure the system is aimed at on-site generation of gas for industrial application. A pressurized version is intended for use ma combined cycle power generation system where it would be used in conjunction with a fluidized bed combustor. Work is currently centering on developing the gasifier for the industrial gas market and the technology is licensed to Otto-Simon Carves. A 12 ton per day demonstration plant financed by British Coal and the European Community is being tested. The initial program will be completed early in 1987. A further two year program has been agreed with the EEC to be completed in 1989. Further assessment of the use of the gasifier in a combined cycle power generation system is now being undertaken prior to a decision to embark on pilot scale testing.

Project Cost: Not disclosed

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

CAN DO PROJECT - Continental Energy Associates (C-es) 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.

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COMMERCIAL PROJECTS (Continued)

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

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 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

CITIES SERVICE/ROCKWELL PROCESS DEVELOPMENT (See Advanced Flash Hydropyrolysis - C-iso)

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

4-57 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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, Inc. (C-las) The COCA-i project has been under development since 1983. The proposed project in Macoupin County, Illinois will consume over 1 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. 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 9 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. 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 1111 Coal Gasification Project Corp. signed a participation agreement on Februrary 24, 1982 to commit $30 million to the Project. ESEERCO and Sohio 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

458 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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. 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. Thus 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. An Australian High Ash Fusion Temperature Coal will be tested in late 1987. 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 commence- ment 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 world's 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 900 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, 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 reduc- tions 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 installing a 30 million BTU per hour (1 ton per hour of coal) combustor at the Keeler Boiler Company/Dorr-Oliver site in Williamsport, Pennsylvania, where a 23 million BTU per hour 0-tube package boiler designed for oil is available. The 24 month demonstration project will be performed on this boiler. On completion of this test effort, the

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

4-59 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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 day 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 DOW SYN GAS PROJECT - Dow Chemical Company (C-245) The Dow Chemical Company proposed a project to produce medium-BTU gas from 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 a 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 NOKOTA 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-economic impact associated with this project.

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COMMERCIAL PROJECTS (Continued)

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 1988 (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 schedule is subject to receipt of all permits, approvals, and certifications required from 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., HRI 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" C 4- 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 thy 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

EDGE WATER 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 scrubbers. The Unit 4 boiler at the Edgewater Station was originally commissioned in 1951, 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 of 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.

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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. Foster Wheeler Tennessee, Inc. announced that they had closed their Elmwood, Tennessee Coal Water Fuel Plant effective July 25, 1986. This move was necessitated as a result of the disparity between the cost of oil and coal water fuel. Foster Wheeler Tennessee, Inc. said that when they started developing their coal water fuel technology, oil was selling for $30 per barrel and projections were for even higher prices. Recent prices have been in the neighborhood of $13 per barrel—far lower than anyone thought was possible three years ago. With oil prices at this level, Foster Wheeler Tennessee, Inc. advises that coal water fuel is not competitive and therefore, ceased production. The Elmwood 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 H 2, CO, 1120 and CU4 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

FULARJI 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 Chants, 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 KRW 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.

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COMMERCIAL PROJECTS (Continued)

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 KRW 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! (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. Each KEW gasifier at Fularji must produce 140 million BTU per hour of fuel gas with a lower heating 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 502 and NOx emissions from existing coal-fired boilers. Program goals are 60 percent NOx control and 50 percent SO2 control. Gas reburning is achieved by injection of natural gas (10 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 502 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 . 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

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uncharacterized species in a cooling tower with respect to drift, further biological activity, and associated fouling, and their effects on the 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. Phase II 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 water had a very low organic loading of approximately 150 milligrams per liter of COD. The Phase II test was terminated April 30, 1984, after a 39 day run. Excessive corrosion rates and now 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 QAC treated liquor cannot be used as cooling tower makeup without the addition of an appropriate corrosion inhibitor. A 50 day Phase III cooling tower test was performed using AS and GAC treated liquor from slagging gasification with addition of a zinc-chromate 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 80 0 to 90°F, carbon steel corrosion did not exceed 7 MPY. Corrosion rates less than 1 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 grams deposit per square meter per day in Phase L The microbial population maintained in the the Phase IV system (3 x 100 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 QPGP 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! and IV. In both cases, 90 percent of the phenol entering the system was detected in the exhaust. Treatment of GPQA SQL in a pilot scale three-stage rotating biological contactor has been completed. Five day biochemical oxygen demand (BOO5) loading rates tested were 0.9, 1.8, 3.1, and 3.4 pounds BOD 5 per 1,000 square feet of disc surface area. The mean RODS removals through the three-stages were 95.6, 94.5, 95.1, and 93.3 percent, respectively. Nitrification was achieved only when the pH was lowered from the typical 9.0 to 10.0 to 7.6. PDIJ scale nitrification and denitrification testing of activated sludge treated GPQA SQL has been completed. Solids retention times (SET) of 37, 21, and 12 days were used for determination of the kinetics of nitrification using

4-64 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

complete mix suspended growth reactors. Denitrification was demonstrated with a 10 day SRT and methanol addition. Ammonia-N removals for nitrification at all SRT's were equal to or greater than 97 percent at a mean influent concentration of 523 milligrams per liter NH3-N. Denitrification was complete at the influent nitrate-N concentrations of 750 milligrams per liter. The Phase V cooling tower test was recently completed using biologically treated GPGP SGL and chemical additives. The SGL was treated by the activated sludge process producing an effluent with the following composition: BOD5, 50 milligrams per liter; COD, 625 milligrams per liter; and ammonia, 800 milligrams per liter. The additives consisted of Calgon pHreeGUARD corrosion/scale inhibitor at 10 ppm in the makeup and Calgon H-510 isothiazolin biocide in slugs of 100 ppm in the basin. The corrosion rates ranged from less than 1 to 1.5 MPY for all metallurgies (carbon steel, 304L 55, 316 55, Admiralty and brass) under all conditions of flow and temperature tested. No significant biofouling, decreases in heat transfer, or decreases in pressure drop were observed. Greater than 94 percent of the influent ammonia was stripped to the atmosphere. No air stripping of organics was detected. No process problems of any kind were noted during this phase of testing.

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) GFK DIRECT LIQUEFACTION PROJECT - West German Federal Ministry for Research and Technology, Saarbergwerke AG, and GfI{ Geselisehaft fur Kohleverflussigung MbH (C-400) Until 1984 GfK Gesellschaft fur Kohleverflussigung 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 a coal price of $US1 per gigajoule 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

4-65 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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 day of ammonia, 88 tons per day of sulfur, 200 million cubic feet per day 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 day 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: • 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 motion 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, TECHNOEXPORT 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 area plant. Project Cost: $480 million HUENXE CGT COAL GASIFICATION PILOT PLANT - Carbon Gas Technology (COT) GmbH, a joint venture of Deutsche Babcock AG, Gelsenberg AG, and Manfred Nemitz lndustrieverwaltung (C-472) CGT was established in 1977, with the goal of developing a coal gasification process to the point of commercial maturity and economic utilization. The CGT coal gasification concept consists of the combination of two principal processes of coal gasification in a specially developed reactor. The characteristic feature of the CGT 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

4-66 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986

COMMERCIAL PROJECTS (Continued)

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 CGT 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 flow 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 BP 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 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°F 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 flow rate and composition was examined. Concepts for further improvement in emissions performance were evaluated 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. The fuel plant was integrated with a software simulation of combined cycle power generation equipment. The 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. The 10CC Experimental Simulation Program has been completed with the final DOE reports documenting the study results. The technical activities at General Electric CRD have been redirected to the evaluation of a new power generation concept using coal gasification with Hot Gas Clean-Up. This project is in the development stages. The ultimate project scope and DOE support packages will be developed by the end of 1986. (Also see Simplified 10CC Demonstration Project.)

Project Cost: $9.3 million

4-67 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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 coal 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, so called NEDOL 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. Detailed design of the new pilot plant has started. It is expected that the pilot plant will start operation in 1991. The total cost, including operations, is expected to be 100 billion yen. Project Cost: 100 billion yen, 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-Achinsk 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 KATEK 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°C. 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 K-FUEL COMMERCIAL FACILITY -- Energy Brothers Inc. (C-SiB) 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.

4-68 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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, KILnGAS 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 KILnOAS Commercial Module (11CM) 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 11CM 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 counterflowing 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 11CM 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 11CM, for which construction was completed in mid-1983, is used to support these objectives. Spanning a period from mid-1983 through late 1985, the 11CM 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 I 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 II 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 I: 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

4-69 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL. PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

KLOCKNER COAL GASIFIER - CRA (Australia), Klockner Kohlegas, West German Federal Government (C-535) In August 1986 the sponsors announced that the commercial plant had been cancelled. Project Cost: $325 million KOI-ILE IRON REDUCTION PROCESS DEMONSTRATION PROJECT -- Weirton Steel Corporation and United States Department of Energy (C-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-ETU, sulfur-free 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 KEW ENERGY SYSTEMS INC. ADVANCED COAL GASIFICATION SYSTEM FOR ELECTRIC POWER GENERATION - Kellogg Rust Inc., United States Department of Energy, and Westinghouse Electric (C-980) 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 KEW coal gasifier. KRW 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 injectin g 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°F and 1,950°F and pressures between 130 psig and 230 psig, 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 KEW 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.

4-70 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

The first commerical-scale operation of KEW 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 1995, the liquid phase methanol PDU located near LaPorte, Texas was started, with the initial objective of a 40 thy 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. 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 thy, 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. Additional laboratory research is currently underway, while operation of the unit is expected to begin again late in 1987. 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 - SGI International (C-557) SGI 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 LFC/cogeneration plant consists of an electric generation unit combined with LFC process equipment in one cogenerating system. According to the developers, SGI's LPC 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 6000F). In the system, the electric generation unit supplies waste heat to meet these LEC process thermal loads, while the solid waste by-products from the LFC process are used to fuel the electric generation unit. SGI has obtained a long-term (35 year) power sales agreement with Montana Power Company. The estimated project cost is $72.5 million. Dravo Engineers, Inc. of Atlanta, Georgia has been selected by SGI 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

4-71 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

LIBIAZ COAL-TO-METHANOL PROJECT - Krupp Koppers and KOPEX (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 Libiaz for several years. The project, which began in 1980, has been stalled due to "political difficulties" in Poland. The Libiaz project will reportedly use approximately 1 million metric tons per year of high sulfur coal. Synthesis gas produced by the Koppers-Totzek (KT) technology will be utilized to produce methanol. Project Cost: Not disclosed 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 1,4000 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-587) 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 MILD GASIFICATION PROCESS DEMONSTRATION UNIT -- United Coal Company and United States Department of Energy (C-622) United Coal Company's Research Division, UCC Research Corporation has built a Mild Gasification Process Demonstration Unit at its research center in Bristol, Virginia. The unit is capable of processing 1 ton per day of coal or coal waste. Under the sponsorship of the United States Department of Energy (DOE), UCC has developed a process that is primarily aimed at recovering the energy value contained in wastes from coal cleaning plants. To utilize this waste, 11CC 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 UCC 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 condensers, 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. UCC is 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.

4-72 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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 Hanna 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 Hanna 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 1978 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"), Texas lignite, and Colorado sub-bituminous coal. "Simplex" Briquettes testing was performed in October 1981. 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. The facility was upgraded for the 1985 test series which included 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? years)

473 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986 COMMERCIAL PROJECTS (Continued)

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 now 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 iron- 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 metal systems, some with an iron base, are also showing good catalytic activity. The studies have now been extended to the use of coal-derived solvents rather than 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 2,800°F), 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 (See British Coal Liquid Solvent Extraction Project) (C-690) NATIONAL COAL BOARD LOW BTU GASIFICATION PROJECT - British Department of Energy and National Coal Board (See British Coal Low BTU Gasification Project) (C-700) 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/devolatilization, 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

4.74 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

NEW MEXICO COAL PYROLYSIS PROJECT - Energy Transition Corporation (C-710) 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 thy 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. Tests using the Navajo coal were conducted in a modified synthane PDU operating at hydrocarbonization conditions at DOE's Pittsburgh Energy Technology Center during January 1985. ETCO is seeking additional equity partners for the project. Project Cost: $710 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 (NEX) 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 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 NEX 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) 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 originally proposed a project to produce energy-grade methanol (METHYL FUEL) and anhydrous ammonia. In mid-1986 the project was re-designed to produce 300,000 gallons per day of an octane enhancer (methanol with co-solvents and corrosion inhibitors) directly from coal. Production of ammonia was eliminated. The project will be 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. Construction is scheduled to start early in the third quarter of J.2!8 with completion and initial operation scheduled for the first quarter of 1990. This plant has been estimated to cost $260 million. Project Cost: $260 million PRENFLO GASIFICATION PILOT PLANT -- Krupp Koppers GmbH (RE) (C-798) Krupp Koppers, of Essen, West Germany (in United States known under the name of GKT Gesellschaft fuer Kohle- Technologie) are presently operating a 48 tons per day demonstration plant and designing a 1,000 tons per day

4-75 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continued)

demonstration module for the PRENFLO process. The PRENFLO process is KR's pressurized version of the Koppers-Totzek (1(T) entrained flow gasifier. In 1973, KR started experiments using a pilot KT gasifier with elevated pressure. In 1974, an agreement was signed between Shell Internationale Petroleum Maatschappij BV and KR 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 KR agreed to continue further development separately, with each partner having access to the data gained up to that date. KM's work has led to the PRENFLO process. Krupp Koppers 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 1,000 tons per day will be carried out. The engineering of the 1,000 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 Braunkohienwerke AG, Uhde GmbH, West German Federal Ministry for Research & Technology (C-803) Rheinbraun 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 1980/1981, 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 Ville/Berrenrath 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. The erection of a new pilot plant for pressures up to 25 bar and throuhputs up to 12 tons per hour is planned on the site of the former pilot plant of hydroasification.

Project Cost: Undisclosed RHEINBRAUN 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 of Germany. A PDU for the hydrogasification was engineered and built by Lurgi company, Frankfurt, on the site of Union Kraftstoff at Wesscling. This plant with a throughput of about S 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.

4-76 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

A pilot plant with a throughput of about 240 tons per thy 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 converted in a methane stream reformer being heated with process heat from a high temperature gas cooled nuclear reactor. 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 5,900 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. At the end of Se ptember 1986 the plant was shut down. From start-up in 1983 the plant was operated for about

At the stage of development now reached, a period of commercial usage could be started if profitability could be achieved. Project Cost: Not disclosed SASOL TWO AND SASOL THREE - Sasol Limited (C-820) 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, synthol reactors, gas reformers, and refineries. The hydrocarbon synthesis uses Sasol's Synthol process. Managing 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 18, 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 conducted 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 thy 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, 1994. A contract was completed with Chevron Research Inc. to test the coals in their two-stage direct liquefaction process (CCLI'). Feasibility report has been completed. Financeability options are being discussed with governments concerned and other parties.

477 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continued)

Project Cost: Approximately $4 million for the feasibility study Approximately $500 million for the plant

SCRUBORASS - Scrubgrass Associates (C-825) Scrubgrass Associates (SGA) planned to build a 2,890 barrels per day 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 day of high sulfur bituminous coal, or about 400 tons per day 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

SIMPLIFIED 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-845) This project will use a coal gasification, steam-injected gas turbine power plant to demonstrate the feasibility of simplified integrated gasification combined cycle (IGCC) 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.

4-78 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

The technology uses an air-blown moving bed gasifier, high temperature sulfur removal technology, hot cyclones, and the "LM" 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—e 5 megawatt plant in Dunkirk, New York owned by Niagara Mohawk Power Corporation and a 50 megawatt General Electric plant in Evendale, Ohio. 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 meet 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 four 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 (BGC) 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 feed to the top of the gasifier has been demonstrated as well as the injection of further quantities of fine coal through the tuyeres into the base of the gasifier. By- product hydrocarbon oils and tars can be recycled and gasified to extinction. The coal is gasified in steam and oxygen. The slag produced is removed from the gasifier in the form of granular frit. Gasification is substantially complete with a high thermal efficiency. A long term proving run on the gasifier has been carried out successfully. 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 SK 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. BCG 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 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 modules 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, FRG, 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-Wachtberg, FRG. 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 RUHR (BAR) - Ruhrkohle Oel and Gas GmbH Ruhrchemie 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-Holten.

4_79 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continue(O

tea per year to produce 41W million cubic meters synthesis gas and hydrogen The by the Federal Minister of Economics of the Federal Republic of Germany. T Technology of the State of North-Rhine Westphalia participates in the

Project Costs: DM220 million (Investment) 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 to be located on the state-line near Wibaux, montana and Beach, North Dakota. However, on July 25, 1984,_Tenneco announced suspension of all

Project Cost: Not Applicable

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 Cool Water plant which manufactures electricity, and the 1,650 tons per day Ube Ammonia plant which manufactures ammonia. Additionally, the 770 ton per day SAR plant in Oberhausen, West Germany has begun operation for the manufacture of oxo-chemicals. Commercial projects currently in detailed design and/or construction include the 440 ton per day LuNan Coal Gasification Plant in China to manufacture ammonia, and the 2,700 ton per day 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-PFB, 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 AEP 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.

4-80 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

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 through 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 (800-970 0F) coal pyrolysis system, named the TOSCOAL Process, at their 25 tons per thy pilot plant facilities, located near Golden, Colorado. The 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. The process selectively reduces the volatile matter of the oarent coal to an y desired level in the char. usually 10 to 18 weight nercent. Combustion and

percent oxygen. Frocess evaluations snow tnat a plant aesigneci to process nominally iu,uuu tons per cay ot coai will produce as major products 7,800 tons of readily combustible char, 11,500 barrels of hydrotreated oil, 310 barrels of vacuum residual as well as 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 EDS residues. Additional tests were made in late 1984 and 1985. The project was completed and the facility was shut down in September 1985 after operating for 3.600 hours. Project Cost: $60 million total

4-81 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986)

COMMERCIAL PROJECTS (Continued)

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 ("TCGP"). 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 commissionedin 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 more 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

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: $6,401,557.30; DOE share $2,818,940.00

VICTORIA BROWN COAL LIQUEFACTION PROJECT - Brown Coal Liquefaction (Victoria) Pty. Ltd. (C-975) BCLV 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 Kobe Steel, Mitsubishi Chemical Industries, Nissho lwai, Idemitsu Kosan, 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 deashing 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).

4-82 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) COMMERCIAL PROJECTS (Continued)

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 trigeneration 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 ICcal 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. It is anticipated that the study will be approximately eight months in duration. Bechtel will be paid from a $600,000 grant to SWCC from the United States trade and development program (TDP), International Development Cooperation Agency. Project Cost: Not disclosed

UNDERGROUND COAL CONVERSION PROJECTS

UNDERGROUND COAL GASIFICATION, BRAZIL -- Companhia Auxiliar de Empresas 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

4-83 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) (Continued)

UNDERGROUND COAL GASIFICATION, BYRNE CREEK - Dravo Constructors, Inc. and Energy Investments, Inc. (C-1010) 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 SFC for loan guarantees and price supports for an underground gasification project. According to the original SFC application, the Fischer-Tropsch synthesis would be used for the production of refinable liquids. However, they did not meet the SFC deadline for additional information. The project sponsors reapplied for a loan guarantee under the SFC's second solicitation ending June 1, 1982. The revised project proposed to utilize UCG technology to produce 14 billion BTU of SNG and 436 barrels of light oils per day. The project did not pass the SFC's project maturity test. Under the SFC's third solicitation, the sponsors proposed to develop an underground coal gasification project to produce 198 million KWH annually (450,000 HOE per year) of electricity, 46,000 barrels per year of light oils (44,000 HOE 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 SFCt5 maturity review. On May 26, 1983 the project passed the SFC strength evaluation and was advanced into Phase II negotiations for financial assistance. Loan and price guarantees were requested. On 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 SEAMS - Groupe d'Etudes de Ia Gazeification Souterraine (GEGS) consisting of Bureau de Recherches Geologiques et Minieres, Charbonnages 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 of the site, (2) creating a link between the wells by , 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.

4-84 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) (Continued)

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 (1919-1985): Approximately $28 million Proposed Project Cost (1986-1988): Approximately $10 million UNDERGROUND COAL GASIFICATION, ENGLISH MIDLANDS PILOT PROJECT -- British Coal (C-1018) The United Kingdom's British Coal 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 'UNDERGROUND COAL GASIFICATION, 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 western India contains large reserves of subbituminous coal that could be amenable to UCG. However, experts from 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 (CRIP) technology developed by the Lawrence Livermore National Laboratory. The first information well (UCG-1) has been drilled in 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.

4-85 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) (Continued)

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 II and to link it with the drainhole in early 1996; this delay is due to the long delivery time of the special, corrosion resisting material to be set inside Well H. In December 1985 and January 1996, 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. Due to problems encountered during the setting of the measuring equipment into the drainhole, it has been decided to insert in the injection well a coiled tubing of 1-1/2 inch diameter, the end of which is provided with a gas burner and some thermocouples. The preparatory works (wellhead modification, design construction, and tests of the new equipment ended in August 1986.

Having cleaned the channel between the wells by water circulation and checked the remaining free section at the bottom of the injection well, the sponsors decided to start the gasification without an y change to the equipment. of the coal by iniectinL a small flow of oxwen enriched

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 & D 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/highwall 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.

4-86 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986)

(Continued)

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 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 electrolinking 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 outcropfhigtiwall 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 WIDCO coal mine near Centralia, Washington; and a larger test at the same location (the "Partial Seam CRIP 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 PY1977-1978, 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 thy 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 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 FY1982 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-D cavity simulation model, CAVSM. The results from the Block tests led to the design of the Centralia Partial Seam CHIP 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 (CRIP) 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 long 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 CHIP 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 UCG at the Centralia site. The CRIP 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 1 is being planned for completion in late FY1987 at Hanna, Wyoming. The test will provide a direct comparison of the CR11' 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.

4-87 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) (Continued)

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 FY1986 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 FY1987 include: 1. Continue to support the Rocky Mountain 1 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. 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 1987 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 Hanna, Wyoming, near a site used in the 1970s by the government to conduct some of the United State& 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 a propane burner inserted

4-88 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS (Underline denotes changes since September 1986) (Continued)

in the horizontal well. The coal gasifies froin 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 seam 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. The project is currently on hold. 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-1115) This project involves a proof-of-concept/pilot demonstration of underground coal gasification (13CC) 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 using a fixed bed indirect liquefaction technology. The demonstration represents one module of a commercial plant which would ultimately produce 4,000 barrels per thy 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

499 SYNTHETIC FUELS REPORT, DECEMBER 1986 COMPLETED AND SUSPENDED PROJECTS

Project Sponsors Last Appearance in SFR 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 B-23 Development Poster-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 Gasification Plant AMAX, Inc. March 1983; page 4-85 Arkansas Lignite Conversion Dow Chemical Company, December 1984; page 4-64 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. BI-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 B-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 B-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

4-90 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SFR

Chesapeake Coal-Water Fuel ARC-COAL, Inc. March 1985; page 4-64 Project Bechtel Power Corporation COMCO of America, Inc. Dominion Resources, Inc. Chokecherry Project Energy Transition Corporation December 1983; page 4-81 Circle West Project Meridian Minerals Company September 1986; page 4-58 Clark Synthesis Gas Project Clark Oil and Refining Corporation December 1982; 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 4-86 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-S Project TransWorld Resources CS/R 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 EDS Process Anaconda Minerals Company June 1985, page 4-63 EN I Electric Power Research Institute Exxon Company USA Japan Coal Liquefaction Development Co.

4-91 SYNTHETIC FUELS REPORT, DECEMBER 1986

Project Sponsors Last Appearance in SF11

Phillips Coal Company Ruhrkohle A.G. United States Department of Energy 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 Fiat/Ansaldo Project Ansaldo March 1985; page 4-66 Fiat VFG KRW 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 Koppers 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 Bay 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-R International, Inc. December 1985, page 4-80 - The Slagging Gasification Consortium Hydrogen from Coal Air Products and Chemicals, Inc. December 1978; page 3-31 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

4-92 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SPR

ICGG Pipeline Gas Demonstra- Illinois Coal Gasification Group September 1981; page 4-66 tion Plant Project United States Department of Energy Integrated Two-Stage Liquefaction Cities Service/Lummus September 1986; page 4-69 ITT 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-18 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 Keystone Project The Signal Companies September 1986; page 4-71 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 4-99 Project Transwestern Coal Gasification Company Latrobe Valley Coal Lique- Rheinische Braunkohlwerkc AG December 1983; page 4-96 faction Project LC-Fining Processing of SRC Cities Service Company December 1993; 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 4-99 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

4-93 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SFR

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 Millmerran Coal Liquefaction Australian Coal Corporation March 1985; page 4-82 Minnegasco High-BTU 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 1983; 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 December 1983; page 4-102 Gas Polygeneration Power Plant New England Energy Park Bechtel Power Corporation December 1983; page 4-104 Brooklyn Union Gas Company Eastern Gas & Fuel Associates E G & 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 lnterNorth 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 Oberhausen Coal Gasification Ruhrchemie AG September 1986; page 4-79 Project Ruhrkohle Oel & Gas GmbH 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

4-94 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SFR

Ott Hydrogeneration Process Carl A. Ott Engineering Company December 1983; page 4-107 Project Peat-by-Wire Project PBW 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 Kohiegas GmbH March 1985; page 4-72 Pennsylvania Engineering Corporation Sharon Steel Corporation Philadelphia Gas Works Synthesis Philadelphia Gas Works December 1983; page 4-108 Gas Plant United States Department of Energy Phillips Coal Gasification Phillips Coal Company September 1984; page C-28 Project Pike County Low-ETU Gasifier Appalachian Regional Commission June 1981; page 4-78 for Commercial Use Kentucky, Commonwealth of United States Department of Energy Plasma Arc Torch Swindell-Dresser Company December 1978; page B-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; page 4-86 Electric Power Research Institute Fluor Engineers and Constructors Illinois, State of United States Department of Energy Purged Project Integrated Carbons Corporation December 1983; page 4-108 Pyrolysis Demonstration Plant Kentucky, Commonwealth of December 1978; page B-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 RUHR100 Project AG September 1984; page C-29 Ruhrkohle AG Steag AG West German Ministry of Research and Technology Saarbergwerke-Otto Gasification Saarbergwerke AG June 1984; 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 Klockner Kohlegas GmbH March 1985; page 4-92 Pennsylvania Engineering Corporation Sharon Steel Corporation Slagging Gasification Consortium Babeok Woodall-Duckham Ltd. September 1985; page 4-78 Project Big Three Industries, Inc. The HOC Group plc British Gas Corporation Consolidation Coal Company

4-95 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SFR

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 B-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. Solvent Refined Coal Demonstration International Coal Refining Company September 1986; page 4-83 Plant Air Products and Chemicals Inc. Kentucky Energy Cabinet United States Department of Energy Wheelabrator-Frye Inc. Steam-Iron Project Gas Research Institute December 1978; page 0-35 Institute of Gas Technology United States Department of Energy Synthane Project United States Department of Energy December 1978; page 8-35 Synthoil Project Foster Wheeler Energy Corporation December 1978; page 8-36 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. December 1983; page 4-112 Mobil-M Plant Transco Coal Gas Plant Transco Energy Company December 1983; 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 1985, page 4-75 University of Texas Underground Coal Gasification, Alberta Research Council September 1984; page C-37 Canada 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 1983; 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 If Project Wold-Jenkins

4-96 SYNTHETIC FUELS REPORT, DECEMBER 1986 Project Sponsors Last Appearance in SFR

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 1985, 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 8-33 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 Questar Synfuels Corporation December 1985, page 4-90 Verdigris Agrico Chemical Company September 1984; page C-35 Virginia Power Combined Cycle Project Consolidation Coal December 1985, page 4-90 Electric Power Research Institute Slagging Gasification Consortium Virginia Electric and Power Company 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 WyCoalGas, Inc. (a Panhandle Eastern December 1982; page 4-112 Company) Zinc Halide 1-lydrocracking Conoco Coal Development Company June 1981; page 4-86 Process Development Shell Development Company

4-97 SYNTHETIC FUELS REPORT, DECEMBER 1986 STATUS OF COAL PROJECTS INDEX OF COMPANY INTEREST

Company or Organization Project Name Page

AECI Ltd. AECI Ammonia/Methanol Operations 4- 54 Coalplex Project 4- 57 AGA Nynas Energy Chemicals Complex 4- 75 Air Products and Chemicals, Inc. Laporte Liquid Phase Methanol Synthesis 4- 71 A. Johnson & Company Nynas Energy Chemicals Complex 4- 75 Allis-Chalmers KILnGAS Project 4- 69 American Electric Power Service Corporation Tidd Pressurized Fluidized Bed Demonstration Project 4- 80 American Natural Service Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 Amerigas, Inc. Mining and Industrial Fuel Gas Group Gasifier 4- 73 Amoco Production Company Underground Coal Gasification Rocky Mountain 1 Test 4- 88 Asia Oil Victoria Brown Coal Liquefaction Project 4- 82 Australia, Federal Government of Victoria Brown Coal Liquefaction Project 4- 82 Bechtel Inc. Cool Water Coal Gasification Project 4- 58 Mining and Industrial Fuel Gas Group Gasifier 4- 73 Belgium, Government of Underground Coal Gasification, Joint Belgo-German Project 4- 85 Black, Sivalls & Bryson, Inc. Mining and Industrial Fuel Gas Group Gasifier 4- 73 HP United Kingdom, Ltd. Monash Hydrolique faction Project 4- 74 Bradley Resources Corporation Underground Gasification of Anthracite, Spruce Creek 4- 89 British Coal British Coal Liquid Solvent Extraction Project 4- 56 British Coal Low-BTU Gasification Project 4- 56 Underground Coal Gasification English Midland Pilot Project 4- 89 British Department of Energy British Coal Liquid Solvent Extraction Project 4- 56 British Coal Low-BTU Gasification Project 4- 56 British Gas Corporation Slagging Gasifier Project 4 79 Broken Hill Pty. Broken Hill Project 4- 56 Brookhaven National Laboratory Flash Pyrolysis of Coal with Reactive and Non-Reactive Gases 4- 62 Brown Coal Liquefaction Pty. Ltd. Victoria Brown Coal Liquefaction Project 4- 82 Burlington Northern, Inc. Mining and Industrial Fuel Gas Group Gasifier 4- 73 Simplified IGCC Demonstration Project 4- 78 Bureau de Recherches Geologiques Underground Coal Gasification of Deep Seams 4- 83 et Minieres

Carbon Gas Technology Huenxe CGT Coal Gasification Pilot Plant 4- 66 Caterpillar Tractor Company Caterpillar Tractor Low BTU Gas From Coal Project 4- 57 Central Illinois Light Co., Inc. KILnGAS Project 4- 69

4-98 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Charbonnages de France Underground Coal Gasification of Deep Seams 4- 84 Chem Systems, Inc. Laporte Liquid Phase Methanol Synthesis 4- 71 China National Technical Import Lu Nan Ammonia-from-Coal Project 4- 72 Corporation Cleveland-Cliffs Iron Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 Coal Gasification COCA-i Project 4- 58 Coal Tech Corporation Cyclone Combustor Demonstration Project 4- 59 Corupanhia Auxiliar de Empresas Underground Coal Gasification, Brazil 4- 83 Electricas Brasileiras

Continental Energy Associates Can Do Project 4- 56 CRA (Australia) Kloechner Coal Gasifier 4- 70 Davy McKee Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 73 Deutsche Babcock AG Huenxe CGT Coal Gasification Pilot Plant 4- 66 DEVCO Scotia Coal Synfuels Project 4- 77 Dow Chemical Dow Gasification Process Development 4- 60 Dow Syngas Project 4- 60 Dravo Engineers and Constructors Mining and Industrial Fuel Gas Group Gasifier 4- 73 Underground Coal Gasification, Byrne Creek 4- 83 Ebasco Services, Inc. Chiriqui Grande Project 4- 57 Electric Power Research Institute Advanced Coal Liquefaction Pilot Plant 4- 53 Cool Water Coal Gasification Project 4- 58 KILnGAS Project 4- 69 Laporte Liquid Phase Methanol Synthesis 4- 71 Mining and Industrial Fuel Gas Group Gasifier 4- 73 Underground Coal Gasification Rocky Mountain 1 Test 4- 88 Elgin Butler Brick Company National Synfuels Projects 4- 74 Empire State Electric Energy Cool Water Coal Gasification Project 4- 58 Research Corporation (ESEERCO) Simplified IGCC Demonstration Project 4- 78 Energy Adaptors Corporation Ohio-I Coal Conversion Project 4- 75 Energy and Environmental Research Gas Reburning Sorbent Injection Demonstration Project 4- 63 Corporation

Energy Brothers Inc. K-Fuel Commercial Facility 4- 68 Energy International Underground Coal Gasification, Steeply Dipping Bed 4- 39 Demonstration Plant Energy Investment Inc. Underground Coal Gasification, Byrne Creek 4- 84 Energy Transition Corporation New Mexico Coal Pyrolysis Project 4- 75 European Economic Community Underground Coal Gasification, Joint Belgo-German Project 4- 85 Fluor Engineers and Constructors Laporte Liquid Phase Methanol Synthesis 4- 71

4-99 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Ford, Bacon & Davis Mountain Fuel Coal Gasification Project 4- 74 Foster Wheeler Tennessee Inc. Elmwood Coal-Water Fuel Project 4- 62 Gallagher Asphalt Company Aqua-Black Coal-Water Fuel Project 4- 55 Gas Research Institute Gas Reburning Sorbent Injection Demonstration Project 4- 63 Underground Coal Gasification Rocky Mountain 1 Test 4- 88 Gaz de France Underground Coal Gasification of Deep Seams 4- 84 Gelsenberg AG Huenxe CGT Coal Gasification Pilot Plant 4- 66 General Electric Company Appalachian Project 4- 55 Cool Water Coal Gasification Project 4- 58 IGCC Simulation 4- 67 Simplified IGCC Demonstration Project 4- 78 Geosystems Corporation Underground Gasification of Anthracite, Spruce Creek 4- 89 Gescllschaft fur Kohle-Technologie PRENFLO Gasification Pilot Plant 4- 80 GfK Gesellschaft fur Kohleverflussigung GFK Direct Liquefaction Project 4- 67 Gillespie, Alastair & Associates, Ltd. Scotia Coal Synfuels Project 4- 77 Gilman Company Underground Gasification of Anthracite, Spruce Creek 4- 84 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- 77 Hanna Mining Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 l-loechst-Uhde Corporation Ohio-I Coal Conversion Project 4- 75 HRI Inc. Fbullated Bed Coal/Oil Co-Processing Prototype 4- 61 Idemitsu Kosan Victoria Brown Coal Liquefaction Project 4- 82 Illinois Power & Light Company KILnGAS Project 4 69 Illinois, State of Gas Reburning Sorbent Injection Demonstration Project 4- 63 KILnGAS Project 4- 69 Institut Francais du Pctrole Underground Coal Gasification of Deep Seams 4- 84 Iowa Power & Light Company KILnGAS Project 4- 69 Japan, Government of Victoria Brown Coal Liquefaction Project 4- 82 Japan Cool Water Program Cool Water Gasification Project (JCWP) Partnership 4- 58

Kellogg Company, The M. W. Appalachian Project 4- 55 Kellogg Rust Inc. Fularji Low BTU Gasifier 4- 62 KRW Energy Systems Inc. Advanced Coal Gasification 4- 70 System for Electric Power Generation

KHD Industries Lulea Molten Iron Pilot Plant 4- 72

4-190 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

KILnGAS It & D, Inc. l{ILnGAS Project 4- 69 Elochner Kohlegas Klochner Coal Gasifier 4- 70 Kobe Steel Victoria Brown Coal Liquefaction Project 4- 82 Kopex Libiaz Coal-to-Methanol Project 4- 72 Krupp Koppers GmbH Libiaz Coal-to-Methanol Project 4- 72 PRENFLO Gasification Pilot Plant 4- 75 KRW Energy Systems Inc. Appalachian Project 4- 55 Fularji Low BTU Gasifier 4- 62 KRW Energy Systems Inc. Advanced Coal Gasification 4- 70 System for Electric Power Generation Lawrence Livermore Laboratory Underground Coal Gasification - LLNL Studies 4- 87 Lurgi Kohle & Mineraloltechnik, GmbH Rheinbraun Hydrogasification of Coal to SNG 4- 76 Manfred Nemitz Industrieverwaltung Huenxe CGT Gasification Pilot Plant 4- 66 Minister of Economics Bottrop Direct Coal Liquefaction Pilot Plant 4- 55 Ministry of Machine Building Industry Falarji Low BTU Gasifier 4- 62 Mitsubishi Chemical Industries Victoria Brown Coal Liquefaction Project 4- 82 Monash University Monash Hydroliquefaction Project 4- 74 Monongahela Power Company KILnGAS Project 4- 69 Morgantown Energy Technology Center Underground Coal Gasification - Bituminous Project 4- 86 Mountain Fuel Supply, Inc. Mountain Fuel Coal Gasification Process 4- 74 National Synfuels Inc. National Synfuels Projects 4- 74 New Energy Development Organization Japanese Bituminous Coal Liquefaction Project 4- 68 New York State Energy Research & Simplified IGCC Demonstration Project 4- 78 Development Authority

Niagara Mohawk Power Corporation Simplified IGCC Demonstration Project 4- 78 Nippon Brown Coal Liquefaction Co. Victoria Brown Coal Liquefaction Project 4- 82 Nissho Iwai Victoria Brown Coal Liquefaction Project 4- 82 Nitrogenous Fertilizers Industry SA Greek Lignite Gasification Complex 4- 66 Nokota Company Dunn Nokota Methanol Project 4- 60 North-Rhine Westphalia, State of Bottrop Direct Coal Liquefaction Pilot Plant 4- 55 Synthesegasanlage Ruhr (SAR) 4- 79 Texaco Coal Gasification Process 4- 80 NOVA Scotia Coal Synfuels Project 4- 77 Nova Scotia Resources Limited Scotia Coal Synfuels Project 4- 77 Ohio Coal Development Office Ebullated Bed Coal/Oil Co-Processing Prototype 4- 61 Edgewater Station LIMB Demonstration Project 4- 61 Tidd Pressurized Fluidized Bed Demonstration Project 4- 80

4-101 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Ohio Department of Development Simplified IGCC Demonstration Project 4- 78 Ohio Edison Company KILnGAS Project 4- 69 Ohio Ontario Clean Fuels Inc. Ebullated Bed Coal/Oil Co-Processing Prototype 4- 61 Ohio Power Company Tidd Pressurized Fluidized Bed Demonstration Project 4- 80 Oil & Natural Gas Commission Underground Coal Gasification, India 4- 85 Peabody Holding Company Simplified IGCC Demonstration Project 4- 78 Pennsylvania Electric Company Appalachian Project 4- 55 Pennsylvania Energy Development Authority Cyclone Combustor Demonstration Project 4- 59 State of Pennsylvania Power and Light Company Cyclone Combustor Demonstration Project 4- 59 Peoples Natural Gas Company Mining and Industrial Fuel Gas Group Gasifier 4- 13 Petro-Canada Scotia Coal Synfuels Project 4- 81 Pickands Mather & Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 Polish Government Libiaz Coal-to-Methanol Project 4- 72 Potomac Edison Company KILnGAS Project 4- 69 Reserve Mining Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 Rheinische Braunkohlwerke Rheinbraun Hydrogasification of Coal to SNG 4- 76 Rheinbraun High Temperature Winkler Project 4- 76 Riley Stoker Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 73 Rockwell International Advanced Flash 1-lydropyrolysis 4- 53 Rocky Mountain Energy Company Mining and Industrial Fuel Gas Group Gasifier 4- 73 Underground Coal Gasification Rocky Mountain 1 Test 4- 88 Underground Coal Gasification, Steeply Dipping Bed 4- 89 Demonstration Plant Royal Dutch/Shell Group Shell Coal Gasification Project 4- 78 Ruhrkohle AG Texaco Coal Gasification Process 4- 80 Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 55 Ruhrkohle Gel & Gas GmbH Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 55 Synthesegasanlage Ruhr (SAR) 4- 79 Ruhrchemie AG Synthesegasanlage Ruhr (SAR) 4- 79 Texaco Coal Gasification Process 4- 80 Saarbergwerke AG 02K Direct Liquefaction Project 4- 65 Sasol Limited Sasol Two and Sasol Three 4- 77 Scrubgrass Associates Scrubgrass Project 4- 78 SGI International LFC Coal Liquefaction/Cogeneration Plant 4- 71 Shanghai Wujing Chemical Corporation Wujing Trigeneration Project 4- 83

4-102 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

Shell Oil Company Shell Coal Gasification Project 4- 78 Sohio Alternate Energy Development Cool Water Coal Gasification Project 4- 58 Company South Australia, Government of South Australian Coal Gasification Project 4- 79 Underground Coal Gasification, Leigh Creek 4- 88 Southern California Edison Cool Water Coal Gasification Project 4- 58 Cyclone Combustor Demonstration Project 4- 59 Spruce Creek Energy Company Underground Gasification of Anthracite, Spruce Creek 4- 89 Standard Havens, Inc. Aqua Black Coal-Water Fuel Project 4- 55 Stearns Catalytic Inc. thullated Bed Coal/Oil Co-Processing Prototype 4- 61 Stone & Webster Engineering Group Mining and Industrial Fuel Gas Group Gasifier 4- 73 Sumitomo Metal Industries, Inc. Lulea Molten Iron Pilot Plant 4- 72 Superfos Group Nynas Energy Chemical Complex 4- 75 Swedish Investment Bank Nynas Energy Chemicals Company 4- 75 Tenneco, Inc. SNG from Coal 4- 80 Tennessee Eastman Company Chemicals From Coal 4- 57 Texaco Inc. Cool Water Coal Gasification Project 4- 58 Texaco Coal Gasification Process 4- 80 TOSCO Corporation TOSCOAL Process Development 4- 81 Twin Cities Metallurgical Mining and Industrial Fuel Gas Group Gasifier 4- 73 Research Center TVA TVA Ammonia-From-Coal Project 4- 81 Ube Industries, Ltd. Ube Ammonia-from-Coal Plant 4- 82 Uhde GmbH Rheinbraun High Temperature Winkler Project 4- 76 Union Electric Company KILnGAS Project 4- 69 Union Pacific Corporation Underground Coal Gasification, Steeply Dipping Bed 4- 89 Demonstration Plant Union of Soviet Socialist Republics Ransak-Achinsk Basin Coal Liquefaction Pilot Plants 4- 68 University of Minnesota University of Minnesota Low-BTU Gasifier for Commercial Use 4- 82 University of North Dakota Gasification Environmental Studies 4- 63 USBM - Twin Cities Metallurgical Mining and Industrial Fuel Gas Group Gasifier 4- 73 Research Center

United Coal Company Mild Gasification Process Demonstration Unit 4- 72

4-103 SYNTHETIC FUELS REPORT, DECEMBER 1986 Company or Organization Project Name Page

United States Department of Energy Advanced Coal Liquefaction Pilot Plant 4- 53 Advanced Flash Hydropyrolysis 4- 53 Appalachian Project 4- 55 Cyclone Combustor Demonstration Project 4- 59 Ebullated Bed Coal/Oil Co-Processing Prototype 4- 61 Edgewater Station LIMB Demonstration Project 4- 61 Flash Pyrolysis of Coal With Reactive and Non-Reactive Gases 4- 62 Gas Reburning Sorbent Injection Demonstration Project 4- 63 Great Plains Gasification Project 4- 65 }CILnGAS Project 4- 69 Hohle Iron Reduction Process Demonstration Project 4- 70 KRW Advanced Coal Gasification System for 4- 70 Electric Power Generation Laporte Liquid Phase Methanol Synthesis 4- 71 Mild Gasification Process Demonstration Unit 4- 72 Mining and Industrial Fuel Gas Group Gasifier 4- 73 Mountain Fuel Coal Gasification Process 4- 74 Simplified IGCC Demonstration Project 4- 78 Tidd Pressurized Fluidized Bed Demonstration Project 4- 80 University of Minnesota Low-BTU Gasifier for 4- 82 Commercial Use Underground Coal Gasification Rocky Mountain I Test 4- 88 Underground Coal Gasification, Steeply Dipping Bed 4- 89 Demonstration Plant

Underground Coal Gasification Brazil Project 4 83 Bituminous Coal Gasification Project 4- 86

United States Environmental Edgewater Station LIMB Demonstration Project 4- 61 Protection Agency

United States State Department Chiriqui Grande Project 4- 57

U.S. Steel Corporation Mining and Industrial Fuel Gas Group Gasifier 4- 73

Veba Oil GmbH Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 55

Victoria, State Government of Victoria Brown Coal Liquefaction Project 4- 82

Weirton Steel Corporation Kohle Iron Reduction Process Demonstration Project 4- 70

Wentworth Brothers Inc. Ohio-I Coal Conversion Project 4- 75

Western Energy Company Mining and Industrial Fuel Gas Group Gasifier 4- 73

West German Federal Government Kloeckner Coal Gasifier 4- 70 Texaco Coal Gasification Process 4- 80 Underground Coal Gasification, Joint Belgo-German Project 4- 85

West German Federal Ministry of Bottrop Direct Coal Liquefaction Pilot Plant Project 4- 55 Research & Technology GRK Direct Liquefaction Project 4- 63 PRENFLO Gasification Pilot Plant 4- 75 Rheinbraun High Temperature Winkler Project 4- 76 Rheinbraun Hydrogasification of Coal to SNG 4- 76 Synthesegasanlage Ruhr (SAR) 4- 79

West Penn Power Company I{ILnGAS Project 4- 69

Westinghouse Electric Appalachian Project 4- 55 KRW Advanced Coal Gasification System for Electric 4- 70 Power Generation

Weyerhaeuser Mining and Industrial Fuel Gas Group Gasifier 4- 73

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